# EDGAR Filing Document

**Accession Number:** 0001017413
**File Stem:** 0001017413-23-000006
**Filing Date:** 2023-3
**Character Count:** 317834
**Document Hash:** 44abe6cf957127c27af5557f6a0fa5a8
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001017413-23-000006.hdr.sgml**: 20230302

**ACCESSION NUMBER**: 0001017413-23-000006

**CONFORMED SUBMISSION TYPE**: 6-K

**PUBLIC DOCUMENT COUNT**: 7

**CONFORMED PERIOD OF REPORT**: 20230302

**FILED AS OF DATE**: 20230302

**DATE AS OF CHANGE**: 20230302

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** CANADIAN NATURAL RESOURCES LTD
- **CENTRAL INDEX KEY:** 0001017413
- **STANDARD INDUSTRIAL CLASSIFICATION:** CRUDE PETROLEUM & NATURAL GAS [1311]
- **IRS NUMBER:** 000000000
- **STATE OF INCORPORATION:** A0
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 6-K
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 333-12138
- **FILM NUMBER:** 23698509

**BUSINESS ADDRESS:**
- **STREET 1:** 2100, 855-2 STREET SW
- **CITY:** CALGARY ALBERTA CANADA
- **STATE:** A0
- **ZIP:** T2P 4J8
- **BUSINESS PHONE:** 403-514-7605

**MAIL ADDRESS:**
- **STREET 1:** 2100, 855-2 STREET SW
- **CITY:** CALGARY ALBERTA CANADA
- **STATE:** A0
- **ZIP:** T2P 4J8

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

**FORM 6-K**

**REPORT OF FOREIGN PRIVATE ISSUER**

**Pursuant to Rule 13a-16 or 15d-16 of the**

**Securities Exchange Act of 1934**

Dated: March 2, 2023

Commission File Number: 333-12138

**CANADIAN NATURAL RESOURCES LIMITED**

(Exact name of registrant as specified in its charter)

2100, 855 - 2<sup>ND</sup> Street S. W., Calgary, Alberta T2P 4J8

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ____&nbsp;&nbsp;&nbsp;&nbsp; &nbsp;&nbsp;&nbsp;&nbsp; Form 40-F <u>X</u> 

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ____

Note: Regulation S-T Rule 101(b)(1) only permits the submission in paper of a Form 6-K if submitted solely to provide an attached annual report to security holders.

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ____

Note: Regulation S-T Rule 101(b)(7) only permits the submission in paper of a Form 6-K if submitted to furnish a report or other document that the registrant foreign private issuer must furnish and make public under the laws of the jurisdiction in which the registrant is incorporated, domiciled or legally organized (the registrant's "home country"), or under the rules of the home country exchange on which the registrant's securities are traded, as long as the report or other document is not a press release, is not required to be and has not been distributed to the registrant's security holders, and, if discussing a material event, has already been the subject of a Form 6-K submission or other Commission filing on EDGAR.

Exhibits 99.1, 99.2 and 99.3 to this report, filed on Form 6-K, shall be incorporated by reference as exhibits to the registrant's Registration Statements under the Securities Act of 1933 on Form F-10 (File Nos. 333-219366 and 333-219367).

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| | |
|:---|:---|
| <u>Exhibit Number</u> | <u>Description</u> |
| 99.1 | <u>[Press Release dated March 2, 2023](a123122q4pressrelease.htm)</u> |
|  | Canadian Natural Resources Limited Announces 2022 Fourth Quarter Results |
| 99.2 | <u>[Management's Discussion and Analysis for the three months and year ended December 31, 2022](a12312022q4mda.htm)</u> |
| 99.3 | <u>[Unaudited interim consolidated financial statements for the three months and year ended December 31, 2022 and 2021](a12312022q4fs.htm)</u> |

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**SIGNATURE**

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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| | | |
|:---|:---|:---|
| | **Canadian Natural Resources Limited**<br>(Registrant) | **Canadian Natural Resources Limited**<br>(Registrant) |
| Date: March 2, 2023 | By: | /s/ Paul M. Mendes |
|  |  | Paul M. Mendes |
|  |  | VP, Legal, General Counsel &<br>Corporate Secretary |

---

## Exhibit 99.1

![pressreleasea.jpg](pressreleasea.jpg)

**CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES** 

**2022 FOURTH QUARTER AND YEAR END RESULTS**

**CALGARY, ALBERTA – MARCH 2, 2023 – FOR IMMEDIATE RELEASE**

Canadian Natural's President, Tim McKay, commented on the Company's 2022 results "In 2022, we demonstrated the strength of our balanced, diverse asset base that when combined with our flexible capital allocation strategy, resulted in substantial free cash flow generation, significant returns to our shareholders and strong reserve growth. We achieved record annual production of 1,281,434 BOE/d in 2022, an increase of 4% from 2021 levels, and 8% growth on a production per share basis. This growth was largely driven by our strategic investment in our robust natural gas assets, which grew 23% from 2021 levels, achieving record annual natural gas production of approximately 2.1 Bcf/d. Our culture of continuous improvement, focus on cost control and disciplined capital allocation continue to drive strong operational and financial results, maximizing value for shareholders.

As a result of our diversified portfolio, we achieved annual realized natural gas pricing of $6.55/Mcf in 2022, which was approximately 17% above the AECO benchmark price. In addition, our high value synthetic crude oil ("SCO") captured a strong price premium to WTI of US$4.43/bbl, driving strong realized SCO pricing of $117.69/bbl, which on an annual basis represents approximately 46% of our total liquids volumes and generates significant free cash flow for the Company.

Canadian Natural's diverse portfolio is supported by long life low decline assets which have low risk, high value reserves that require low maintenance capital. This allows us to remain flexible with our capital allocation and maximize value. Total proved reserves increased by 6% to 13.587 billion BOE, replacing 2022 production by 265%. This provides the Company with a 32 year reserve life index ("RLI") and reflects the strength and depth of our assets. We continued to deliver strong total proved finding, development and acquisition ("FD&A") costs, including changes in future development costs, of $8.39/BOE in 2022.

Canadian Natural is committed to supplying safe, reliable and responsible energy, along with reducing its environmental footprint. In 2022, we announced a new environmental target to reduce corporate scope 1 and 2 absolute GHG emissions by 40% by 2035, in addition to our other robust environmental targets. We have a defined journey to net zero emissions in oil sands operations and are working collaboratively with our industry peers through the Pathways Alliance to achieve this goal. It is important we work together with both federal and provincial governments to achieve climate goals, in an economically feasible manner. We are also an industry leader in abandonment and reclamation activity and through our active program, we have abandoned more than 3,000 wells per year in each of the last two years. At this pace, we would be able to achieve 100% abandonment of our current inventory of inactive wells in approximately 10 years."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added "The combination of our leading financial results and our top tier asset base provides unique competitive advantages which drive substantial cash flow generation and shareholder returns. Canadian Natural generated approximately $19.8 billion in adjusted funds flow in 2022, resulting in free cash flow of approximately $10.9 billion, after total dividend payments and base capital expenditures excluding net acquisitions and strategic growth capital. We were able to deliver significant returns to shareholders in 2022, totaling approximately $10.5 billion through $5.6 billion in share repurchases and $4.9 billion in dividends, including the special dividend of $1.50 per common share paid in August 2022. This equates to approximately $9.25 per share in direct returns to shareholders in 2022.

In 2022, the Board of Directors approved two separate raises to our quarterly dividend, for a combined increase of 45%, to $0.85 per common share. Subsequent to year end, the Board of Directors approved a 6% increase to the quarterly dividend to $0.90 per common share from $0.85 per common share, demonstrating the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our

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diverse, long life low decline asset base. The Company has a leading track record of 23 consecutive years of dividend increases.

We maintain a strong balance sheet and reduced our net debt by approximately $3.4 billion in 2022, closing the year with approximately $10.5 billion in net debt. In just two years, we have reduced our net debt by $10.7 billion or approximately 50% from the beginning of 2021.

Subsequent to year end 2022, up to and including March 1, 2023, the Company has returned approximately $0.5 billion to shareholders through the repurchase and cancellation of approximately 6.2 million common shares. Additionally, the Board of Directors has approved the renewal of the Company's Normal Course Issuer Bid ("NCIB"), which states that during the 12 month period commencing March 13, 2023 and ending March 12, 2024, the Company can repurchase for cancellation up to 10% of the public float, subject to TSX approval.

After reviewing our strong financial position and sustainable cash flow profile, particularly when you compare our debt levels to the size, diversity, and long life low decline nature of our high value reserves, the Board of Directors has enhanced our free cash flow allocation policy to accelerate incremental shareholder returns to 100% of free cash flow when the Company's net debt reaches $10 billion, changed from the previous $8 billion net debt level. These changes reflect the substantial debt reduction over the last two years of approximately $10.7 billion, the increase in our production and reserve base and that our fixed outstanding bonds of approximately $11.4 billion are similar to the $10 billion net debt level in the free cash flow allocation policy. Additionally, with fully committed undrawn bank credit facilities of approximately $5.5 billion, we ensure strong liquidity. Once the Company's net debt reaches $10 billion, the enhanced free cash allocation policy will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures in the year.

Canadian Natural's operations create long-term value in the areas we operate, through payments to governments, employment, investment in the oil and natural gas sector and returns to shareholders. In 2022, Canadian Natural paid a total of approximately $10.3 billion to Canadian governments in the form of income taxes, property taxes and royalties, an increase of approximately $5.3 billion, or 107%, from 2021 levels. Additionally, our 2022 capital investment of approximately $5.0 billion, excluding acquisitions, was an increase of approximately $1.5 billion, or 44%, from 2021 levels, delivering responsibly produced energy to help meet global energy demand, while creating jobs for Canadians."

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 2 Three months and year ended December 31, 2022

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**HIGHLIGHTS**

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except per common share amounts) | ($ millions, except per common share amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Net earnings | Net earnings | $**1520** | $2814 | $2534 | $**10937** | $7664 |
| Per common share | – basic | $**1.37** | $2.52 | $2.16 | $**9.64** | $6.49 |
|  | – diluted | $**1.36** | $2.49 | $2.14 | $**9.52** | $6.46 |
| Adjusted net earnings from operations <sup>(1)</sup> | Adjusted net earnings from operations <sup>(1)</sup> | $**2194** | $3493 | $2626 | $**12863** | $7420 |
| Per common share | – basic <sup>(2)</sup> | $**1.98** | $3.12 | $2.24 | $**11.33** | $6.28 |
|  | – diluted <sup>(2)</sup> | $**1.96** | $3.09 | $2.21 | $**11.19** | $6.25 |
| Cash flows from operating activities | Cash flows from operating activities | $**4544** | $6098 | $4712 | $**19391** | $14478 |
| Adjusted funds flow <sup>(1)</sup> | Adjusted funds flow <sup>(1)</sup> | $**4176** | $5208 | $4338 | $**19791** | $13733 |
| Per common share | – basic <sup>(2)</sup> | $**3.78** | $4.66 | $3.69 | $**17.44** | $11.63 |
|  | – diluted <sup>(2)</sup> | $**3.73** | $4.60 | $3.66 | $**17.22** | $11.57 |
| Cash flows used in investing activities | Cash flows used in investing activities | $**1262** | $1129 | $1615 | $**4987** | $3703 |
| Net capital expenditures <sup>(1)</sup>, excluding net acquisition costs and strategic growth capital <sup>(3)</sup> | Net capital expenditures <sup>(1)</sup>, excluding net acquisition costs and strategic growth capital <sup>(3)</sup> | $**850** | $996 | $837 | $**3956** | $3483 |
| Net capital expenditures <sup>(1)</sup> | Net capital expenditures <sup>(1)</sup> | $**1317** | $1249 | $1804 | $**5471** | $4908 |
| Daily production, before royalties | Daily production, before royalties |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Natural gas (MMcf/d) | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Natural gas (MMcf/d) | **2115** | 2132 | 1857 | **2090** | 1695 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Crude oil and NGLs (bbl/d) | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Crude oil and NGLs (bbl/d) | **942258** | 983678 | 1004425 | **933149** | 952404 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalent production (BOE/d) <sup>(4)</sup> | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalent production (BOE/d) <sup>(4)</sup> | **1294679** | 1338940 | 1313900 | **1281434** | 1234906 |

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*(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.*

*(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.*

*(3)Net capital expenditures, excluding net acquisition costs and strategic growth capital, is defined as base capital expenditures.*

*(4)A barrel of oil equivalent ("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, or to compare the value ratio using current crude oil and natural gas prices 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.*

**ANNUAL HIGHLIGHTS**

▪ The strength of Canadian Natural's long life low decline asset base, supported by safe, effective and efficient operations, makes our business unique, robust and sustainable. In 2022, the Company generated strong financial results, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Net earnings of approximately $10.9 billion and adjusted net earnings from operations of approximately $12.9 billion in 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Cash flows from operating activities of approximately $19.4 billion in 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Adjusted funds flow of approximately $19.8 billion in 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Free cash flow<sup>(1)</sup> of approximately $10.9 billion<sup>(2)</sup> in 2022 after total dividend payments of approximately $4.9 billion and base capital expenditures<sup>(3)</sup> of approximately $4.0 billion.

▪ Significant returns to shareholders and debt reduction in 2022 are a result of substantial free cash flow generation and the Company's free cash flow allocation policy that states when net debt is below $15 billion, 50% of free cash flow will be allocated to share repurchases and 50% of free cash flow allocated to the balance sheet less strategic growth / acquisition opportunities. Free cash flow for the purpose of the policy is defined as adjusted funds flow less dividends, less base capital.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 3 Three months and year ended December 31, 2022

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Returns to shareholders in 2022 were significant, having returned approximately $10.5 billion, comprised of approximately $4.9 billion in dividends and approximately $5.6 billion in share repurchases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Canadian Natural increased its sustainable and growing quarterly dividend twice in 2022 for a total combined increase of 45% to $3.40 per share annually. The last increase in 2022 was in November, when the Board of Directors approved a 13% increase to our quarterly dividend to $0.85 per common share, which demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline asset base. The Company's leading track record of dividend increases continues, as this increase marked the 23<sup>rd</sup> consecutive year of dividend increases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ In addition, the Company paid a special dividend of $1.50 per common share in August 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• In 2022, the Company repurchased a total of approximately 77.3 million common shares for cancellation at a weighted average price of $72.03 per share for a total of approximately $5.6 billion.

▪ Canadian Natural continues to maintain a strong balance sheet and financial flexibility. The Company reduced net debt<sup>(1)</sup> by approximately $3.4 billion in 2022, ending the year with approximately $10.5 billion in net debt and significant liquidity<sup>(1)</sup> of approximately $6.9 billion. The Company executed on a number of initiatives in 2022 to strengthen the Company's financial flexibility, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Repaid $1.0 billion of 3.31% medium term notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Repaid and cancelled a total of $1.15 billion of non-revolving term credit facilities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Early repayment of US$1.0 billion of 2.95% debt securities, originally due January 15, 2023.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Repaid through market purchases approximately $0.5 billion of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028.

▪ Concurrently with the release of Canadian Natural's year end results, the Company enhanced its free cash flow allocation policy due to being in a strong financial position and having a sustainable cash flow profile, particularly when you compare our debt levels to the size, diversity, and long life low decline nature of our high value reserves. As a result, the Board of Directors has confidence in the sustainability and resilience of the Company to support accelerating incremental shareholder returns to 100% of free cash flow when the Company's net debt reaches $10 billion, changed from the previous $8 billion net debt level. Once the Company's net debt reaches $10 billion, the free cash allocation policy will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures in the year.

▪ In 2022, the Company continued to focus on safe, effective and efficient operations, delivering record annual average production of 1,281,434 BOE/d, consisting of total liquids production of 933,149 bbl/d and record natural gas production of 2,090 MMcf/d.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Total BOE production increased by 4% from 2021 levels, or 8% on a production per share basis, driven by a 23% increase in annual natural gas production volumes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• As a result of the Company's diversified sale points, we achieved strong annual natural gas realized pricing of $6.55/Mcf in 2022, which was approximately 17% above the AECO benchmark price, maximizing value for shareholders. Approximately 28% of the Company's natural gas production was sold at AECO/Station 2 pricing, and approximately 34% was exported to other North American and international markets, capturing higher natural gas prices. Additionally, the Company used the equivalent of approximately 38% of its natural gas production in its operations in 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company's high value SCO captured a strong price premium to WTI of US$4.43/bbl in 2022, driving strong annual realized SCO pricing of $117.69/bbl, which on an annual basis represented approximately 46% of total liquids volumes and generated significant free cash flow for the Company.

▪ Subsequent to year end:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Board of Directors did an annual review of dividend levels and approved a 6% increase to the quarterly dividend to $0.90 per common share, from $0.85 per common share, payable on April 5, 2023 to shareholders of record on March 17, 2023.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company returned a total of approximately $1.4 billion to shareholders through approximately $0.9 billion in dividends and $0.5 billion from the repurchase and cancellation of approximately 6.2 million common shares, up to and including March 1, 2023.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 4 Three months and year ended December 31, 2022

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Board of Directors approved the renewal of the Company's NCIB, which states that during the 12 month period commencing March 13, 2023 and ending March 12, 2024, the Company can repurchase for cancellation up to 10% of the public float (determined in accordance with the rules of the TSX), subject to TSX approval.

**QUARTERLY HIGHLIGHTS**

▪ In Q4/22, the Company generated strong financial results, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Net earnings of approximately $1.5 billion and adjusted net earnings from operations of approximately $2.2 billion in Q4/22.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Cash flows from operating activities of approximately $4.5 billion in Q4/22.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Adjusted funds flow of approximately $4.2 billion in Q4/22.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Free cash flow of approximately $2.5 billion in Q4/22 after total dividend payments of approximately $0.8 billion and base capital expenditures of approximately $0.9 billion.

▪ Returns to shareholders in Q4/22 of approximately $1.6 billion, comprised of approximately $834 million in dividends and approximately $746 million in share repurchases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• In Q4/22, the Company repurchased a total of approximately 9.6 million common shares for cancellation at a weighted average price of $77.69 per share for a total of approximately $0.7 billion.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• In November 2022, the Board of Directors approved a 13% increase to our quarterly dividend to $0.85 per common share, from $0.75 per common share.

▪ Reduced net debt by approximately $1.9 billion in Q4/22.

▪ Delivered quarterly average production of 1,294,679 BOE/d, consisting of 942,258 bbl/d of liquids and 2,115 MMcf/d of natural gas.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• North America E&P liquids production, excluding thermal in situ, averaged 233,371 bbl/d in Q4/22, a 2% increase from Q3/22 levels, reflecting increased drilling activity and acquisitions, partially offset by natural declines and the impact of extreme cold weather in December 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Thermal in situ production averaged 253,188 bbl/d, a 4% increase from Q3/22 levels, reflecting strong production at Jackfish following planned maintenance activities completed in Q3/22, partially offset by natural field declines.

(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.

(2)Based on sum of rounded numbers.

(3)Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023 for more details on net capital expenditures.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 5 Three months and year ended December 31, 2022

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**RESERVES UPDATE**

A key differentiator for Canadian Natural is the strength, diversity and balance of our world class, top tier reserves. Strategically assembled and developed over several decades, these assets have a low decline rate as well as low maintenance capital relative to the size and quality of the reserves. The low maintenance capital requirements of our reserves affords the Company significant flexibility when balancing our four pillars of capital allocation to maximize shareholder value.

The Company's reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators ("IQREs"). The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2022 (all reserves values are Company Gross unless stated otherwise).

▪ Total proved reserves increased 6% to 13.587 billion BOE, with reserves additions and revisions of 1.242 billion BOE. Total proved plus probable reserves increased 6% to 18.046 billion BOE, with reserves additions and revisions of 1.563 billion BOE.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The strength and depth of the Company's assets are evident as approximately 77% of total proved reserves are long life low decline reserves. This results in a total proved BOE reserves life index<sup>(1)</sup> of approximately 32 years and a total proved plus probable BOE reserves life index of approximately 42 years.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Additionally, high value, zero decline SCO is approximately 51% of total proved reserves with a reserve life index of approximately 44 years.

▪ Proved developed producing reserves additions and revisions are 491 million BOE, replacing 2022 production by 105%. The proved developed producing BOE reserves life index is approximately 21 years.

▪ Total proved reserves additions and revisions replaced 2022 production by 265%. Total proved plus probable reserves additions and revisions replaced 2022 production by 334%. This includes negative technical revisions as a result of accelerating the cessation of production from two platforms in the North Sea.

▪ In 2022, Canadian Natural continued to achieve strong finding and development costs:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• FD&A<sup>(1)</sup> costs, excluding changes in Future Development Cost ("FDC"), are $4.11/BOE for total proved reserves and $3.26/BOE for total proved plus probable reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• FD&A costs, including changes in FDC, are $8.39/BOE for total proved reserves and $7.62/BOE for total proved plus probable reserves.

▪ The net present value of future net revenues, before income tax, discounted at 10%, is approximately $102.3 billion for proved developed producing reserves, approximately $150.9 billion for total proved reserves, and approximately $183.7 billion for total proved plus probable reserves.

(1)Supplementary financial measure. Refer to the "2022 Year End Reserves" section of this interim report.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 6 Three months and year ended December 31, 2022

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**OPERATIONS REVIEW AND CAPITAL ALLOCATION**

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural's production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO (herein collectively referred to as "crude oil") and natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company's shareholders.

Underpinning this asset base is the Company's long life low decline production, representing approximately 73% of total liquids production in 2022, the majority of which is zero decline high value SCO production from the Company's world class Oil Sands Mining and Upgrading assets. The remaining balance of the Company's long life low decline production comes from its top tier thermal in situ oil sands operations and Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, and effective and efficient operations results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.

In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximize value for our shareholders. Supporting these projects is the Company's undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company's operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions or corporate needs.

Canadian Natural's balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.

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| | | | | |
|:---|:---|:---|:---|:---|
| **Drilling Activity** | Year Ended Dec 31 | Year Ended Dec 31 | Year Ended Dec 31 | Year Ended Dec 31 |
|  | **2022** | **2022** | 2021 | 2021 |
| (number of wells) | **Gross** | **Net** | Gross | Net |
| Crude oil <sup>(1)</sup> | **332** | **317** | 154 | 149 |
| Natural gas | **100** | **72** | 62 | 49 |
| Dry | **1** | **1** | 1 | 1 |
| Subtotal | **433** | **390** | 217 | 199 |
| Stratigraphic test / service wells | **530** | **452** | 485 | 393 |
| Total | **963** | **842** | 702 | 592 |
| &nbsp;&nbsp;&nbsp;&nbsp;Success rate (excluding stratigraphic test / service wells) |  | **99%** |  | 99% |

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*(1)Includes bitumen wells.*

▪ The Company drilled a total of 390 net crude oil and natural gas wells in 2022 compared to 199 in 2021, nearly doubling the number of wells drilled over this time period.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 7 Three months and year ended December 31, 2022

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**North America Exploration and Production**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| *Crude oil and NGLs – excluding Thermal In Situ Oil Sands* | *Crude oil and NGLs – excluding Thermal In Situ Oil Sands* | *Crude oil and NGLs – excluding Thermal In Situ Oil Sands* | *Crude oil and NGLs – excluding Thermal In Situ Oil Sands* |  |  |
|  | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
|  | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Crude oil and NGLs production (bbl/d) | **233371** | 228239 | 215628 | **227953** | 213336 |
| Net wells targeting crude oil | **71** | 60 | 20 | **214** | 136 |
| Net successful wells drilled | **71** | 60 | 20 | **213** | 135 |
| &nbsp;&nbsp;&nbsp;&nbsp;Success rate | **100%** | 100% | 100% | **99%** | 99% |

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▪ North America E&P liquids production, excluding thermal in situ, averaged 227,953 bbl/d in 2022, an increase of 7% from 2021 levels, reflecting increased drilling activity and acquisitions, partially offset by natural declines and the impact of extreme cold weather in December 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Primary heavy crude oil production averaged 67,699 bbl/d in 2022, an increase of 5% from 2021 levels, reflecting strong results from the Company's horizontal multilateral drilling program, partially offset by natural field declines.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Operating costs<sup>(1)</sup> in the Company's primary heavy crude oil operations averaged $21.84/bbl (US$16.79/bbl) in 2022, an increase of 13% from 2021 levels, primarily due to higher energy and trucking costs.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ In 2022, the Company drilled a total of 127 net horizontal multilateral heavy oil wells, including 52 net wells at Smith in the Clearwater. The Company's Clearwater production averaged approximately 13,000 BOE/d in Q4/22, up by approximately 9,100 BOE/d from the start of the year.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Pelican Lake production averaged 50,333 bbl/d in 2022, a decrease of 7% from 2021 levels, primarily reflecting a temporary injection reduction in Q4/22 and natural field declines. As of February 2023, injection rates have been reinstated and the polymer flood field is targeted to return to its historical low decline rate of approximately 5% in the second half of 2023.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Operating costs at Pelican Lake averaged $8.36/bbl (US$6.43/bbl) in 2022, a 24% increase from 2021 levels, primarily as a result of higher energy costs.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• North America light crude oil and NGL production averaged 109,921 bbl/d in 2022, an increase of 16% from 2021 levels as a result of strong drilling results and acquisitions, partially offset by natural field declines.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Operating costs in the Company's North America light crude oil and NGL areas averaged $15.91/bbl (US$12.23/bbl) in 2022, an increase of 4% from 2021 levels, primarily due to higher energy costs.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ The Company successfully drilled a total of 32 net Montney and Deep Basin light crude oil wells in 2022.

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| *Thermal In Situ Oil Sands* | *Thermal In Situ Oil Sands* | *Thermal In Situ Oil Sands* | *Thermal In Situ Oil Sands* |  |  |
|  | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
|  | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Bitumen production (bbl/d) | **253188** | 243393 | 263110 | **252018** | 259284 |
| Net wells targeting bitumen | **9** | 38 | 1 | **104** | 8 |
| Net successful wells drilled | **9** | 38 | 1 | **104** | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;Success rate | **100%** | 100% | 100% | **100%** | 100% |

---

▪ Canadian Natural's long life low decline thermal in situ assets produced an average of 252,018 bbl/d in 2022, a decrease of 3% from 2021 levels, demonstrating the long life low decline nature of these assets.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Thermal in situ operating costs averaged $16.50/bbl (US$12.68/bbl) in 2022, an increase of 36% from 2021 levels, primarily related to higher energy costs.

(1)Calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.

(2)Supplementary financial measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 8 Three months and year ended December 31, 2022

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▪ The Company remains on track with its pad development plans across its thermal in situ assets, adding production while offsetting natural field declines. The Company targets to achieve capital efficiencies ranging from approximately $8,000/bbl/d to $10,000/bbl/d on its Steam Assisted Gravity Drainage ("SAGD") and cyclic steam stimulation ("CSS") pads.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• At Primrose, the Company finished drilling two CSS pads in Q4/22, and targets to bring these pads on production in early Q3/23.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• At Kirby, the Company is progressing with the development of four SAGD pads, the first of which began steam injection in late December 2022 and targets to ramp up to full production capacity in Q3/23. The remaining three pads target to ramp up to full production capacity in 2024.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• At Jackfish, the Company is currently drilling a SAGD pad, which is targeted to begin steam injection in early Q4/23 and ramp up to full production capacity in 2024.

▪ Canadian Natural has been piloting solvent enhanced oil recovery technology on certain of its thermal in situ assets with an objective to increase bitumen production, reduce the Steam to Oil Ratio ("SOR"), reduce GHG intensity and realize high solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• After a successful solvent pilot at Kirby South, the Company has substantially completed engineering and design of a commercial scale solvent SAGD pad development at Kirby North. The solvent facility site construction and module installations are targeted to begin in Q3/23, followed by solvent injection targeted for Q2/24.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• At Primrose, the Company is currently piloting solvent enhanced oil recovery in the steam flood area and is targeting SOR and GHG intensity reductions of 40% to 45%, with solvent recovery greater than 70%. Results to date have been positive and the Company targets to complete the pilot in Q4/23.

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| *North America Natural Gas* | *North America Natural Gas* | *North America Natural Gas* | *North America Natural Gas* |  |  |
|  | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
|  | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Natural gas production (MMcf/d) | **2105** | 2117 | 1841 | **2075** | 1680 |
| Net wells targeting natural gas | **15** | 14 | 9 | **72** | 49 |
| Net successful wells drilled | **15** | 14 | 9 | **72** | 49 |
| &nbsp;&nbsp;&nbsp;&nbsp;Success rate | **100%** | 100% | 100% | **100%** | 100% |

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▪ Canadian Natural achieved record annual North America natural gas production in 2022, averaging approximately 2,075 MMcf/d, an increase of 395 MMcf/d, or 24%, from 2021 levels, driven by strong drilling results and acquisitions, partially offset by natural field declines and the impact of extreme cold weather in December 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• North America natural gas operating costs averaged $1.19/Mcf in 2022, a 3% increase from 2021 levels, primarily reflecting higher energy costs.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company's successful natural gas drilling program included 15 net wells in Q4/22, bringing the total drilled in the year to 72 net wells, including 38 net Montney and 34 net Deep Basin wells.

▪ As a result of the Company's diversified sales points, the Company realized strong North American natural gas pricing of $6.51/Mcf in 2022, which is 16% above the 2022 average AECO benchmark price.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 9 Three months and year ended December 31, 2022

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**International Exploration and Production**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Crude oil production (bbl/d) | **26915** | 24493 | 32281 | **27233** | 31650 |
| Natural gas production (MMcf/d) | **10** | 15 | 16 | **15** | 15 |
| Net wells targeting crude oil | **—** |  | 1.0 | **—** | 5.9 |
| Net successful wells drilled | **—** |  | 1.0 | **—** | 5.9 |
| &nbsp;&nbsp;&nbsp;&nbsp;Success rate | **—%** | —% | 100% | **—%** | 100% |

---

▪ International E&P crude oil production volumes averaged 27,233 bbl/d in 2022, a decrease of 14% from 2021 levels, primarily reflecting natural field declines and maintenance activities in 2022.

▪ Primarily as a result of prevailing regulatory and economic conditions in 2022 along with the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, the Company completed an assessment of its North Sea operations and de-booked 65 million BOE of its North Sea total proved reserves and 99 million BOE of its North Sea total proved plus probable reserves, representing approximately 0.5% of the Company's total reserves at December 31, 2022. Additionally, the Company is accelerating the abandonment of two of the platforms in the North Sea.

**North America Oil Sands Mining and Upgrading**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Synthetic crude oil production (bbl/d) <sup>(1)(2)</sup>  | **428784** | 487553 | 493406 | **425945** | 448133 |

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*(1)SCO production before royalties and excludes production volumes consumed internally as diesel.* 

*(2)Consists of heavy and light synthetic crude oil products.*

▪ Canadian Natural continues to focus on safe, reliable and efficient operations of its world class Oil Sands Mining and Upgrading assets to deliver high value SCO. Production averaged 425,945 bbl/d in 2022, a decrease of 5% from 2021 levels, primarily as a result of the previously announced updated Q4/22 targeted production range as well as the impact of extreme cold weather conditions in December 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• As a result of extreme cold weather in December 2022, the Company had to complete multiple mining equipment repairs, resulting in reduced rates at Horizon in both December 2022 and January 2023. These events are targeted to impact Q1/23 production by approximately 25,000 bbl/d. Production from the Company's Oil Sands Mining and Upgrading assets averaged approximately 483,000 bbl/d in February 2023.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company is progressing with its reliability enhancement project, which is now targeted to be 45 days ahead of our previous schedule. This project targets to extend the major maintenance cycle from once per year to once every second year, increasing the SCO production capacity by approximately 5,000 bbl/d in 2023, increasing to approximately 14,000 bbl/d in 2025.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• As a result of the advancement of the reliability enhancement project and the reduced rates in Q1/23, the Company's 2023 thermal and Oil Sands Mining and Upgrading production guidance range remains unchanged.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Approximately 46% of the Company's total liquids production is comprised of high value SCO, which captured a strong price premium to WTI of US$4.43/bbl in 2022, driving strong SCO average realized pricing of $117.69/bbl and generating significant free cash flow for the Company.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Operating costs on the Company's SCO averaged $26.04/bbl (US$20.01/bbl) in 2022, an increase of 25% from 2021 levels as a result of increased energy and maintenance services costs, together with lower production volumes in 2022.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 10 Three months and year ended December 31, 2022

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▪ Included in the Company's previously announced 2023 production guidance, planned turnaround schedules for its Oil Sands Mining and Upgrading operations in 2023 include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• A major turnaround at the non-operated Scotford Upgrader is targeted to begin in April 2023 with reduced rates from the mines targeted for approximately 73 days, impacting 2023 annual production by approximately 8,300 bbl/d.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• A turnaround at Horizon is targeted to begin in May 2023 with a full plant outage targeted for approximately 28 days, impacting 2023 annual production by approximately 21,600 bbl/d. During this time, the Company is planning to complete tie ins supporting the reliability enhancement project.

▪ The Company is evaluating the detailed design work of the 750t/hr commercial unit for the In-Pit Extraction Plant ("IPEP") that will provide dry stackable tailings directly in the mine-pit, targeting to reduce GHG emissions and tailings ponds in the future.

**MARKETING**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Crude oil and NGLs pricing |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;WTI benchmark price (US$/bbl) <sup>(1)</sup> | $**82.62** | $91.64 | $77.17 | $**94.23** | $67.96 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;WCS heavy differential as a percentage of<br>WTI (%) <sup>(2)</sup> | **31%** | 22% | 19% | **19%** | 19% |
| &nbsp;&nbsp;&nbsp;&nbsp;SCO benchmark price (US$/bbl)  | $**86.78** | $100.51 | $75.39 | $**98.66** | $66.36 |
| &nbsp;&nbsp;&nbsp;&nbsp;Condensate benchmark price (US$/bbl) | $**83.33** | $87.15 | $79.10 | $**93.69** | $68.24 |
| &nbsp;&nbsp;&nbsp;&nbsp;Exploration & Production liquids realized pricing (C$/bbl) <sup>(3)(4)</sup> | $**69.34** | $84.91 | $72.81 | $**90.64** | $63.71 |
| &nbsp;&nbsp;&nbsp;&nbsp;SCO realized pricing (C$/bbl) <sup>(5)</sup> | $**103.79** | $120.91 | $88.48 | $**117.69** | $77.95 |
| Natural gas pricing |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;AECO benchmark price (C$/GJ) | $**5.29** | $5.51 | $4.67 | $**5.28** | $3.38 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Average realized pricing before risk<br>management (C$/Mcf) <sup>(4)</sup> | $**6.39** | $6.57 | $5.35 | $**6.55** | $4.07 |

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*(1)West Texas Intermediate ("WTI").*

*(2)Western Canadian Select ("WCS").*

*(3)Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.*

*(4)Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.*

*(5)Pricing is net of blending costs and excluding risk management activities.*

▪ Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, thermal in situ bitumen and SCO.

▪ Commodity prices improved in 2022, with WTI averaging US$94.23/bbl, an increase of 39% from US$67.96/bbl in 2021. Crude oil prices increased in the first half of 2022, primarily in response to the impact of the Russian invasion of Ukraine, the OPEC+ decision to adhere to production cut agreements, and an increase in global demand for crude oil due to improved economic conditions as a result of the lessening of COVID-19 restrictions. In the latter part of 2022, crude oil prices softened due to demand concerns related to the temporary reinstatement of COVID-19 restrictions in China, rising interest rates and concerns of a global recession.

▪ SCO benchmark pricing remained strong as a result of strong North American demand for refined products, averaging US$98.66/bbl in 2022, representing a US$4.43/bbl price premium to WTI, relative to a US$1.60/bbl discount to WTI in 2021.

▪ Increased market access from western Canada has resulted in a more balanced market for heavy crude oil, with the WCS heavy oil differential as a percentage of WTI remaining at 19% in 2022, the same percentage as in 2021.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 11 Three months and year ended December 31, 2022

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▪ Natural gas prices continued to strengthen in 2022, with AECO averaging $5.28/GJ in 2022, an increase of 56% from 2021 levels, primarily reflecting lower storage levels and increased NYMEX benchmark pricing.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Canadian Natural has diversified sales points to maximize value for our shareholders. Approximately 28% of its natural gas production was sold at AECO/Station 2 pricing, and approximately 34% was exported to other North American and international markets, capturing higher natural gas prices. Additionally, the Company used the equivalent of approximately 38% of its natural gas production in its operations in 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company's diversified sales points drove strong annual realized natural gas pricing averaging $6.55/Mcf in 2022, which was 17% above the average AECO benchmark price in 2022.

*▪* The North West Redwater ("NWR") refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 58,351 BOE/d in 2022 and resulted in strong margins on domestic diesel volumes.

▪ Canadian Natural has been a supporter of incremental pipeline projects to ensure Canadian crude oil and natural gas can access global markets to deliver the most responsible and leading ESG production that the world needs.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Canadian Natural has committed 94,000 bbl/d on the 590,000 bbl/d Trans Mountain Pipeline Expansion. Trans Mountain Corporation anticipates mechanical completion of the pipeline to occur at the end of Q3/23 with commercial service expected to occur late in Q4/23 per its third quarter 2022 press release dated November 29, 2022.

**FINANCIAL REVIEW&nbsp;&nbsp;&nbsp;&nbsp;**

The Company continues to implement proven strategies including its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural's adjusted funds flow generation, credit facilities, US commercial paper program, access to capital markets, diverse asset base and flexible capital expenditure program, all support a strong financial position and provide the appropriate financial resources for the near-, mid- and long-term.

▪ Safe, effective and efficient operations combined with our high quality, long life low decline asset base generated annual free cash flow of approximately $10.9 billion after dividend payments of approximately $4.9 billion and base capital expenditures of approximately $4.0 billion (excluding net acquisitions and strategic growth capital, as per the Company's free cash flow allocation policy).

▪ In 2022, Canadian Natural's free cash flow allocation policy stated that when net debt is below $15 billion, 50% of free cash flow will be allocated to share repurchases and 50% of free cash flow to the balance sheet less strategic growth / acquisition opportunities. Free cash flow for the purpose of the policy is defined as adjusted funds flow less dividends, less base capital.

▪ Returns to shareholders were significant in 2022, having returned approximately $10.5 billion, comprised of approximately $4.9 billion in dividends and approximately $5.6 billion in share repurchases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Canadian Natural increased its sustainable and growing quarterly dividend twice in 2022 for a total combined increase of 45% to $3.40 per share annually. The last increase in 2022 was in November, when the Board of Directors approved a 13% increase to our quarterly dividend to $0.85 per common share, which demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline asset base. The Company's leading track record of dividend increases continues, as this increase marked the 23<sup>rd</sup> consecutive year of dividend increases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ In addition, the Company paid a special dividend of $1.50 per common share in August 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• In 2022, the Company repurchased a total of approximately 77.3 million common shares for cancellation at a weighted average price of $72.03 per share for a total of approximately $5.6 billion.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ In Q4/22, the Company repurchased a total of approximately 9.6 million common shares for cancellation at a weighted average price of $77.69 per share for a total of approximately $0.7 billion.

▪ Canadian Natural continues to maintain a strong balance sheet and financial flexibility. The Company reduced net debt by approximately $3.4 billion in 2022, ending the year with approximately $10.5 billion in net debt and significant liquidity of approximately $6.9 billion. The Company executed on a number of initiatives in 2022 to strengthen the Company's financial flexibility, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Repaid $1.0 billion of 3.31% medium term notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Repaid and cancelled a total of $1.15 billion of non-revolving term credit facilities.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 12 Three months and year ended December 31, 2022

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Early repayment of US$1.0 billion of 2.95% debt securities, originally due January 15, 2023.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Repaid through market purchases approximately $0.5 billion of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Undrawn revolving bank credit facilities totaling approximately $5.5 billion were available at December 31, 2022. Including cash and cash equivalents and short-term investments, the Company had significant liquidity of approximately $6.9 billion. At year end, the Company had no amount drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

▪ Concurrently with the release of Canadian Natural's year end results, the Company enhanced its free cash flow allocation policy due to being in a strong financial position and having a sustainable cash flow profile, particularly when you compare our debt levels to the size, diversity, and long life low decline nature of our high value reserves. As a result, the Board of Directors has confidence in the sustainability and resilience of the Company to support accelerating incremental shareholder returns to 100% of free cash flow when the Company's net debt reaches $10 billion instead of the previous $8 billion net debt level. Once the Company's net debt reaches $10 billion, the free cash allocation policy will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures in the year.

▪ Subsequent to year end:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company, up to and including March 1, 2023, returned approximately $1.4 billion to shareholders through approximately $0.9 billion in dividends and $0.5 billion from the repurchase and cancellation of approximately 6.2 million common shares.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Board of Directors approved the renewal of the Company's NCIB, which states that during the 12 month period commencing March 13, 2023 and ending March 12, 2024, the Company can repurchase for cancellation up to 10% of the public float (determined in accordance with the rules of the TSX), subject to TSX approval.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Board of Directors did an annual review of dividend levels and approved a 6% increase to the quarterly dividend to $0.90 per common share, from $0.85 per common share, payable on April 5, 2023 to shareholders of record on March 17, 2023.

**ENVIRONMENTAL, SOCIAL AND GOVERNANCE HIGHLIGHTS**

Canada and Canadian Natural are well positioned to deliver affordable, reliable, safe and responsibly produced energy that the world needs through leading ESG performance. Canadian Natural's culture of continuous improvement provides a significant advantage and results in ongoing enhancements to the Company's environmental performance.

**Environmental Targets**

Canadian Natural is committed to reducing its environmental footprint and as previously announced, has committed to the following environmental targets:

▪ 40% reduction in corporate Scope 1 and Scope 2 absolute GHG emissions by 2035, from a 2020 baseline

▪ 50% reduction in North America E&P (including thermal in situ) methane emissions by 2030, from a 2016 baseline

▪ 40% reduction in thermal in situ fresh water usage intensity by 2026, from a 2017 baseline

▪ 40% reduction in mining fresh river water usage intensity by 2026, from a 2017 baseline

Canadian Natural is an industry leader in abandonment and reclamation activity and through its active program, the Company has abandoned more than 3,000 wells per year in each of the last two years. At this pace, the Company would be able to achieve 100% abandonment of its current inventory of inactive wells in approximately 10 years.

**Pathways Alliance**

The six major oil sands companies in the Pathways Alliance ("Pathways"), including Canadian Natural, operate approximately 95% of Canada's oil sands production. The goal of this unique alliance is to support Canada in meeting its climate commitments and position Canada to be the preferred source of crude oil globally. Working collectively with the federal and provincial governments, the Pathways Alliance has a goal to achieve net zero GHG emissions from oil sands operations by 2050 and is pursuing realistic and workable solutions to deliver significant emission reductions.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 13 Three months and year ended December 31, 2022

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On January 4, 2023, Pathways reached another milestone as it entered into a Carbon Sequestration Evaluation Agreement with the Government of Alberta, enabling Pathways to conduct a detailed evaluation of the proposed geological storage hub to safely inject and permanently store CO2. Members of Pathways are advancing environmental field programs, engineering design and a subsurface development plan. Ongoing field activity includes a water injection well test at a Manatokan site, which is refining our understanding of storage capability and capacity, and will ensure safe, effective and efficient CO2 sequestration.

The proposed carbon storage hub would be one of the world's largest carbon capture and storage ("CCS") projects and would be connected to a transportation line that would initially gather captured CO2 from an anticipated 14 oil sands facilities in the Fort McMurray, Christina Lake and Cold Lake regions. The plan is to grow the transportation network to include over 20 oil sands facilities, and to accommodate other industries in the region interested in CCS. Stakeholder engagement continues to progress with Indigenous and local communities in northern Alberta related to the Pathways CCS project.

**Government Support for Carbon Capture, Utilization and Storage ("CCUS")**

Canadian Natural is a leader in CCUS and GHG reduction projects and sees many opportunities for industry to advance investments in CCUS. The Government of Canada has proposed an investment tax credit for CCUS projects for all sectors across Canada. In addition, the Government of Alberta announced its 2023 Budget on February 28, 2023, which includes support for CCUS projects and coordination with federal CCUS initiatives. Together, these are positive approaches whereby industry and governments can co-invest in infrastructure that advances CCUS projects. Decarbonization projects, including CCUS, represents an important opportunity for industry and governments to work together to achieve climate goals and economic objectives while supporting Canada's allies with energy security.

**Technology Innovation and Emissions Reduction ("TIER") Regulation**

In Q4/22, the Alberta government announced changes to its Technology Innovation and Emissions Reduction Regulation ("TIER"), which became effective January 1, 2023, to align with the federal carbon pricing system. It is encouraging that the federal government review of provincial carbon pricing systems continued to accept the TIER system in Alberta. Moving forward, it will be important to work together to ensure that the TIER system continues to support sustainable, long-term investments in GHG reduction technologies.

**Blueberry River First Nations**

In January 2023, the British Columbia Government and the Oil & Gas Commission came to a resolution with the Blueberry River First Nations ("BRFN") regarding the impact of resource development on the BRFN lands. Further engagement with government and the regulator is required to gather more information to understand the implementation of its land management framework and the impacts to Canadian Natural going forward. The Company values its relationships with local Indigenous communities, including the Blueberry River First Nations, and meets regularly with communities to build and maintain positive relationships in order to create shared value and mutual benefit from our operations.

**British Columbia Royalty Framework**

On May 19, 2022, the Government of British Columbia ("BC") announced a new royalty framework, which comes into effect 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 are recovered and then a price sensitive royalty rate between 5% and 40% will apply and will 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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 14 Three months and year ended December 31, 2022

------

**2022 YEAR END RESERVES**

**Determination of Reserves**

For the year ended December 31, 2022, the Company retained Independent Qualified Reserves Evaluators (IQREs), Sproule Associates Limited, Sproule International Limited and GLJ Ltd., to evaluate and review all of the Company's proved and 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. The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.

The Reserves Committee of the Company's Board of Directors has met with and carried out independent due diligence procedures with the IQREs as to the Company's reserves.

Additional reserves information is disclosed in the Company's Annual Information Form.

**Summary of Company Gross Reserves**

**As of December 31, 2022<br>Forecast Prices and Costs**

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | Light and<br>Medium<br>Crude Oil<br>(MMbbl) | Primary<br>Heavy<br>Crude Oil<br>(MMbbl) | Pelican Lake <br>Heavy<br>Crude Oil<br>(MMbbl) | Bitumen <br>(Thermal Oil)<br>(MMbbl) | Synthetic<br>Crude Oil<br>(MMbbl) | Natural Gas<br>(Bcf) | Natural Gas<br>Liquids<br>(MMbbl) | Barrels of Oil<br>Equivalent<br>(MMBOE) |
| **Total Company** |  |  |  |  |  |  |  |  |
| Proved |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Developed Producing | 122 | 96 | 207 | 540 | 6836 | 4989 | 143 | 8775 |
| &nbsp;&nbsp;&nbsp;&nbsp;Developed Non-Producing | 16 | 11 |  | 140 |  | 306 | 6 | 225 |
| &nbsp;&nbsp;&nbsp;&nbsp;Undeveloped | 93 | 73 | 55 | 2604 | 37 | 8332 | 337 | 4587 |
| Total Proved | 231 | 179 | 262 | 3284 | 6873 | 13627 | 486 | 13587 |
| Probable | 89 | 93 | 114 | 1901 | 535 | 8643 | 285 | 4458 |
| Total Proved plus Probable | 320 | 272 | 376 | 5186 | 7408 | 22270 | 772 | 18046 |

---

**Notes to Reserves:**

1. Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.

2. Information in the reserves data tables may not add due to rounding. BOE values and oil and gas metrics may not calculate exactly due to rounding.

3. Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates are the 3-consultant-average of price forecasts developed by Sproule Associates Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated December 31, 2022:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | 2023 | 2024 | 2025 | 2026 | 2027 |
| **Crude Oil and NGL** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;WTI | US$/bbl | 80.33 | 78.50 | 76.95 | 77.61 | 79.16 |
| &nbsp;&nbsp;&nbsp;&nbsp;WCS | C$/bbl | 76.54 | 77.75 | 77.55 | 80.07 | 81.89 |
| &nbsp;&nbsp;&nbsp;&nbsp;Canadian Light Sweet | C$/bbl | 103.76 | 97.74 | 95.27 | 95.58 | 97.07 |
| &nbsp;&nbsp;&nbsp;&nbsp;Cromer LSB | C$/bbl | 104.55 | 98.50 | 95.55 | 96.83 | 98.13 |
| &nbsp;&nbsp;&nbsp;&nbsp;Edmonton C5+ | C$/bbl | 106.22 | 101.35 | 98.94 | 100.19 | 101.74 |
| &nbsp;&nbsp;&nbsp;&nbsp;Brent | US$/bbl | 84.67 | 82.69 | 81.03 | 81.39 | 82.65 |
| **Natural gas** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;AECO | C$/MMBtu | 4.23 | 4.40 | 4.21 | 4.27 | 4.34 |
| &nbsp;&nbsp;&nbsp;&nbsp;BC Westcoast Station 2 | C$/MMBtu | 4.08 | 4.28 | 4.11 | 4.16 | 4.23 |
| &nbsp;&nbsp;&nbsp;&nbsp;Henry Hub | US$/MMBtu | 4.74 | 4.50 | 4.31 | 4.40 | 4.49 |

---

All prices increase at a rate of 2%/year after 2027.

A foreign exchange rate of 0.7450 US$/C$ for 2023 and 0.7650 US$/C$ for 2024, 0.7683 US$/C$ for 2025, 0.7717 US$/C$ for 2026 and 0.7750 US$/C$ after 2026 was used in the year end 2022 evaluation.

4. A barrel of oil equivalent ("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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 15 Three months and year ended December 31, 2022

------

5. Oil and gas metrics included herein are commonly used in the crude oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when making comparisons. Management uses these metrics to evaluate Canadian Natural's performance over time. However, such measures are not reliable indicators of Canadian Natural's future performance and future performance may vary.

6. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.

7. Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period.

8. Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2023 proved developed producing production forecast prepared by the Independent Qualified Reserves Evaluators.

9. Finding, Development and Acquisition ("FD&A") costs excluding changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2022 by the sum of total additions and revisions for the relevant reserves category.

10. FD&A costs including changes in FDC are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2022 and net changes in FDC from December 31, 2021 to December 31, 2022 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation costs.

11. Abandonment, decommissioning and reclamation ("ADR") costs included in the calculation of the Future Net Revenue (FNR) consist of both the Company's total Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as at December 31, 2022 and forecast estimates of ADR costs attributable to future development activity.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 16 Three months and year ended December 31, 2022

------

**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 press release and the 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 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 effects of the novel coronavirus ("COVID-19") pandemic, the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+") and inflation) 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 including due to actions of OPEC+ taken in response to COVID-19 or otherwise; 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; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; 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 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); 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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 17 Three months and year ended December 31, 2022

------

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this press release or the Company's 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 press release or the Company's 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 Currency, Financial Information and Production**

This press release should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three months and year ended December 31, 2022 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2021. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three months and year ended December 31, 2022 and the Company's MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout the Company's 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 the Company's 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 financial results for the three months and year ended December 31, 2022 in relation to the comparable periods in 2021 and the third quarter of 2022. In addition, the Company's MD&A details its targeted capital program for 2023. The accompanying tables form an integral part of the Company's MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2021, is available on SEDAR at www.sedar.com 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 the Company's MD&A dated March 1, 2023.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 18 Three months and year ended December 31, 2022

------

**Special Note Regarding non-GAAP and Other Financial Measures**

This press release includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial performance, financial position or 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 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 press release, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022, dated March 1, 2023.

**Free Cash Flow**

Free cash flow is a non-GAAP financial measure that represents adjusted funds flow adjusted for base capital expenditures and dividends on common shares. 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, pay returns to shareholders and to repay debt.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Adjusted funds flow <sup>(1)</sup> | $**4176** | $5208 | $4338 | $**19791** | $13733 |
| Less: Base capital expenditures <sup>(2)</sup> | **850** | 996 | 837 | **3956** | 3483 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Dividends on common shares | **834** | 2532 | 558 | **4926** | 2170 |
| Free cash flow | $**2492** | $1680 | $2943 | $**10909** | $8080 |

---

*(1)Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023.*

*(2)Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of Company's MD&A for the three months and year ended December 31, 2022 dated March 1, 2023 for more details on net capital expenditures.*

**Capital Budget**

Capital budget is a 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 the Company's MD&A for more details on net capital expenditures.

**Long-term Debt, net**

Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.

**Capital Efficiency**

Capital efficiency is a supplementary financial measure that represents the capital spent to add new or incremental production divided by the current rate of the new or incremental production. It is expressed as a dollar amount per flowing volume of a product ($/bbl/d or $/BOE/d). The Company considers capital efficiency a key measure in evaluating its performance, as it demonstrates the efficiency of the Company's capital investments.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 19 Three months and year ended December 31, 2022

------

**CONFERENCE CALL**

Canadian Natural Resources Limited (TSX-CNQ / NYSE-CNQ) will be issuing its 2022 Fourth Quarter and Year End Results on Thursday, March 2, 2023 before market open.

A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, March 2, 2023.

**Dial-in to the live event:**

North America 1-888-886-7786 / International 001-416-764-8658

**Listen to the audio webcast:**

Access the audio webcast on the home page of our website, www.cnrl.com.

**Conference call playback:**

North America 1-877-674-7070 / International 001-416-764-8692 (Passcode: 348479#)

Canadian Natural is a senior oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.

---

| |
|:---|
| **CANADIAN NATURAL RESOURCES LIMITED** |
| 2100, 855 - 2<sup>nd</sup> Street S.W. Calgary, Alberta, T2P4J8<br>Phone: 403-514-7777 Email: ir@cnrl.com<br>www.cnrl.com |
| **TIM S. MCKAY**<br>President<br>**MARK A. STAINTHORPE**<br>Chief Financial Officer and Senior Vice-President, Finance<br>**LANCE J. CASSON**<br>Manager, Investor Relations<br>Trading Symbol - CNQ<br>Toronto Stock Exchange<br>New York Stock Exchange |

---

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 20 Three months and year ended December 31, 2022

## Exhibit 99.2

![canadiannatural_color.jpg](canadiannatural_color.jpg)

**CANADIAN NATURAL RESOURCES LIMITED**

---

| |
|:---|
| **MANAGEMENT'S DISCUSSION & ANALYSIS**<br>**FOR THE THREE MONTHS AND YEAR ENDED DECEMBER 31, 2022** |
| **MARCH 1, 2023** |

---

------

**MANAGEMENT'S DISCUSSION AND ANALYSIS**

**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 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 effects of the novel coronavirus ("COVID-19") pandemic, the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+") and inflation) 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 including due to actions of OPEC+ taken in response to COVID-19 or otherwise; 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; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; 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 of 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); 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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 1 Three months and year ended December 31, 2022

------

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 and Production**

This MD&A should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three months and year ended December 31, 2022 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2021. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three months and year ended December 31, 2022 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 and per unit statistics 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 financial results for the three months and year ended December 31, 2022 in relation to the comparable periods in 2021 and the third quarter of 2022. In addition, this MD&A details the Company's targeted capital program for 2023. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2021, is available on SEDAR at <u>www.sedar.com</u>, and on EDGAR at <u>www.sec.gov</u>. 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 March 1, 2023.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 2 Three months and year ended December 31, 2022

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**FINANCIAL HIGHLIGHTS**

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except per common share amounts) | ($ millions, except per common share amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Product sales <sup>(1)</sup> | Product sales <sup>(1)</sup> | $**11012** | $12574 | $10190 | $**49530** | $32854 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Crude oil and NGLs | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Crude oil and NGLs | $**9508** | $11001 | $8979 | $**43009** | $29256 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Natural gas |  | $**1287** | $1342 | $958 | $**5236** | $2716 |
| Net earnings | Net earnings | $**1520** | $2814 | $2534 | $**10937** | $7664 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Per common share | – basic | $**1.37** | $2.52 | $2.16 | $**9.64** | $6.49 |
|  | – diluted | $**1.36** | $2.49 | $2.14 | $**9.52** | $6.46 |
| Adjusted net earnings from operations <sup>(2)</sup> | Adjusted net earnings from operations <sup>(2)</sup> | $**2194** | $3493 | $2626 | $**12863** | $7420 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Per common share | – basic <sup>(3)</sup> | $**1.98** | $3.12 | $2.24 | $**11.33** | $6.28 |
|  | – diluted <sup>(3)</sup> | $**1.96** | $3.09 | $2.21 | $**11.19** | $6.25 |
| Cash flows from operating activities | Cash flows from operating activities | $**4544** | $6098 | $4712 | $**19391** | $14478 |
| Adjusted funds flow <sup>(2)</sup>  | Adjusted funds flow <sup>(2)</sup>  | $**4176** | $5208 | $4338 | $**19791** | $13733 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Per common share | – basic <sup>(3)</sup> | $**3.78** | $4.66 | $3.69 | $**17.44** | $11.63 |
|  | – diluted <sup>(3)</sup> | $**3.73** | $4.60 | $3.66 | $**17.22** | $11.57 |
| Cash flows used in investing activities | Cash flows used in investing activities | $**1262** | $1129 | $1615 | $**4987** | $3703 |
| Net capital expenditures <sup>(2)</sup> | Net capital expenditures <sup>(2)</sup> | $**1317** | $1249 | $1804 | $**5471** | $4908 |

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*(1)Further details related to product sales are disclosed in note 18 to the 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.*

**SUMMARY OF FINANCIAL HIGHLIGHTS**

**Consolidated Net Earnings and Adjusted Net Earnings from Operations**

Net earnings for the year ended December 31, 2022 were $10,937 million compared with $7,664 million for the year ended December 31, 2021. Net earnings for the year ended December 31, 2022 included non-operating items, net of tax, of $1,926 million compared with $244 million for the year ended December 31, 2021 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of 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 de-booking of reserves at the Ninian field in the North Sea, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the year ended December 31, 2022 were $12,863 million compared with $7,420 million for the year ended December 31, 2021.

Net earnings for the fourth quarter of 2022 were $1,520 million compared with $2,534 million for the fourth quarter of 2021 and $2,814 million for the third quarter of 2022. Net earnings for the fourth quarter of 2022 included non-operating items, net of tax, of $674 million compared with $92 million for the fourth quarter of 2021 and $679 million for the third quarter of 2022 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of realized foreign exchange on the repayment of US dollar debt securities, the gain from investments, a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the fourth quarter of 2022 were $2,194 million compared with $2,626 million for the fourth quarter of 2021 and $3,493 million for the third quarter of 2022.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 3 Three months and year ended December 31, 2022

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The increase in net earnings and adjusted net earnings from operations for the year ended December 31, 2022 from the year ended December 31, 2021 primarily reflected:

▪ higher crude oil and NGLs netbacks <sup>(1)</sup> and crude oil and NGLs sales volumes in the North America segment;

▪ higher natural gas netbacks and natural gas sales volumes in the Exploration and Production segments; and

▪ higher realized SCO sales price <sup>(1)</sup> in the Oil Sands Mining and Upgrading segment;

partially offset by:

▪ lower SCO sales volumes in the Oil Sands Mining and Upgrading segment.

The decrease in net earnings and adjusted net earnings from operations for the fourth quarter of 2022 from the fourth quarter of 2021 primarily reflected:

▪ lower crude oil and NGLs netbacks in the North America segment; and

▪ lower SCO sales volumes in the Oil Sands Mining and Upgrading segment;

partially offset by:

▪ higher natural gas netbacks and natural gas sales volumes in the Exploration and Production segments.

The decrease in net earnings and adjusted net earnings from operations for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected:

▪ lower crude oil and NGLs netbacks in the North America segment;

▪ lower natural gas netbacks in the Exploration and Production segments; and

▪ lower realized SCO sales price and sales volumes in the Oil Sands Mining and Upgrading segment;

partially offset by:

▪ higher crude oil and NGLs sales volumes in the Exploration and Production segments.

The impacts of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the gain on acquisitions, income from North West Redwater Partnership ("NWRP"), and the gain from investments, also contributed to the movements in net earnings. These items are discussed in detail in the relevant sections of this MD&A.

Prevailing regulatory and economic conditions in 2022 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. 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. 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, net of deferred tax recoveries of $969 million.

**Cash Flows from Operating Activities and Adjusted Funds Flow**

Cash flows from operating activities for the year ended December 31, 2022 were $19,391 million compared with $14,478 million for the year ended December 31, 2021. Cash flows from operating activities for the fourth quarter of 2022 were $4,544 million compared with $4,712 million for the fourth quarter of 2021 and $6,098 million for the third quarter of 2022. The fluctuations in cash flows from operating activities from the comparable periods were primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.

Adjusted funds flow for the year ended December 31, 2022 was $19,791 million compared with $13,733 million for the year ended December 31, 2021. Adjusted funds flow for the fourth quarter of 2022 was $4,176 million compared with $4,338 million for the fourth quarter of 2021 and $5,208 million for the third quarter of 2022. The fluctuations in adjusted funds flow from the comparable periods were primarily due to the factors noted above related to the fluctuations 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.

(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 4 Three months and year ended December 31, 2022

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**Production Volumes**

Crude oil and NGLs production before royalties for the fourth quarter of 2022 of 942,258 bbl/d decreased 6% from 1,004,425 bbl/d for the fourth quarter of 2021 and decreased 4% from 983,678 bbl/d for the third quarter of 2022. Natural gas production before royalties for the fourth quarter of 2022 increased 14% to 2,115 MMcf/d from 1,857 MMcf/d for the fourth quarter of 2021 and was comparable with 2,132 MMcf/d for the third quarter of 2022. Total production before royalties for the fourth quarter of 2022 of 1,294,679 BOE/d was comparable with 1,313,900 BOE/d for the fourth quarter of 2021 and decreased 3% from 1,338,940 BOE/d for the third quarter of 2022. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.

**Product Prices**

In the Company's Exploration and Production segments, realized crude oil and NGLs prices <sup>(1)</sup> averaged $69.34 per bbl for the fourth quarter of 2022, a decrease of 5% compared with $72.81 per bbl for the fourth quarter of 2021, and a decrease of 18% from $84.91 per bbl for the third quarter of 2022. The realized natural gas price increased 19% to average $6.39 per Mcf for the fourth quarter of 2022, from $5.35 per Mcf for the fourth quarter of 2021, and decreased 3% from $6.57 per Mcf for the third quarter of 2022. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price increased 17% to average $103.79 per bbl for the fourth quarter of 2022 from $88.48 per bbl for the fourth quarter of 2021, and decreased 14% from $120.91 per bbl for the third quarter of 2022. 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, crude oil and NGLs production expense <sup>(2)</sup> averaged $20.37 per bbl for the fourth quarter of 2022, an increase of 30% from $15.70 per bbl for the fourth quarter of 2021, and an increase of 21% from $16.86 per bbl for the third quarter of 2022. Natural gas production expense <sup>(2)</sup> averaged $1.25 per Mcf for the fourth quarter of 2022, an increase of 12% from $1.12 per Mcf for the fourth quarter of 2021, and an increase of 8% from $1.16 for the third quarter of 2022. In the Oil Sands Mining and Upgrading segment, production expense <sup>(2)</sup> averaged $25.48 per bbl for the fourth quarter of 2022, an increase of 30% from $19.55 per bbl for the fourth quarter of 2021, and an increase of 14% from $22.35 per bbl for the third quarter of 2022. Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production Expense – Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.

(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(2) Calculated as respective production expense divided by respective sales volumes.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 5 Three months and year ended December 31, 2022

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**SUMMARY OF QUARTERLY FINANCIAL RESULTS**

The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:

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| | | | | |
|:---|:---|:---|:---|:---|
| ($ millions, except per common share amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Jun 30<br>2022 | Mar 31<br>2022 |
| Product sales <sup>(1)</sup> | $**11012** | $12574 | $13812 | $12132 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Crude oil and NGLs | $**9508** | $11001 | $11727 | $10773 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Natural gas | $**1287** | $1342 | $1605 | $1002 |
| Net earnings | $**1520** | $2814 | $3502 | $3101 |
| Net earnings per common share |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;– basic | $**1.37** | $2.52 | $3.04 | $2.66 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;– diluted | $**1.36** | $2.49 | $3.00 | $2.63 |
| ($ millions, except per common share amounts) | Dec 31<br>2021 | Sep 30<br>2021 | Jun 30<br>2021 | Mar 31<br>2021 |
| Product sales <sup>(1)</sup> | $10190 | $8521 | $7124 | $7019 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Crude oil and NGLs | $8979 | $7607 | $6382 | $6288 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Natural gas | $958 | $694 | $509 | $555 |
| Net earnings | $2534 | $2202 | $1551 | $1377 |
| Net earnings per common share |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;– basic | $2.16 | $1.87 | $1.31 | $1.16 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;– diluted | $2.14 | $1.86 | $1.30 | $1.16 |

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*(1) Further details related to product sales for the three months ended December 31, 2022 and 2021 are disclosed in note 18 to the financial statements.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 6 Three months and year ended December 31, 2022

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Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:

▪ **Crude oil pricing** – Fluctuating 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 COVID-19 and in connection with governmental responses to COVID-19 and the impact of the Russian invasion of Ukraine, on worldwide benchmark pricing; the impact of shale oil production in North America; the impact of the Western Canadian Select ("WCS") Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America; and the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the International segments.

▪ **Natural gas pricing** – The impact of 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 North America and the International segments, natural decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and the impact of shut-in production due to lower demand during COVID-19. 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 North America and the International segments, natural decline rates, the temporary shutdown and subsequent reinstatement of the Pine River Gas Plant during 2021, and the impact and timing of acquisitions.

▪ **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 and energy costs, inflationary cost pressures, cost optimizations across all segments, the impact and timing of acquisitions, 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 including the impact and timing of acquisitions and dispositions, 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, and a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea.

▪ **Share-based compensation** – Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability.

▪ **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 Petroleum Revenue Tax ("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. Fluctuations in 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 on acquisitions, gain from investments and income from NWRP** – Fluctuations due to the recognition of gains on acquisitions, gain from the investments in PrairieSky Royalty Ltd. and Inter Pipeline Ltd. shares, and the distribution from NWRP in the second quarter of 2021.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 7 Three months and year ended December 31, 2022

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**BUSINESS ENVIRONMENT**

Global benchmark crude oil prices increased significantly in the first half of 2022, primarily in response to the impact of the Russian invasion of Ukraine and the OPEC+ decision to adhere to previously agreed upon production cut agreements, together with the improvement of global economic conditions and outlook due to the lessening of COVID-19 restrictions. In the second half of 2022, global benchmark crude oil prices decreased from levels in the first half of 2022 due to demand concerns related to the temporary reinstatement of COVID-19 restrictions in China, the impact of rising interest rates and concerns of a global recession.

**Liquidity**

As at December 31, 2022, the Company had undrawn revolving bank credit facilities of $5,520 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,931 million in liquidity <sup>(1)</sup>. 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**

Safe, reliable, effective and efficient operations continue to be a focus for the Company. On November 30, 2022, the Company announced its 2023 base capital budget <sup>(2)</sup> targeted at approximately $4,190 million. The budget also includes incremental strategic growth capital of approximately $1,020 million that targets to add additional production and capacity growth beyond 2023 in the Company's Exploration and Production segments, and long life low decline thermal in situ and Oil Sands Mining and Upgrading assets. Production for 2023 is targeted between 1,330,000 BOE/d and 1,374,000 BOE/d. 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 2023 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

**Risks and Uncertainties**

COVID-19, including variants of concern, continues to have the potential to further 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, any of which may require the Company to temporarily reduce or shut down its operations depending on their extent and severity. The global economy, including Canada, is experiencing higher and more persistent inflation, in part due to the Russian invasion of Ukraine and ongoing supply constraints due to the impacts of COVID-19. As a result of these conditions, the Company has experienced and may continue to experience higher than normal fluctuations in commodity prices, and may experience inflationary pressures on operating and capital expenditures.

**Benchmark Commodity Prices**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| <br>(Average for the period) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| WTI benchmark price (US$/bbl) | $**82.62** | $91.64 | $77.17 | $**94.23** | $67.96 |
| Dated Brent benchmark price (US$/bbl) | $**88.15** | $99.34 | $79.55 | $**99.80** | $70.49 |
| WCS Heavy Differential from WTI (US$/bbl) | $**25.65** | $19.87 | $14.65 | $**18.26** | $13.04 |
| SCO price (US$/bbl) | $**86.78** | $100.51 | $75.39 | $**98.66** | $66.36 |
| Condensate benchmark price (US$/bbl) | $**83.33** | $87.15 | $79.10 | $**93.69** | $68.24 |
| Condensate Differential from WTI (US$/bbl) | $**(0.71)** | $4.49 | $(1.93) | $**0.54** | $(0.28) |
| NYMEX benchmark price (US$/MMBtu) | $**6.27** | $8.18 | $5.83 | $**6.64** | $3.85 |
| AECO benchmark price (C$/GJ) | $**5.29** | $5.51 | $4.67 | $**5.28** | $3.38 |
| US/Canadian dollar average exchange rate (US$) | $**0.7366** | $0.7660 | $0.7937 | $**0.7686** | $0.7979 |

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(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 Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 8 Three months and year ended December 31, 2022

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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 the volatility of 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 the North America segment are typically based on WTI benchmark pricing. WTI averaged US$94.23 per bbl for the year ended December 31, 2022, an increase of 39% from US$67.96 per bbl for the year ended December 31, 2021. WTI averaged US$82.62 per bbl for the fourth quarter of 2022, an increase of 7% from US$77.17 per bbl for the fourth quarter of 2021, and a decrease of 10% from US$91.64 per bbl for the third quarter of 2022.

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$99.80 per bbl for the year ended December 31, 2022, an increase of 42% from US$70.49 per bbl for the year ended December 31, 2021. Brent averaged US$88.15 per bbl for the fourth quarter of 2022, an increase of 11% from US$79.55 per bbl for the fourth quarter of 2021, and a decrease of 11% from US$99.34 per bbl for the third quarter of 2022.

The increase in WTI and Brent pricing for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected the impact of the Russian invasion of Ukraine, the OPEC+ decision to adhere to the previously agreed upon production cut agreements, and an increase in global demand for crude oil due to improved economic conditions as a result of the lessening of earlier COVID-19 restrictions. The decrease in WTI and Brent pricing for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected demand concerns related to temporary reinstatement of COVID-19 restrictions in China, rising interest rates and concerns of a global recession.

The WCS Heavy Differential averaged US$18.26 per bbl for the year ended December 31, 2022, compared with US$13.04 per bbl for the year ended December 31, 2021. The WCS Heavy Differential averaged US$25.65 per bbl for the fourth quarter of 2022, compared with US$14.65 per bbl for the fourth quarter of 2021, and US$19.87 per bbl for the third quarter of 2022. The widening of the WCS Heavy Differential for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected weakening US Gulf Coast pricing due to increased sour supply from the US Strategic Petroleum Reserve and lower Russian pricing as a result of the Ukraine invasion. The widening of the WCS Heavy Differential for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected lower seasonal demand, unplanned refinery maintenance in the US Midwest and lower fuel oil pricing in the US Gulf Coast.

The SCO price averaged US$98.66 per bbl for the year ended December 31, 2022, an increase of 49% from US$66.36 per bbl for the year ended December 31, 2021. The SCO price averaged US$86.78 per bbl for the fourth quarter of 2022, an increase of 15% from US$75.39 per bbl for the fourth quarter of 2021, and a decrease of 14% from US$100.51 per bbl for the third quarter of 2022. The increase in SCO pricing for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected the increase in WTI benchmark pricing. The decrease in SCO pricing for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected the decrease in WTI benchmark pricing.

NYMEX natural gas prices averaged US$6.64 per MMBtu for the year ended December 31, 2022, an increase of 72% from US$3.85 per MMBtu for the year ended December 31, 2021. NYMEX natural gas prices averaged US$6.27 per MMBtu for the fourth quarter of 2022, an increase of 8% from US$5.83 per MMBtu for the fourth quarter of 2021, and a decrease of 23% from US$8.18 per MMBtu for the third quarter of 2022. The increase in NYMEX natural gas prices for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected increased global commodity prices due to lower European inventories and the Russian invasion of Ukraine. The decrease in NYMEX natural gas prices for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected lower than expected demand due to the impact of warmer seasonal weather conditions and strong production volumes, combined with further delays in the restart of the Freeport LNG facility.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 9 Three months and year ended December 31, 2022

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AECO natural gas prices averaged $5.28 per GJ for the year ended December 31, 2022, an increase of 56% from $3.38 per GJ for the year ended December 31, 2021. AECO natural gas prices averaged $5.29 per GJ for the fourth quarter of 2022, an increase of 13% from $4.67 per GJ for the fourth quarter of 2021, and a decrease of 4% from $5.51 per GJ for the third quarter of 2022. The increase in AECO natural gas prices for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected lower storage levels and increased NYMEX benchmark pricing. The decrease in AECO natural gas prices for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected increased production levels and decreased NYMEX benchmark pricing.

**DAILY PRODUCTION, before royalties**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Crude oil and NGLs** (bbl/d) |  |  |  |  |  |
| North America – Exploration and Production | **486559** | 471632 | 478738 | **479971** | 472621 |
| North America – Oil Sands Mining and Upgrading <sup>(1)</sup> | **428784** | 487553 | 493406 | **425945** | 448133 |
| International – Exploration and Production |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North Sea | **14006** | 10855 | 17860 | **12890** | 17633 |
| &nbsp;&nbsp;&nbsp;&nbsp;Offshore Africa | **12909** | 13638 | 14421 | **14343** | 14017 |
| Total International <sup>(2)</sup> | **26915** | 24493 | 32281 | **27233** | 31650 |
| Total Crude oil and NGLs | **942258** | 983678 | 1004425 | **933149** | 952404 |
| **Natural gas** (MMcf/d) <sup>(3)</sup> |  |  |  |  |  |
| North America | **2105** | 2117 | 1841 | **2075** | 1680 |
| International |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North Sea | **3** | 1 | 3 | **2** | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Offshore Africa | **7** | 14 | 13 | **13** | 12 |
| Total International | **10** | 15 | 16 | **15** | 15 |
| Total Natural gas | **2115** | 2132 | 1857 | **2090** | 1695 |
| Total Barrels of oil equivalent (BOE/d) | **1294679** | 1338940 | 1313900 | **1281434** | 1234906 |
| **Product mix** |  |  |  |  |  |
| Light and medium crude oil and NGLs | **11%** | 10% | 10% | **11%** | 10% |
| Pelican Lake heavy crude oil | **4%** | 4% | 4% | **4%** | 5% |
| Primary heavy crude oil | **5%** | 5% | 5% | **5%** | 5% |
| Bitumen (thermal oil) | **20%** | 18% | 20% | **20%** | 21% |
| Synthetic crude oil <sup>(1)</sup> | **33%** | 36% | 38% | **33%** | 36% |
| Natural gas | **27%** | 27% | 23% | **27%** | 23% |
| **Percentage of gross revenue** <sup>(1)</sup> <sup>(4)</sup> |  |  |  |  |  |
| &nbsp;&nbsp;(excluding Midstream and Refining revenue) |  |  |  |  |  |
| Crude oil and NGLs | **87%** | 88% | 90% | **88%** | 91% |
| Natural gas | **13%** | 12% | 10% | **12%** | 9% |

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*(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 costs and excluding risk management activities.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 10 Three months and year ended December 31, 2022

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**DAILY PRODUCTION, net of royalties**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Crude oil and NGLs** (bbl/d) |  |  |  |  |  |
| North America – Exploration and Production | **381546** | 361987 | 403305 | **374089** | 404637 |
| North America – Oil Sands Mining and Upgrading | **372894** | 391165 | 440492 | **351740** | 410385 |
| International – Exploration and Production |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North Sea | **13985** | 10776 | 17825 | **12849** | 17588 |
| &nbsp;&nbsp;&nbsp;&nbsp;Offshore Africa | **11153** | 11965 | 13638 | **12972** | 13354 |
| Total International | **25138** | 22741 | 31463 | **25821** | 30942 |
| Total Crude oil and NGLs | **779578** | 775893 | 875260 | **751650** | 845964 |
| **Natural gas** (MMcf/d) |  |  |  |  |  |
| North America | **1937** | 1920 | 1721 | **1885** | 1593 |
| International |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North Sea | **3** | 1 | 3 | **2** | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Offshore Africa | **6** | 12 | 12 | **11** | 11 |
| Total International | **9** | 13 | 15 | **13** | 14 |
| Total Natural gas | **1946** | 1933 | 1736 | **1898** | 1607 |
| Total Barrels of oil equivalent (BOE/d) | **1103833** | 1098001 | 1164613 | **1068063** | 1113878 |

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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.

Crude oil and NGLs production before royalties for the year ended December 31, 2022 averaged 933,149 bbl/d, comparable with 952,404 bbl/d for the year ended December 31, 2021. Crude oil and NGLs production for the fourth quarter of 2022 averaged 942,258 bbl/d, a decrease of 6% from 1,004,425 bbl/d for the fourth quarter of 2021, and a decrease of 4% from 983,678 bbl/d for the third quarter of 2022. The decrease in crude oil and NGLs production for the fourth quarter of 2022 from the comparable periods primarily reflected an unplanned outage at Horizon in October and the impact of extreme cold weather conditions on the Oil Sands Mining and Upgrading and the North America Exploration and Production segments late in the fourth quarter of 2022.

Annual crude oil and NGLs production for 2022 was slightly below the Company's previously issued production forecast of 943,000 bbl/d. Annual crude oil and NGLs production for 2023 is targeted to average between 969,000 bbl/d and 1,001,000 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 for the year ended December 31, 2022 of 2,090 MMcf/d increased 23% from 1,695 MMcf/d for the year ended December 31, 2021. Natural gas production for the fourth quarter of 2022 of 2,115 MMcf/d increased 14% from 1,857 MMcf/d for the fourth quarter of 2021, and was comparable with 2,132 MMcf/d for the third quarter of 2022. The increase in natural gas production for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected strong drilling results and the acquisition completed in the fourth quarter of 2021, partially offset by natural field declines and the impact of extreme cold weather conditions late in the fourth quarter of 2022.

Annual natural gas production for 2022 was slightly below the Company's previously issued production forecast of 2,112 MMcf/d. Annual natural gas production for 2023 is targeted to average between 2,170 MMcf/d and 2,242 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 11 Three months and year ended December 31, 2022

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**North America – Exploration and Production**

North America crude oil and NGLs production before royalties for the year ended December 31, 2022 averaged 479,971 bbl/d, comparable with 472,621 bbl/d for the year ended December 31, 2021. North America crude oil and NGLs production for the fourth quarter of 2022 of 486,559 bbl/d was comparable with 478,738 bbl/d for the fourth quarter of 2021 and increased 3% from 471,632 bbl/d for the third quarter of 2022. The increase in crude oil and NGLs production for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected higher thermal oil production and added production from the conventional drilling program, partially offset by natural field declines and the impact of extreme cold weather conditions late in the fourth quarter of 2022.

The Company's thermal in situ assets continued to demonstrate long life production before royalties, averaging 253,188 bbl/d for the fourth quarter of 2022, a decrease of 4% from 263,110 bbl/d for the fourth quarter of 2021, and an increase of 4% from 243,393 bbl/d for the third quarter of 2022, primarily reflecting strong production at Jackfish following planned maintenance activities completed during the third quarter of 2022, and partially offset by natural field declines.

Pelican Lake heavy crude oil production before royalties for the fourth quarter of 2022 averaged 48,221 bbl/d, a decrease of 9% from 52,963 bbl/d for the fourth quarter of 2021, and a decrease of 4% from 50,051 bbl/d for the third quarter of 2022, primarily reflecting a temporary injection reduction in the fourth quarter of 2022, together with natural field declines.

Natural gas production before royalties for the year ended December 31, 2022 averaged 2,075 MMcf/d, an increase of 24% from 1,680 MMcf/d for the year ended December 31, 2021. Natural gas production for the fourth quarter of 2022 averaged 2,105 MMcf/d, an increase of 14% from 1,841 MMcf/d for the fourth quarter of 2021, and comparable with 2,117 MMcf/d for the third quarter of 2022. The increase in natural gas production for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected strong drilling results and the acquisition completed in the fourth quarter of 2021, partially offset by natural field declines and the impact of extreme cold weather conditions late in the fourth quarter of 2022.

**North America – Oil Sands Mining and Upgrading**

SCO production before royalties for the year ended December 31, 2022 of 425,945 bbl/d decreased 5% from 448,133 bbl/d for the year ended December 31, 2021. SCO production for the fourth quarter of 2022 of 428,784 bbl/d decreased 13% from 493,406 bbl/d for the fourth quarter of 2021 and decreased 12% from 487,553 bbl/d for the third quarter of 2022. The decrease in SCO production for the year ended December 31, 2022 from the year ended December 31, 2021 primarily reflected the extended turnaround at the Scotford Upgrader ("Scotford") in the first half of 2022, the unplanned outage at Horizon in October, and the impact of extreme cold weather conditions late in the fourth quarter at both mines. The decrease in SCO production for the fourth quarter of 2022 from the comparable periods primarily reflected the unplanned outage at Horizon in October, and the impact of extreme cold weather conditions late in the fourth quarter at both mines.

**International – Exploration and Production**

International crude oil and NGLs production before royalties for the year ended December 31, 2022 averaged 27,233 bbl/d, a decrease of 14% from 31,650 bbl/d for the year ended December 31, 2021. International crude oil and NGLs production for the fourth quarter of 2022 averaged 26,915 bbl/d, a decrease of 17% from 32,281 bbl/d for the fourth quarter of 2021 and an increase of 10% from 24,493 bbl/d for the third quarter of 2022. The decrease in crude oil and NGLs production for the three months and year ended December 31, 2022 from comparable periods in 2021 primarily reflected natural field declines, together with the impact of maintenance activities in the North Sea in 2022. The increase in crude oil and NGLs production for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected the completion of maintenance activities in the North Sea and Offshore Africa in the third quarter of 2022.

**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:

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| | | | |
|:---|:---|:---|:---|
| (bbl) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 |
| International | **390,959** | 1,126,786 | 727,439 |

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Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 12 Three months and year ended December 31, 2022

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**OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Crude oil and NGLs** ($/bbl) <sup>(1)</sup> |  |  |  |  |  |
| Realized price <sup>(2)</sup> | $**69.34** | $84.91 | $72.81 | $**90.64** | $63.71 |
| Transportation <sup>(2)</sup> | **4.11** | 4.10 | 3.93 | **4.13** | 3.86 |
| Realized price, net of transportation <sup>(2)</sup> | **65.23** | 80.81 | 68.88 | **86.51** | 59.85 |
| Royalties <sup>(3)</sup> | **13.56** | 19.48 | 10.67 | **18.91** | 8.59 |
| Production expense <sup>(4)</sup> | **20.37** | 16.86 | 15.70 | **18.17** | 14.71 |
| Netback <sup>(2)</sup> | $**31.30** | $44.47 | $42.51 | $**49.43** | $36.55 |
| **Natural gas** ($/Mcf) <sup>(1)</sup> |  |  |  |  |  |
| Realized price <sup>(5)</sup> | $**6.39** | $6.57 | $5.35 | $**6.55** | $4.07 |
| Transportation <sup>(6)</sup>  | **0.55** | 0.51 | 0.42 | **0.51** | 0.45 |
| Realized price, net of transportation  | **5.84** | 6.06 | 4.93 | **6.04** | 3.62 |
| Royalties <sup>(3)</sup> | **0.51** | 0.61 | 0.35 | **0.61** | 0.22 |
| Production expense <sup>(4)</sup> | **1.25** | 1.16 | 1.12 | **1.22** | 1.18 |
| Netback  | $**4.08** | $4.29 | $3.46 | $**4.21** | $2.22 |
| **Barrels of oil equivalent** ($/BOE) <sup>(1)</sup> |  |  |  |  |  |
| Realized price <sup>(2)</sup> | $**56.83** | $66.04 | $57.72 | $**70.07** | $49.67 |
| Transportation <sup>(2)</sup> | **3.80** | 3.64 | 3.40 | **3.72** | 3.44 |
| Realized price, net of transportation <sup>(2)</sup> | **53.03** | 62.40 | 54.32 | **66.35** | 46.23 |
| Royalties <sup>(3)</sup> | **9.31** | 12.88 | 7.48 | **12.75** | 5.98 |
| Production expense <sup>(4)</sup> | **15.17** | 12.68 | 12.33 | **13.76** | 11.98 |
| Netback <sup>(2)</sup> | $**28.55** | $36.84 | $34.51 | $**39.84** | $28.27 |

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*(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.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 13 Three months and year ended December 31, 2022

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**REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Crude oil and NGLs** ($/bbl) <sup>(1)</sup> |  |  |  |  |  |
| North America <sup>(2)</sup>  | $**65.79** | $83.62 | $71.57 | $**88.43** | $62.10 |
| International average <sup>(3)</sup> | $**118.44** | $120.09 | $95.23 | $**128.41** | $87.04 |
| &nbsp;&nbsp;North Sea <sup>(3)</sup> | $**118.91** | $123.18 | $100.45 | $**129.04** | $87.98 |
| &nbsp;&nbsp;Offshore Africa <sup>(3)</sup> | $**117.74** | $119.08 | $75.42 | $**127.85** | $85.71 |
| Crude oil and NGLs average <sup>(2)</sup>  | $**69.34** | $84.91 | $72.81 | $**90.64** | $63.71 |
| **Natural gas** ($/Mcf) <sup>(1) (3)</sup>  |  |  |  |  |  |
| North America | $**6.36** | $6.51 | $5.33 | $**6.51** | $4.05 |
| International average | $**13.70** | $14.83 | $7.77 | $**12.78** | $6.21 |
| &nbsp;&nbsp;North Sea | $**13.51** | $20.88 | $3.20 | $**15.75** | $2.94 |
| &nbsp;&nbsp;Offshore Africa | $**13.80** | $14.27 | $9.00 | $**12.23** | $7.17 |
| Natural gas average | $**6.39** | $6.57 | $5.35 | $**6.55** | $4.07 |
| Average ($/BOE) <sup>(1) (2)</sup>  | $**56.83** | $66.04 | $57.72 | $**70.07** | $49.67 |

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*(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 increased 42% to average $88.43 per bbl for the year ended December 31, 2022 from $62.10 per bbl for the year ended December 31, 2021. North America realized crude oil and NGLs prices decreased 8% to average $65.79 per bbl for the fourth quarter of 2022 from $71.57 per bbl for the fourth quarter of 2021, and decreased 21% from $83.62 per bbl for the third quarter of 2022. The increase for the year ended December 31, 2022 from the year ended December 31, 2021 primarily reflected higher WTI benchmark pricing. The decrease for the fourth quarter of 2022 from the fourth quarter of 2021 primarily reflected the widening of the WCS Heavy Differential. The decrease for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected lower WTI benchmark pricing and the widening of the WCS Heavy Differential. The Company continues to focus on its crude oil blending marketing strategy and in the fourth quarter of 2022 contributed approximately 173,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 61% to average $6.51 per Mcf for the year ended December 31, 2022 from $4.05 per Mcf for the year ended December 31, 2021. North America realized natural gas prices increased 19% to average $6.36 per Mcf for the fourth quarter of 2022 from $5.33 per Mcf for the fourth quarter of 2021, and was comparable with $6.51 per Mcf for the third quarter of 2022. The increase for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected increased AECO benchmark pricing.

Comparisons of the prices received in North America Exploration and Production by product type were as follows:

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| | | | |
|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended |
| (Quarterly average) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 |
| **Wellhead Price** <sup>(1)</sup>  |  |  |  |
| Light and medium crude oil and NGLs ($/bbl) | $**77.08** | $82.26 | $74.41 |
| Pelican Lake heavy crude oil ($/bbl) | $**73.25** | $91.98 | $77.40 |
| Primary heavy crude oil ($/bbl) | $**69.20** | $89.80 | $75.47 |
| Bitumen (thermal oil) ($/bbl) | $**58.13** | $80.74 | $68.45 |
| Natural gas ($/Mcf) | $**6.36** | $6.51 | $5.33 |

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*(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 14 Three months and year ended December 31, 2022

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**International**

International realized crude oil and NGLs prices increased 48% to average $128.41 per bbl for the year ended December 31, 2022 from $87.04 per bbl for the year ended December 31, 2021. International realized crude oil and NGLs prices increased 24% to average $118.44 per bbl for the fourth quarter of 2022 from $95.23 per bbl for the fourth quarter of 2021, and was comparable with $120.09 per bbl for the third quarter of 2022. Realized crude oil and NGLs prices per barrel in any particular period 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 increase in realized crude oil and NGLs prices for the three months and year ended December 31, 2022 from the comparable periods in 2021 reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.

**ROYALTIES – EXPLORATION AND PRODUCTION**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Crude oil and NGLs** ($/bbl) <sup>(1)</sup> |  |  |  |  |  |
| North America | $**14.07** | $19.78 | $11.21 | $**19.64** | $9.06 |
| International average | $**6.56** | $11.24 | $1.01 | $**6.38** | $1.75 |
| &nbsp;&nbsp;North Sea | $**0.18** | $0.86 | $0.19 | $**0.30** | $0.19 |
| &nbsp;&nbsp;Offshore Africa | $**16.02** | $14.61 | $4.10 | $**11.79** | $3.94 |
| Crude oil and NGLs average | $**13.56** | $19.48 | $10.67 | $**18.91** | $8.59 |
| **Natural gas** ($/Mcf) <sup>(1)</sup> |  |  |  |  |  |
| North America | $**0.51** | $0.61 | $0.35 | $**0.61** | $0.22 |
| Offshore Africa | $**0.71** | $1.73 | $0.41 | $**1.50** | $0.33 |
| Natural gas average | $**0.51** | $0.61 | $0.35 | $**0.61** | $0.22 |
| Average ($/BOE) <sup>(1)</sup> | $**9.31** | $12.88 | $7.48 | $**12.75** | $5.98 |

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*(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**

North America crude oil and NGLs and natural gas royalties for the three months and year ended December 31, 2022 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 <sup>(1)</sup> averaged approximately 22% of product sales for the year ended December 31, 2022 compared with 15% of product sales for the year ended December 31, 2021. Crude oil and NGLs royalty rates averaged approximately 21% of product sales for the fourth quarter of 2022 compared with 16% for the fourth quarter of 2021 and 24% for the third quarter of 2022. The increase in royalty rates for the three months and year ended December 31, 2022 from the comparable periods in 2021 was primarily due to higher benchmark prices together with fluctuations in the WCS Heavy Differential. The decrease in royalty rates for the fourth quarter of 2022 from the third quarter of 2022 was primarily due to lower benchmark prices.

Natural gas royalty rates averaged approximately 9% of product sales for the year ended December 31, 2022 compared with 5% of product sales for the year ended December 31, 2021. Natural gas royalty rates averaged approximately 8% of product sales for the fourth quarter of 2022 compared with 7% for the fourth quarter of 2021 and 9% for the third quarter of 2022. The increase in royalty rates for the three months and year ended December 31, 2022 from the comparable periods in 2021 was primarily due to higher benchmark prices.

(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 15 Three months and year ended December 31, 2022

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**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 the year ended December 31, 2022, compared with 5% of product sales for the year ended December 31, 2021. Royalty rates as a percentage of product sales averaged approximately 13% for the fourth quarter of 2022 compared with 5% of product sales for the fourth quarter of 2021 and 12% for the third quarter of 2022. 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** 

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Crude oil and NGLs** ($/bbl) <sup>(1)</sup> |  |  |  |  |  |
| North America | $**16.80** | $15.98 | $13.55 | $**16.25** | $13.12 |
| International average | $**69.70** | $40.86 | $54.91 | $**51.01** | $37.77 |
| &nbsp;&nbsp;North Sea | $**100.30** | $115.41 | $64.96 | $**88.99** | $54.13 |
| &nbsp;&nbsp;Offshore Africa | $**24.30** | $16.64 | $16.75 | $**17.25** | $14.73 |
| Crude oil and NGLs average | $**20.37** | $16.86 | $15.70 | $**18.17** | $14.71 |
| **Natural gas** ($/Mcf) <sup>(1)</sup> |  |  |  |  |  |
| North America | $**1.22** | $1.13 | $1.08 | $**1.19** | $1.15 |
| International average | $**8.07** | $4.99 | $5.51 | $**5.16** | $5.07 |
| &nbsp;&nbsp;North Sea | $**10.38** | $12.67 | $9.19 | $**9.27** | $7.31 |
| &nbsp;&nbsp;Offshore Africa | $**6.98** | $4.27 | $4.52 | $**4.40** | $4.41 |
| Natural gas average | $**1.25** | $1.16 | $1.12 | $**1.22** | $1.18 |
| Average ($/BOE) <sup>(1)</sup> | $**15.17** | $12.68 | $12.33 | $**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.*

**North America**

North America crude oil and NGLs production expense for the year ended December 31, 2022 averaged $16.25 per bbl, an increase of 24% from $13.12 per bbl for the year ended December 31, 2021. North America crude oil and NGLs production expense for the fourth quarter of 2022 of $16.80 per bbl increased 24% from $13.55 per bbl for the fourth quarter of 2021 and increased 5% from $15.98 per bbl for the third quarter of 2022. The increase in crude oil and NGLs production expense per bbl for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected higher energy and service costs. The increase in crude oil and NGLs production expense per bbl for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected higher energy costs in the fourth quarter of 2022.

North America natural gas production expense averaged $1.19 per Mcf for the year ended December 31, 2022, an increase of 3% from $1.15 per Mcf for the year ended December 31, 2021. North America natural gas production expense for the fourth quarter of 2022 averaged $1.22 per Mcf, an increase of 13% from $1.08 per Mcf for the fourth quarter of 2021 and an increase of 8% from $1.13 per Mcf for the third quarter of 2022. The increase in natural gas production expense per Mcf for the three months and year ended December 31, 2022 from all comparable periods reported primarily reflected higher energy costs.

**International**

International crude oil and NGLs production expense for the year ended December 31, 2022 averaged $51.01 per bbl, an increase of 35% from $37.77 per bbl for the year ended December 31, 2021. International crude oil and NGLs production expense for the fourth quarter of 2022 of $69.70 per bbl increased 27% from $54.91 per bbl for the fourth quarter of 2021 and increased 71% from $40.86 per bbl for the third quarter of 2022. The increase in crude oil and

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 16 Three months and year ended December 31, 2022

------

NGLs production expense per bbl for the three months and year ended December 31, 2022 from the comparable periods primarily reflected the timing of liftings from various fields that have different cost structures, the impact of lower production volumes, higher energy costs, and fluctuations in foreign exchange.

**DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except per BOE amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| North America | $**949** | $913 | $939 | $**3595** | $3569 |
| North Sea | **1653** | 15 | 33 | **1747** | 160 |
| Offshore Africa | **41** | 39 | 19 | **173** | 142 |
| Depletion, Depreciation and Amortization | $**2643** | $967 | $991 | $**5515** | $3871 |
| Less: Recoverability charge <sup>(1)</sup> | **1620** |  |  | **1620** |  |
| Adjusted depletion, depreciation and <br>&nbsp;&nbsp;&nbsp;&nbsp; amortization <sup>(2)</sup> | $**1023** | $967 | $991 | $**3895** | $3871 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;$/BOE <sup>(3)</sup> | $**12.78** | $12.48 | $13.03 | $**12.45** | $13.49 |

---

*(1)Prevailing regulatory and economic conditions in 2022 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. 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. As a result, 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.*

*(2)This is a non-GAAP measure used to calculate depletion, depreciation and amortization, excluding the impact of non-recurring charges that do not reflect the Company's normal course depletion, depreciation and amortization costs. 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. It is calculated as depletion, depreciation and amortization expense, less the impact of non-recurring charges.* 

*(3)Non-GAAP ratio calculated as adjusted depletion, depreciation and amortization 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 the year ended December 31, 2022 of $12.45 per BOE decreased 8% from $13.49 per BOE for the year ended December 31, 2021. Adjusted depletion, depreciation and amortization expense for the fourth quarter of 2022 of $12.78 per BOE was comparable with $13.03 per BOE for the fourth quarter of 2021 and comparable with $12.48 per BOE for the third quarter of 2022. The decrease in adjusted depletion, depreciation and amortization expense per BOE for the year ended December 31, 2022 from the year ended December 31, 2021 primarily reflected lower depletion rates due to increases to the Company's North America Exploration and Production reserve estimates at December 31, 2021, including the impact of acquisitions completed during the prior year.

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**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except per BOE amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| North America | $**51** | $50 | $25 | $**171** | $101 |
| North Sea | **10** | 10 | 5 | **33** | 21 |
| Offshore Africa | **2** | 2 | 2 | **7** | 6 |
| Asset Retirement Obligation Accretion | $**63** | $62 | $32 | $**211** | $128 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;$/BOE <sup>(1)</sup> | $**0.78** | $0.80 | $0.42 | $**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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 17 Three months and year ended December 31, 2022

------

Asset retirement obligation accretion expense for the year ended December 31, 2022 of $0.67 per BOE increased 52% from $0.44 per BOE for the year ended December 31, 2021. Asset retirement obligation accretion expense for the fourth quarter of 2022 of $0.78 per BOE increased 86% from $0.42 per BOE for the fourth quarter of 2021 and decreased 3% from $0.80 per BOE for the third quarter of 2022. The increase in asset retirement obligation accretion expense per BOE for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected the cost estimate and discount rate revisions made to the asset retirement obligation in the fourth quarter of 2021 and the second quarter of 2022. The decrease in asset retirement obligation accretion expense per BOE for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected fluctuating sales volumes from different underlying operations.

**OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING** 

The Company continues to focus on safe, reliable and efficient operations and leveraging its technical expertise across the Horizon and AOSP sites. SCO production averaged 428,784 bbl/d in the fourth quarter of 2022, reflecting an unplanned outage at Horizon in October and the impact of extreme cold weather conditions late in the fourth quarter of 2022 at both mines.

The Company incurred production expense of $1,017 million for the fourth quarter of 2022, an increase of 17% from $871 million for the fourth quarter of 2021, and comparable with $1,005 million for the third quarter of 2022. The increase from the fourth quarter of 2021 primarily reflected increased energy and maintenance services costs.

**REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($/bbl) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Realized SCO sales price <sup>(1)</sup> | $**103.79** | $120.91 | $88.48 | $**117.69** | $77.95 |
| Bitumen value for royalty purposes <sup>(2)</sup> | $**58.24** | $82.19 | $65.80 | $**83.07** | $58.39 |
| Bitumen royalties <sup>(3)</sup> | $**14.48** | $24.87 | $9.16 | $**20.71** | $6.62 |
| Transportation <sup>(1)</sup> | $**1.80** | $1.55 | $1.33 | $**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 $117.69 per bbl for the year ended December 31, 2022, an increase of 51% from $77.95 per bbl for the year ended December 31, 2021. The realized SCO sales price averaged $103.79 per bbl for the fourth quarter of 2022, an increase of 17% from $88.48 per bbl for the fourth quarter of 2021 and a decrease of 14% from $120.91 per bbl for the third quarter of 2022. The increase in the realized SCO sales price for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected the increase in WTI benchmark pricing. The decrease for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected the decrease in WTI benchmark pricing.

The increase in bitumen royalties per bbl for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected the impact of Horizon reaching full payout in the second quarter of 2022 and higher sliding scale royalty rates. The decrease for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected the impact of lower prevailing bitumen pricing.

Transportation expense averaged $1.71 per bbl for the year ended December 31, 2022, an increase of 41% from $1.21 per bbl for the year ended December 31, 2021. Transportation expense averaged $1.80 per bbl for the fourth quarter of 2022, an increase of 35% from $1.33 per bbl for the fourth quarter of 2021 and an increase of 16% from $1.55 per bbl for the third quarter of 2022. The increase in transportation expense per bbl for the three months and year ended December 31, 2022 from the comparable periods primarily reflected the impact of higher pipeline tolls, partially offset by lower sales volumes.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 18 Three months and year ended December 31, 2022

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**PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING**

The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 18 to the financial statements.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Production expense, excluding natural gas costs | $**933** | $935 | $796 | $**3743** | $3176 |
| Natural gas costs | **84** | 70 | 75 | **333** | 238 |
| Production expense | $**1017** | $1005 | $871 | $**4076** | $3414 |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($/bbl)  | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Production expense, excluding natural gas costs <sup>(1)</sup> | $**23.37** | $20.77 | $17.86 | $**23.91** | $19.45 |
| Natural gas costs <sup>(2)</sup> | **2.11** | 1.58 | 1.69 | **2.13** | 1.46 |
| Production expense <sup>(3)</sup> | $**25.48** | $22.35 | $19.55 | $**26.04** | $20.91 |
| &nbsp;&nbsp;&nbsp;&nbsp;Sales volumes (bbl/d) | **433731** | 489146 | 483972 | **428820** | 447230 |

---

*(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 the year ended December 31, 2022 of $26.04 per bbl increased 25% from $20.91 per bbl for the year ended December 31, 2021. Production expense for the fourth quarter of 2022 averaged $25.48 per bbl, an increase of 30% from $19.55 per bbl for the fourth quarter of 2021 and an increase of 14% from $22.35 per bbl for the third quarter of 2022. The increase in production expense per bbl for the three months and year ended December 31, 2022 from the comparable periods in 2021 primarily reflected increased energy and maintenance services costs, together with lower production volumes. The increase in production expense per bbl for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected lower production volumes in the fourth quarter of 2022.

**DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except per bbl amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Depletion, depreciation and amortization | $**481** | $484 | $478 | $**1822** | $1838 |
| &nbsp;&nbsp;&nbsp;&nbsp;$/bbl <sup>(1)</sup> | $**12.07** | $10.75 | $10.73 | $**11.64** | $11.26 |

---

*(1) Calculated as depletion, depreciation and amortization divided by sales volumes.*

Depletion, depreciation and amortization expense for the year ended December 31, 2022 of $11.64 per bbl increased 3% from $11.26 per bbl for the year ended December 31, 2021. Depletion, depreciation and amortization expense for the fourth quarter of 2022 of $12.07 per bbl increased 12% from $10.73 per bbl for the fourth quarter of 2021, and increased 12% from $10.75 per bbl for the third quarter of 2022. The increase in depletion, depreciation and amortization expense on a per barrel basis for the three months and year ended December 31, 2022 from the comparable periods primarily reflected the impact of lower production volumes during the fourth quarter of 2022.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 19 Three months and year ended December 31, 2022

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**ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except per bbl amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Asset retirement obligation accretion | $**19** | $20 | $14 | $**70** | $57 |
| &nbsp;&nbsp;&nbsp;&nbsp;$/bbl <sup>(1)</sup> | $**0.49** | $0.43 | $0.32 | $**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 the year ended December 31, 2022 of $0.45 per bbl increased 29% from $0.35 per bbl for the year ended December 31, 2021. Asset retirement obligation accretion expense for the fourth quarter of 2022 of $0.49 per bbl increased 53% from $0.32 per bbl for the fourth quarter of 2021, and increased 14% from $0.43 per bbl for the third quarter of 2022. The increase in asset retirement obligation accretion expense on a per barrel basis from comparable periods in 2021 primarily reflected the impact of cost estimate and discount rate revisions made to the asset retirement obligation during the second quarter of 2022. The increase in asset retirement obligation accretion expense on a per barrel basis for the fourth quarter of 2022 from the third quarter of 2022 primarily reflected the impact of lower production volumes during the fourth quarter of 2022.

**MIDSTREAM AND REFINING**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Product sales |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Midstream activities | $**21** | $21 | $17 | $**80** | $78 |
| &nbsp;&nbsp;&nbsp;&nbsp;NWRP, refined product sales and other | **205** | 134 | 200 | **906** | 681 |
| Segmented revenue | **226** | 155 | 217 | **986** | 759 |
| Less: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;NWRP, refining toll | **57** | 66 | 37 | **247** | 213 |
| &nbsp;&nbsp;&nbsp;&nbsp;Midstream activities | **6** | 6 | 5 | **24** | 21 |
| Production expense | **63** | 72 | 42 | **271** | 234 |
| NWRP, transportation and feedstock costs | **155** | 113 | 165 | **691** | 550 |
| Depreciation | **5** | 3 | 4 | **16** | 15 |
| Income from NWRP | **—** |  |  | **—** | (400) |
| Segmented earnings (loss) | $**3** | $(33) | $6 | $**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.

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. For the fourth quarter of 2022, production of ultra-low sulphur diesel and other refined products averaged 54,593 BOE/d (13,648 BOE/d to the Company), (three months ended December 31, 2021 – 71,433 BOE/d; 17,858 BOE/d to the Company), reflecting the completion of turnaround activities during the quarter.

During the third quarter of 2022, NWRP extended its $3,000 million syndicated credit facility and increased it to $3,175 million. The revolving portion of the credit facility was increased to $2,175 million, with $118 million maturing in June 2023, and $2,057 million maturing in June 2025. The $1,000 million non-revolving portion of the credit facility was extended, with $60 million maturing in June 2023, and $940 million maturing in June 2025. During the third quarter of 2022, NWRP also entered into a $150 million facility to support letters of credit. As at December 31, 2022, NWRP had borrowings of $2,318 million under the syndicated credit facility (December 31, 2021 – $1,981 million).

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 20 Three months and year ended December 31, 2022

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As at December 31, 2022, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $551 million (December 31, 2021 – $562 million). For the three months ended December 31, 2022, the Company's recovery of its share of unrecognized equity losses was $37 million (year ended December 31, 2022 – recovery of unrecognized equity losses of $11 million; three months ended December 31, 2021 – unrecognized equity loss of $12 million; year ended December 31, 2021 – unrecognized equity loss of $9 million and partnership distributions of $400 million).

**ADMINISTRATION EXPENSE**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Expense ($ millions) | $**108** | $94 | $97 | $**415** | $366 |
| &nbsp;&nbsp;&nbsp;&nbsp;$/BOE <sup>(1)</sup> | $**0.90** | $0.76 | $0.81 | $**0.88** | $0.81 |
| Sales volumes (BOE/d) <sup>(2)</sup> | **1303996** | 1331189 | 1310878 | **1285877** | 1233457 |

---

*(1)Calculated as administration expense divided by sales volumes.*

*(2)Total Company sales volumes.* 

Administration expense for the year ended December 31, 2022 of $0.88 per BOE increased 9% from $0.81 per BOE for the year ended December 31, 2021. Administration expense for the fourth quarter of 2022 of $0.90 per BOE increased 11% from $0.81 per BOE for the fourth quarter of 2021 and increased 18% from $0.76 per BOE for the third quarter of 2022. The increase in administration expense per BOE for the three months and year ended December 31, 2022 from the comparable periods was primarily due to higher personnel costs, partially offset by the impact of higher overhead recoveries.

**SHARE-BASED COMPENSATION**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Expense (recovery) | $**319** | $(4) | $191 | $**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 by individual employee performance and the extent to which certain other performance measures are met.

The Company recognized $804 million of share-based compensation expense for the year ended December 31, 2022, 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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 21 Three months and year ended December 31, 2022

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**INTEREST AND OTHER FINANCING EXPENSE** 

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except effective interest rate) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Interest and other financing expense | $**76** | $150 | $171 | $**549** | $711 |
| Interest income and other <sup>(1)</sup> | **93** | 18 | 2 | **121** | 32 |
| Interest on long-term debt and lease liabilities <sup>(1)</sup> | $**169** | $168 | $173 | $**670** | $743 |
| Average current and long-term debt <sup>(2)</sup>  | $**13174** | $13714 | $16084 | $**13986** | $18935 |
| Average lease liabilities <sup>(2)</sup>  | **1508** | 1526 | 1578 | **1531** | 1619 |
| Average long-term debt and lease liabilities <sup>(2)</sup>  | $**14682** | $15240 | $17662 | $**15517** | $20554 |
| Average effective interest rate <sup>(3) (4)</sup> | **4.5%** | 4.3% | 3.9% | **4.3%** | 3.5% |
| Interest and other financing expense per $/BOE <sup>(5)</sup> | $**0.63** | $1.23 | $1.42 | $**1.17** | $1.58 |
| Sales volumes (BOE/d) <sup>(6)</sup> | **1303996** | 1331189 | 1310878 | **1285877** | 1233457 |

---

*(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 period.*

*(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 financial statements, as applicable, as an indication of the Company's performance.*

*(4)Calculated as the total of interest on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance for the respective period. 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 the year ended December 31, 2022 decreased 26% to $1.17 per BOE from $1.58 per BOE for the year ended December 31, 2021. Interest and other financing expense per BOE for the fourth quarter of 2022 decreased 56% to $0.63 per BOE from $1.42 per BOE for the fourth quarter of 2021 and decreased 49% from $1.23 per BOE for the third quarter of 2022. The decrease in interest and other financing expense per BOE for the three months and year ended December 31, 2022 from the comparable periods was primarily due to lower debt levels in 2022 and accrued interest on the deferred PRT recovery.

The Company's average effective interest rate for the three months and year ended December 31, 2022 increased from the comparable periods primarily due to higher prevailing interest rates on floating rate debt held during 2022.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 22 Three months and year ended December 31, 2022

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**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.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Foreign currency contracts | $**3** | $(43) | $(11) | $**(37)** | $1 |
| Natural gas financial instruments <sup>(1)</sup> | **(6)** | (3) | 6 | **13** | 17 |
| Crude oil and NGLs financial instruments <sup>(1)</sup> | **1** | 2 | (1) | **17** | (1) |
| Net realized (gain) loss | **(2)** | (44) | (6) | **(7)** | 17 |
| Foreign currency contracts | **(2)** |  | 16 | **(16)** | 6 |
| Natural gas financial instruments <sup>(1)</sup> | **18** | (44) | (10) | **(10)** | 11 |
| Crude oil and NGLs financial instruments <sup>(1)</sup> | **(1)** | (4) | 2 | **(2)** | 2 |
| Net unrealized loss (gain) | **15** | (48) | 8 | **(28)** | 19 |
| Net loss (gain) | $**13** | $(92) | $2 | $**(35)** | $36 |

---

*(1)Commodity financial instruments were assumed in the acquisition of Storm Resources Ltd. ("Storm") in the fourth quarter of 2021.*

During the year ended December 31, 2022, net realized risk management gains were related to the settlement of foreign currency contracts, partially offset by losses on natural gas financial instruments, and crude oil and NGLs financial instruments. The Company recorded a net unrealized gain of $28 million ($25 million after-tax of $3 million) on its risk management activities for the year ended December 31, 2022, including an unrealized loss of $15 million ($11 million after-tax of $4 million) for the fourth quarter of 2022 (three months ended September 30, 2022 – unrealized gain of $48 million, $37 million after-tax of $11 million; three months ended December 31, 2021 – unrealized loss of $8 million, $10 million after-tax of $2 million; year ended December 31, 2021 – unrealized loss of $19 million, $16 million after-tax of $3 million).

Further details related to outstanding derivative financial instruments as at December 31, 2022 are disclosed in note 16 to the financial statements.

**FOREIGN EXCHANGE**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Net realized loss (gain) | $**18** | $(49) | $(27) | $**(114)** | $78 |
| Net unrealized (gain) loss | **(203)** | 785 | (79) | **852** | (205) |
| Net (gain) loss <sup>(1)</sup> | $**(185)** | $736 | $(106) | $**738** | $(127) |

---

*(1)Amounts are reported net of the hedging effect of cross currency swaps.*

The net realized foreign exchange gain for the year ended December 31, 2022 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling and the settlement of the US$550 million cross currency swap during the second quarter of 2022. The net unrealized foreign exchange loss for the year ended December 31, 2022 was primarily related to the impact of a weaker Canadian dollar with respect to outstanding US dollar debt and the reclassification of the gain on the US$550 million cross currency swap to realized foreign exchange due to its settlement in the second quarter of 2022. The US/Canadian dollar exchange rate as at December 31, 2022 was US$0.7389 (September 30, 2022 – US$0.7300, December 31, 2021 – US$0.7901).

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 23 Three months and year ended December 31, 2022

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**INCOME TAXES** 

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except effective tax rates) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| North America <sup>(1)</sup>  | $**345** | $755 | $691 | $**2789** | $1841 |
| North Sea | **33** | 14 | (3) | **69** | 7 |
| Offshore Africa | **23** | 21 | 3 | **74** | 21 |
| PRT – North Sea | **(5)** | (36) | (12) | **(42)** | (34) |
| Other taxes | **3** | 3 | 4 | **16** | 13 |
| Current income tax | **399** | 757 | 683 | **2906** | 1848 |
| Deferred corporate income tax | **(148)** | 194 | 193 | **302** | 399 |
| Deferred PRT – North Sea | **(441)** |  |  | **(441)** |  |
| Deferred income tax | **(589)** | 194 | 193 | **(139)** | 399 |
| Income tax | $**(190)** | $951 | $876 | $**2767** | $2247 |
| Earnings before taxes | $**1330** | $3765 | $3410 | $**13704** | $9911 |
| Effective tax rate on net earnings <sup>(2)</sup>  | **(14)%** | 25% | 26% | **20%** | 23% |
| Income tax | $**(190)** | $951 | $876 | $**2767** | $2247 |
| Tax effect on non-operating items <sup>(3)</sup> | **980** | (15) |  | **964** | 5 |
| Current PRT - North Sea | **5** | 36 | 12 | **42** | 34 |
| Other taxes | **(3)** | (3) | (4) | **(16)** | (13) |
| Effective tax on adjusted net earnings | $**792** | $969 | $884 | $**3757** | $2273 |
| Adjusted net earnings from operations <sup>(4)</sup> | $**2194** | $3493 | $2626 | $**12863** | $7420 |
| Effective tax on adjusted net earnings | **792** | 969 | 884 | **3757** | 2273 |
| Adjusted net earnings from operations, before taxes | $**2986** | $4462 | $3510 | $**16620** | $9693 |
| Effective tax rate on adjusted net earnings from operations <sup>(5) (6)</sup> | **27%** | 22% | 25% | **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 tax effect of PSUs, unrealized risk management, abandonment expenditure recovery, and the recoverability charge recognized in the fourth quarter of 2022 in adjusted net earnings from operations.*

*(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 the three months and year ended December 31, 2022 and the comparable periods 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 corporate income tax and PRT in the North Sea for the three months and year ended December 31, 2022 and the comparable periods included the impact of carrybacks of PRT losses, including expenditures related to the decommissioning activities at the Company's platforms in the North Sea. Deferred PRT and income taxes for the three months and year ended December 31, 2022 also reflected the impact of the recoverability charge recognized in depletion, depreciation and amortization during the period.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 24 Three months and year ended December 31, 2022

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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.

**NET CAPITAL EXPENDITURES** <sup>(1) (2)</sup> 

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Exploration and Evaluation** |  |  |  |  |  |
| Net expenditures | $**11** | $2 | $2 | $**36** | $12 |
| Net property (dispositions) acquisitions | **(2)** | 1 | (6) | **(3)** | (11) |
| Total Exploration and Evaluation | **9** | 3 | (4) | **33** | 1 |
| **Property, Plant and Equipment** |  |  |  |  |  |
| Net property acquisitions <sup>(3)</sup> | **—** | 1 | 973 | **513** | 1112 |
| Well drilling, completion and equipping | **407** | 410 | 196 | **1545** | 918 |
| Production and related facilities | **351** | 378 | 180 | **1233** | 802 |
| Other  | **15** | 15 | 23 | **59** | 64 |
| Total Property, Plant and Equipment | **773** | 804 | 1372 | **3350** | 2896 |
| Total Exploration and Production | **782** | 807 | 1368 | **3383** | 2897 |
| **Oil Sands Mining and Upgrading** |  |  |  |  |  |
| Project costs | **98** | 77 | 65 | **294** | 236 |
| Sustaining capital | **367** | 223 | 270 | **1171** | 1035 |
| Turnaround costs | **16** | 18 | 23 | **287** | 145 |
| Net property dispositions | **(40)** |  |  | **(40)** |  |
| Other <sup>(4)</sup>  | **1** | 3 | 1 | **7** | 331 |
| Total Oil Sands Mining and Upgrading | **442** | 321 | 359 | **1719** | 1747 |
| **Midstream and Refining** | **2** | 2 | 3 | **9** | 9 |
| **Head office** | **7** | 5 | 7 | **25** | 23 |
| **Abandonments expenditures, net** <sup>(2)</sup> | **84** | 114 | 67 | **335** | 232 |
| Net capital expenditures  | $**1317** | $1249 | $1804 | $**5471** | $4908 |
| **By segment** |  |  |  |  |  |
| North America | $**677** | $736 | $1301 | $**3133** | $2662 |
| North Sea | **48** | 40 | 48 | **126** | 173 |
| Offshore Africa | **57** | 31 | 19 | **124** | 62 |
| Oil Sands Mining and Upgrading  | **442** | 321 | 359 | **1719** | 1747 |
| Midstream and Refining | **2** | 2 | 3 | **9** | 9 |
| Head office | **7** | 5 | 7 | **25** | 23 |
| Abandonments expenditures, net <sup>(2)</sup> | **84** | 114 | 67 | **335** | 232 |
| Net capital expenditures  | $**1317** | $1249 | $1804 | $**5471** | $4908 |

---

*(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. 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 the fourth quarter of 2021.*

*(4)Includes the acquisition of a 5% net carried interest on an existing oil sands lease in the second quarter of 2021.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 25 Three months and year ended December 31, 2022

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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 the year ended December 31, 2022 were $5,471 million compared with $4,908 million for the year ended December 31, 2021. Net capital expenditures for the year ended December 31, 2022 included base capital expenditures <sup>(1)</sup> of $3,956 million and strategic growth capital expenditures <sup>(1)</sup> of $1,045 million, in accordance with the Company's capital budget. The Company also completed strategic acquisitions <sup>(1)</sup> of $470 million during the year ended December 31, 2022. Net capital expenditures were $1,317 million for the fourth quarter of 2022 compared with $1,804 million for the fourth quarter of 2021 and $1,249 million for the third quarter of 2022.

**2023 Capital Budget** 

On November 30, 2022, the Company announced its 2023 base capital budget <sup>(2)</sup> targeted at approximately $4,190 million. The budget also includes incremental strategic growth capital of approximately $1,020 million that targets to add additional production and capacity growth beyond 2023 in the Company's Exploration and Production segments, and long life low decline thermal in situ and Oil Sands Mining and Upgrading assets.

The 2023 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

**Drilling Activity** <sup>(1) (2)</sup>

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| (number of net wells) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Net successful crude oil wells <sup>(3)</sup> | **80** | 98 | 22 | **317** | 149 |
| Net successful natural gas wells | **15** | 14 | 9 | **72** | 49 |
| Dry wells | **—** |  |  | **1** | 1 |
| Total | **95** | 112 | 31 | **390** | 199 |
| Success rate | **100%** | 100% | 100% | **99%** | 99% |

---

*(1)Includes drilling activity for North America and International segments.*

*(2)In addition, during the fourth quarter of 2022, on a net basis, the Company drilled 22 stratigraphic and 1 service well in the Oil Sands Mining and Upgrading segment, 19 service wells in the Company's thermal oil projects and 1 service well in Northwest Alberta. During the year ended December 31, 2022, on a net basis, the Company drilled 373 stratigraphic and 5 service wells in the Oil Sands Mining and Upgrading segment, 18 stratigraphic and 53 service wells in the Company's thermal oil projects, and 3 service wells in Northwest Alberta.* 

*(3)Includes bitumen wells.*

**North America**

During the fourth quarter of 2022, the Company drilled 15 net natural gas wells, 60 net primary heavy crude oil wells, 6 net Pelican Lake heavy crude oil wells, 9 net bitumen (thermal oil) wells and 5 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) 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 Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 26 Three months and year ended December 31, 2022

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**LIQUIDITY AND CAPITAL RESOURCES**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ($ millions, except ratios) | **Dec 31<br>2022** | **Dec 31<br>2022** | Sep 30<br>2022 | Sep 30<br>2022 | Dec 31<br>2021 | Dec 31<br>2021 |
| Adjusted working capital <sup>(1)</sup> | **$** | **(1190)** | $| (606) | $| (480) |
| Long-term debt, net <sup>(2)</sup> | **$** | **10525** | $| 12384 | $| 13950 |
| Shareholders' equity | **$** | **38175** | $| 38139 | $| 36945 |
| Debt to book capitalization <sup>(2)</sup>  | **21.6%** | **21.6%** | 24.5% | 24.5% | 27.4% | 27.4% |
| After-tax return on average capital employed <sup>(3)</sup> | **22.1%** | **22.1%** | 24.0% | 24.0% | 15.6% | 15.6% |

---

*(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, 2022, 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 is dependent on factors discussed in the "Business Environment" section of this MD&A and in the "Risks and Uncertainties" section of the Company's annual MD&A for the year ended December 31, 2021. 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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪ Monitoring cash flows from operating activities, which is the primary source of funds;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪ 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪ 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪ 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪ Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪ Reviewing the Company's borrowing capacity:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ During the second quarter of 2022, the Company repaid and cancelled the $500 million non-revolving portion of the $1,000 million term credit facility, reducing the remaining facility to the $500 million revolving facility maturing February 2023. During the fourth quarter of 2022, the facility was extended from February 2023 to February 2024.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ During the first quarter of 2022, the Company repaid $500 million of the $1,150 million non-revolving term credit facility maturing February 2023. During the second quarter of 2022, the Company repaid the remaining $650 million and the facility was cancelled.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ During the first quarter of 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ 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, LIBOR, SOFR, US base rate or Canadian prime rate.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 27 Three months and year ended December 31, 2022

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**◦** During the fourth quarter of 2022, the Company repaid through market purchases $18 million of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028 (year ended December 31, 2022 - $498 million).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ During the first quarter of 2022, the Company repaid $1,000 million of 3.31% medium-term notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ In July 2021, 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 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ During the fourth quarter of 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ In July 2021, 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 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, 2022, the Company had undrawn revolving bank credit facilities of $5,520 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,931 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit.

During the second quarter of 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, 2022, the Company had no cross currency swap contracts outstanding. As at December 31, 2022, there were no foreign currency contracts designated as cash flow hedges.

Long-term debt, net was $10,525 million as at December 31, 2022, resulting in a debt to book capitalization ratio <sup>(1)</sup> of 21.6% (December 31, 2021 – 27.4%); this ratio was below the 25% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may be below the low end of the targeted range when cash flows from operating activities are greater than current investment activities. 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 as at December 31, 2022 are discussed in note 9 to the 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, 2022, 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 as at December 31, 2022 are discussed in note 16 to the financial statements.

As at December 31, 2022, the maturity dates of long-term debt and other long-term liabilities and related interest payments were as follows:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Less than<br>1 year | 1 to less than<br>2 years | 2 to less than<br>5 years | Thereafter |
| Long-term debt <sup>(1)</sup> | $404 | $1009 | $3757 | $6344 |
| Other long-term liabilities <sup>(2)</sup> | $247 | $156 | $416 | $724 |
| Interest and other financing expense <sup>(3)</sup>  | $584 | $577 | $1410 | $3790 |

---

*(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, $244 million; one to less than two years, $156 million; two to less than five years, $416 million; and thereafter, $724 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, 2022.*

(1) Capital management measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 28 Three months and year ended December 31, 2022

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**Share Capital**

As at December 31, 2022, there were 1,102,636,000 common shares outstanding (December 31, 2021 – 1,168,369,000 common shares) and 31,150,000 stock options outstanding. As at February 28, 2023, the Company had 1,099,741,000 common shares outstanding and 31,902,000 stock options outstanding.

On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share, beginning with the dividend payable on April 5, 2023.

On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share, beginning with the dividend paid on January 5, 2023.

On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share, paid on August 31, 2022.

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, 2022, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up to 101,574,207 common shares, representing 10% of the public float, over a 12-month period commencing March 11, 2022 and ending March 10, 2023.

For the year ended December 31, 2022, the Company purchased 77,338,200 common shares at a weighted average price of $72.03 per common share for a total cost of $5,571 million. Retained earnings were reduced by $4,868 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2022, up to and including February 28, 2023, the Company purchased 6,000,000 common shares at a weighted average price of $77.72 per common share for a total cost of $466 million.

On March 1, 2023, 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.

**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, 2022:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ($ millions) | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter |
| Product transportation and processing <sup>(1)</sup> | $1171 | $1349 | $1168 | $1102 | $1052 | $11095 |
| North West Redwater Partnership service toll <sup>(2)</sup> | $151 | $152 | $151 | $133 | $118 | $4884 |
| Offshore vessels and equipment | $44 | $35 | $— | $— | $— | $— |
| Field equipment and power | $36 | $27 | $24 | $23 | $22 | $215 |
| Other | $23 | $24 | $21 | $16 | $— | $— |

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*(1)Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion.*

*(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 $2,863 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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 29 Three months and year ended December 31, 2022

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**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.

**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 the Company's annual MD&A and audited consolidated financial statements for the year ended December 31, 2021.

**CONTROL ENVIRONMENT**

There have been no changes to internal control over financial reporting during the year ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect the Company's internal control over financial reporting. Due to inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

**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 or 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 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.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 30 Three months and year ended December 31, 2022

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**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. 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.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Net earnings  | $**1520** | $2814 | $2534 | $**10937** | $7664 |
| &nbsp;&nbsp;&nbsp;&nbsp;Share-based compensation, net of tax <sup>(1)</sup> | **309** | (8) | 183 | **780** | 495 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrealized risk management loss (gain), net of tax <sup>(2)</sup> | **11** | (37) | 10 | **(25)** | 16 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrealized foreign exchange (gain) loss, net of tax <sup>(3)</sup> | **(203)** | 785 | (79) | **852** | (205) |
| &nbsp;&nbsp;&nbsp;&nbsp;Realized foreign exchange loss (gain), net of tax <sup>(4)</sup> | **7** |  |  | **(62)** | 118 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gain on acquisitions, net of tax <sup>(5)</sup> | **—** |  |  | **—** | (478) |
| &nbsp;&nbsp;&nbsp;&nbsp;Gain from investments, net of tax <sup>(6)</sup> | **(88)** | (36) | (3) | **(182)** | (132) |
| &nbsp;&nbsp;&nbsp;&nbsp;Recoverability charge, net of tax <sup>(7)</sup> | **651** |  |  | **651** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net of tax <sup>(8)</sup> | **(13)** | (25) | (19) | **(88)** | (58) |
| Non-operating items, net of tax | **674** | 679 | 92 | **1926** | (244) |
| Adjusted net earnings from operations | $**2194** | $3493 | $2626 | $**12863** | $7420 |

---

*(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 the three months ended December 31, 2022 was an expense of $319 million (three months ended September 30, 2022 – $4 million recovery, three months ended December 31, 2021 – $191 million expense; year ended December 31, 2022 – $804 million expense, year ended December 31, 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 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 the three months ended December 31, 2022 was $15 million (three months ended September 30, 2022 – $48 million gain, three months ended December 31, 2021 – $8 million loss; year ended December 31, 2022 – $28 million gain, year ended December 31, 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, and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign exchange losses and gains are the same.*

*(4)During the fourth quarter of 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. During the second quarter of 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 the third quarter of 2021, the Company repaid US$500 million of 3.45% debt securities, originally due November 2021, 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 the third quarter of 2021, the Company completed two acquisitions resulting in a 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 recoverability charge of $1,620 million in depletion, depreciation and amortization at December 31, 2022 relating to the de-booking of reserves at the Ninian field in the North Sea. Prevailing regulatory and economic conditions in 2022 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. 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.*

*(8)Other relates to the impact of government grant income under the provincial well-site rehabilitation programs. Pre-tax other for the three months ended December 31, 2022 was $16 million (three months ended September 30, 2022 – $33 million, three months ended December 31, 2021 – $25 million; year ended December 31, 2022 – $114 million, year ended December 31, 2021 – $75 million).*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 31 Three months and year ended December 31, 2022

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**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.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Cash flows from operating activities | $**4544** | $6098 | $4712 | $**19391** | $14478 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net change in non-cash working capital | **(517)** | (1024) | (420) | **(79)** | (964) |
| &nbsp;&nbsp;&nbsp;&nbsp;Abandonment expenditures, net <sup>(1)</sup> | **84** | 114 | 67 | **335** | 232 |
| &nbsp;&nbsp;&nbsp;&nbsp;Movements in other long-term assets <sup>(2)</sup> | **65** | 20 | (21) | **144** | (13) |
| Adjusted funds flow | $**4176** | $5208 | $4338 | $**19791** | $13733 |

---

*(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 and accrued interest on the deferred PRT recovery.*

**Adjusted Net Earnings from Operations and Adjusted Funds Flow, Per Common 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 15 to the 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 annual capital budget. Abandonment expenditures, net is calculated as abandonment expenditures, as presented in the Company's 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.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Abandonment expenditures | $**100** | $147 | $92 | $**449** | $307 |
| Government grants for abandonment expenditures | **(16)** | (33) | (25) | **(114)** | (75) |
| Abandonment expenditures, net | $**84** | $114 | $67 | $**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" section 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 18 to the financial statements.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 32 Three months and year ended December 31, 2022

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**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 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.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except bbl/d and $/bbl) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Crude oil and NGLs** (bbl/d) |  |  |  |  |  |
| North America | **482931** | 469532 | 490448 | **480691** | 471331 |
| International |  |  |  |  |  |
| &nbsp;&nbsp;North Sea | **20854** | 4229 | 21360 | **13215** | 18942 |
| &nbsp;&nbsp;Offshore Africa | **14059** | 13020 | 5624 | **14866** | 13452 |
| Total International | **34913** | 17249 | 26984 | **28081** | 32394 |
| Total sales volumes | **517844** | 486781 | 517432 | **508772** | 503725 |
| Crude oil and NGLs sales <sup>(1)</sup> | $**4505** | $4813 | $4667 | $**22072** | $15505 |
| Less: Blending costs <sup>(2)</sup> | **1202** | 1010 | 1202 | **5239** | 3792 |
| Realized crude oil and NGLs sales | $**3303** | $3803 | $3465 | $**16833** | $11713 |
| Realized price ($/bbl) | $**69.34** | $84.91 | $72.81 | $**90.64** | $63.71 |

---

*(1)Crude oil and NGLs sales in note 18 to the financial statements.*

*(2)Blending costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.*

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except BOE/d and $/BOE) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Barrels of oil equivalent** (BOE/d) |  |  |  |  |  |
| North America | **833719** | 822257 | 797185 | **826526** | 751330 |
| International |  |  |  |  |  |
| &nbsp;&nbsp;North Sea | **21375** | 4447 | 21940 | **13598** | 19512 |
| &nbsp;&nbsp;Offshore Africa | **15171** | 15339 | 7781 | **16933** | 15385 |
| Total International | **36546** | 19786 | 29721 | **30531** | 34897 |
| Total sales volumes | **870265** | 842043 | 826906 | **857057** | 786227 |
| Barrels of oil equivalent sales <sup>(1)</sup> | $**5751** | $6100 | $5581 | $**27071** | $18025 |
| Less: Blending costs <sup>(2)</sup> | **1202** | 1010 | 1202 | **5239** | 3792 |
| Less: Sulphur income | **(3)** | (25) | (12) | **(88)** | (21) |
| Realized barrels of oil equivalent sales  | $**4552** | $5115 | $4391 | $**21920** | $14254 |
| Realized price ($/BOE) | $**56.83** | $66.04 | $57.72 | $**70.07** | $49.67 |

---

*(1)Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 18 to the financial statements.*

*(2)Blending costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 33 Three months and year ended December 31, 2022

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**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 costs. A reconciliation for Exploration and Production transportation and the calculations for transportation on a per unit basis are presented below.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except $ per unit amounts) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Transportation, blending and feedstock <sup>(1)</sup> | $**1506** | $1292 | $1461 | $**6401** | $4780 |
| Less: Blending costs | **1202** | 1010 | 1202 | **5239** | 3792 |
| Transportation | $**304** | $282 | $259 | $**1162** | $988 |
| Transportation ($/BOE)  | $**3.80** | $3.64 | $3.40 | $**3.72** | $3.44 |
| Amounts attributed to crude oil and NGLs | $**196** | $184 | $187 | $**767** | $710 |
| Transportation ($/bbl)  | $**4.11** | $4.10 | $3.93 | $**4.13** | $3.86 |
| Amounts attributed to natural gas | $**108** | $98 | $72 | $**395** | $278 |
| Transportation ($/Mcf)  | $**0.55** | $0.51 | $0.42 | $**0.51** | $0.45 |

---

*(1)Transportation, blending and feedstock in note 18 to the 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 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.

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended | Year Ended | Year Ended |
| ($ millions, except $/bbl and royalty rates) | **Dec 31<br>2022** | **Dec 31<br>2022** | Sep 30<br>2022 | Sep 30<br>2022 | Dec 31<br>2021 | Dec 31<br>2021 | **Dec 31<br>2022** | **Dec 31<br>2022** | Dec 31<br>2021 | Dec 31<br>2021 |
| Crude oil and NGLs sales <sup>(1)</sup> | **$** | **4124** | $| 4622 | $| 4431 | **$** | **20755** | $| 14478 |
| Less: Blending costs <sup>(2)</sup> | **1202** | **1202** | 1010 | 1010 | 1202 | 1202 | **5239** | **5239** | 3792 | 3792 |
| Realized crude oil and NGLs sales | **$** | **2922** | $| 3612 | $| 3229 | **$** | **15516** | $| 10686 |
| Realized crude oil and NGLs prices ($/bbl) | **$** | **65.79** | $| 83.62 | $| 71.57 | **$** | **88.43** | $| 62.10 |
| Crude oil and NGLs royalties <sup>(3)</sup> | **$** | **625** | $| 854 | $| 506 | **$** | **3445** | $| 1558 |
| Crude oil and NGLs royalty rates | **21%** | **21%** | 24% | 24% | 16% | 16% | **22%** | **22%** | 15% | 15% |

---

*(1)Crude oil and NGLs sales in note 18 to the financial statements.*

*(2)Blending 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 18 to the financial statements.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 34 Three months and year ended December 31, 2022

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**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.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions, except for bbl/d and $/bbl) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| SCO sales volumes (bbl/d) | **433731** | 489146 | 483972 | **428820** | 447230 |
| Crude oil and NGLs sales <sup>(1)</sup> | $**4935** | $6056 | $4408 | $**20804** | $14033 |
| Less: Blending and feedstock costs | **795** | 615 | 468 | **2384** | 1309 |
| Realized SCO sales | $**4140** | $5441 | $3940 | $**18420** | $12724 |
| Realized SCO sales price ($/bbl) | $**103.79** | $120.91 | $88.48 | $**117.69** | $77.95 |
| Transportation, blending and feedstock <sup>(2)</sup> | $**867** | $684 | $527 | $**2652** | $1505 |
| Less: Blending and feedstock costs | **795** | 615 | 468 | **2384** | 1309 |
| Transportation | $**72** | $69 | $59 | $**268** | $196 |
| Transportation ($/bbl) | $**1.80** | $1.55 | $1.33 | $**1.71** | $1.21 |

---

*(1)Crude oil and NGLs sales in note 18 to the financial statements.*

*(2)Transportation, blending and feedstock in note 18 to the financial statements.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 35 Three months and year ended December 31, 2022

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**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 consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, the proceeds from investments, the repayment of NWRP subordinated debt advances, and abandonment expenditures including the impact of government grant income under the provincial well-site rehabilitation programs. 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.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| ($ millions) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Cash flows used in investing activities | $**1262** | $1129 | $1615 | $**4987** | $3703 |
| Net change in non-cash working capital | **(29)** | 6 | (61) | **149** | 107 |
| Proceeds from investment | **—** |  |  | **—** | 128 |
| Repayment of NWRP subordinated debt advances | **—** |  |  | **—** | 555 |
| Capital expenditures | **1233** | 1135 | 1554 | **5136** | 4493 |
| Abandonment expenditures, net <sup>(1)</sup> | **84** | 114 | 67 | **335** | 232 |
| Settlement of long-term debt acquired <sup>(2)</sup> | **—** |  | 183 | **—** | 183 |
| Net capital expenditures <sup>(3)</sup> | $**1317** | $1249 | $1804 | $**5471** | $4908 |

---

*(1)Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the "Abandonment Expenditures, net" section above.*

*(2)Relates to the settlement of long-term debt assumed in the acquisition of Storm in the fourth quarter of 2021.*

*(3)For the year ended December 31, 2022, includes base capital expenditures of $3,956 million, net property, plant and equipment acquisitions and net exploration and evaluation asset dispositions of $470 million, and strategic growth capital expenditures of $1,045 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.* 

**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) | **Dec 31<br>2022** | Sep 30<br>2022 | Dec 31<br>2021 |
| Undrawn bank credit facilities | $**5520** | $5520 | $6098 |
| Cash and cash equivalents | **920** | 565 | 744 |
| Investments | **491** | 403 | 309 |
| Liquidity | $**6931** | $6488 | $7151 |

---

**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 14 to the financial statements.

**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 14 to the financial statements.

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 36 Three months and year ended December 31, 2022

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**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.

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ($ millions, except ratios) | **Dec 31<br>2022** | **Dec 31<br>2022** | Sep 30<br>2022 | Sep 30<br>2022 | Dec 31<br>2021 | Dec 31<br>2021 |
| Interest adjusted after-tax return: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Net earnings, 12 months trailing | **$** | **10937** | $| 11951 | $| 7664 |
| &nbsp;&nbsp;&nbsp;Interest and other financing expense, net of tax, 12 months trailing <sup>(1)</sup> | **424** | **424** | 497 | 497 | 547 | 547 |
| Interest adjusted after-tax return | **$** | **11361** | $| 12448 | $| 8211 |
| 12 months average current portion long-term debt <sup>(2)</sup> | **$** | **1359** | $| 1478 | $| 1483 |
| 12 months average long-term debt <sup>(2)</sup> | **11761** | **11761** | 12707 | 12707 | 16769 | 16769 |
| 12 months average common shareholders' equity <sup>(2)</sup> | **38218** | **38218** | 37688 | 37688 | 34458 | 34458 |
| 12 months average capital employed | **$** | **51338** | $| 51873 | $| 52710 |
| After-tax return on average capital employed | **22.1%** | **22.1%** | 24.0% | 24.0% | 15.6% | 15.6% |

---

*(1)The blended tax rate on interest was 23% for each of the periods presented.*

*(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.*

Canadian Natural Resources Limited &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 37 Three months and year ended December 31, 2022

## Exhibit 99.3

![canadiannatural_colora.jpg](canadiannatural_colora.jpg)

**CANADIAN NATURAL RESOURCES LIMITED**

---

| |
|:---|
| **UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS**<br>**FOR THE THREE MONTHS AND YEAR ENDED DECEMBER 31, 2022 AND 2021** |
| **MARCH 1, 2023** |

---

------

**INTERIM CONSOLIDATED FINANCIAL STATEMENTS**

**CONSOLIDATED BALANCE SHEETS**

---

| | | | |
|:---|:---|:---|:---|
| As at | Note | **Dec 31<br>2022** | Dec 31<br>2021 |
| (millions of Canadian dollars, unaudited) | Note | **Dec 31<br>2022** | Dec 31<br>2021 |
| **ASSETS** |  |  |  |
| **Current assets** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Cash and cash equivalents |  | $**920** | $744 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable |  | **3555** | 3111 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Inventory |  | **1815** | 1548 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Prepaids and other |  | **215** | 195 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Investments | 7 | **491** | 309 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Current portion of other long-term assets | 8 | **61** | 35 |
|  |  | **7057** | 5942 |
| **Exploration and evaluation assets** | 4 | **2226** | 2250 |
| **Property, plant and equipment** | 5 | **64859** | 66400 |
| **Lease assets** | 6 | **1447** | 1508 |
| **Other long-term assets** | 8 | **553** | 565 |
|  |  | $**76142** | $76665 |
| **LIABILITIES** |  |  |  |
| **Current liabilities** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts payable |  | $**1341** | $803 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accrued liabilities |  | **4209** | 3064 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Current income taxes payable |  | **1324** | 1607 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Current portion of long-term debt | 9 | **404** | 1000 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Current portion of other long-term liabilities | 610 | **1373** | 948 |
|  |  | **8651** | 7422 |
| **Long-term debt** | 9 | **11041** | 13694 |
| **Other long-term liabilities** | 610 | **8161** | 8384 |
| **Deferred income taxes** |  | **10114** | 10220 |
|  |  | **37967** | 39720 |
| **SHAREHOLDERS' EQUITY** |  |  |  |
| **Share capital** | 12 | **10294** | 10168 |
| **Retained earnings** |  | **27672** | 26778 |
| **Accumulated other comprehensive income (loss)** | 13 | **209** | (1) |
|  |  | **38175** | 36945 |
|  |  | $**76142** | $76665 |

---

*Commitments and contingencies (note 17)*

Approved by the Board of Directors on March 1, 2023.

Canadian Natural Resources Limited 1 Three months and year ended December 31, 2022

------

**CONSOLIDATED STATEMENTS OF EARNINGS**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| (millions of Canadian dollars, except per<br> common share amounts, unaudited) | Note | **Dec 31<br>2022** | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Product sales | 18 | $**11012** | $10190 | $**49530** | $32854 |
| Less: royalties |  | **(1323)** | (977) | **(7232)** | (2797) |
| **Revenue** |  | **9689** | 9213 | **42298** | 30057 |
| **Expenses** |  |  |  |  |  |
| Production |  | **2309** | 1869 | **8712** | 7152 |
| Transportation, blending and feedstock |  | **2601** | 2065 | **9973** | 6604 |
| Depletion, depreciation and amortization | 56 | **3129** | 1473 | **7353** | 5724 |
| Administration |  | **108** | 97 | **415** | 366 |
| Share-based compensation | 10 | **319** | 191 | **804** | 514 |
| Asset retirement obligation accretion | 10 | **82** | 46 | **281** | 185 |
| Interest and other financing expense |  | **76** | 171 | **549** | 711 |
| Risk management activities | 16 | **13** | 2 | **(35)** | 36 |
| Foreign exchange (gain) loss |  | **(185)** | (106) | **738** | (127) |
| Gain on acquisitions |  | **—** |  | **—** | (478) |
| Income from North West Redwater Partnership | 8 | **—** |  | **—** | (400) |
| Gain from investments | 7 | **(93)** | (5) | **(196)** | (141) |
|  |  | **8359** | 5803 | **28594** | 20146 |
| **Earnings before taxes** |  | **1330** | 3410 | **13704** | 9911 |
| Current income tax expense | 11 | **399** | 683 | **2906** | 1848 |
| Deferred income tax (recovery) expense | 11 | **(589)** | 193 | **(139)** | 399 |
| **Net earnings** |  | $**1520** | $2534 | $**10937** | $7664 |
| **Net earnings per common share** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Basic | 15 | $**1.37** | $2.16 | $**9.64** | $6.49 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Diluted | 15 | $**1.36** | $2.14 | $**9.52** | $6.46 |

---

**CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| (millions of Canadian dollars, unaudited) | **Dec 31<br>2022** | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Net earnings** | $**1520** | $2534 | $**10937** | $7664 |
| **Items that may be reclassified subsequently to net earnings** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Net change in derivative financial instruments**<br>**designated as cash flow hedges** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Unrealized (loss) income during the period, net of taxes of<br>$nil (2021 – $1 million) – three months ended; <br>$1 million (2021 – $2 million) – year ended | **—** | (19) | **4** | 15 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Reclassification to net earnings, net of taxes of <br>$nil (2021 – $nil) – three months ended; <br>$1 million (2021 – $1 million) – year ended | **—** | 1 | **(6)** | (7) |
|  | **—** | (18) | **(2)** | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Foreign currency translation adjustment** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Translation of net investment | **(21)** | (20) | **212** | (17) |
| **Other comprehensive (loss) income, net of taxes** | **(21)** | (38) | **210** | (9) |
| **Comprehensive income** | $**1499** | $2496 | $**11147** | $7655 |

---

Canadian Natural Resources Limited 2 Three months and year ended December 31, 2022

------

**CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY**

---

| | | | |
|:---|:---|:---|:---|
| | | Year Ended | Year Ended |
| <br>(millions of Canadian dollars, unaudited) | Note | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Share capital** | 12 |  |  |
| Balance – beginning of year |  | $**10168** | $9606 |
| Issued upon exercise of stock options |  | **442** | 707 |
| Previously recognized liability on stock options exercised for common shares |  | **387** | 139 |
| Purchase of common shares under Normal Course Issuer Bid |  | **(703)** | (284) |
| Balance – end of year |  | **10294** | 10168 |
| **Retained earnings** |  |  |  |
| Balance – beginning of year |  | **26778** | 22766 |
| Net earnings |  | **10937** | 7664 |
| Dividends on common shares | 12 | **(5175)** | (2355) |
| Purchase of common shares under Normal Course Issuer Bid | 12 | **(4868)** | (1297) |
| Balance – end of year |  | **27672** | 26778 |
| **Accumulated other comprehensive income (loss)** | 13 |  |  |
| Balance – beginning of year |  | **(1)** | 8 |
| Other comprehensive income (loss), net of taxes |  | **210** | (9) |
| Balance – end of year |  | **209** | (1) |
| **Shareholders' equity** |  | $**38175** | $36945 |

---

Canadian Natural Resources Limited 3 Three months and year ended December 31, 2022

------

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| (millions of Canadian dollars, unaudited) | Note | **Dec 31<br>2022** | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Operating activities** |  |  |  |  |  |
| Net earnings |  | $**1520** | $2534 | $**10937** | $7664 |
| Non-cash items |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Depletion, depreciation and amortization | 5 | **3129** | 1473 | **7353** | 5724 |
| &nbsp;&nbsp;&nbsp;&nbsp;Share-based compensation |  | **319** | 191 | **804** | 514 |
| &nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligation accretion |  | **82** | 46 | **281** | 185 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrealized risk management loss (gain) |  | **15** | 8 | **(28)** | 19 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrealized foreign exchange (gain) loss |  | **(203)** | (79) | **852** | (205) |
| &nbsp;&nbsp;&nbsp;&nbsp;Gain on acquisitions |  | **—** |  | **—** | (478) |
| &nbsp;&nbsp;&nbsp;&nbsp;Gain from investments | 7 | **(88)** | (3) | **(182)** | (132) |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred income tax (recovery) expense |  | **(589)** | 193 | **(139)** | 399 |
| Realized foreign exchange loss (gain) <sup>(1)</sup>  |  | **7** |  | **(62)** | 118 |
| Proceeds on settlement of cross currency swap | 16 | **—** |  | **89** |  |
| Other |  | **(65)** | 21 | **(144)** | 13 |
| Abandonment expenditures | 10 | **(100)** | (92) | **(449)** | (307) |
| Net change in non-cash working capital |  | **517** | 420 | **79** | 964 |
| Cash flows from operating activities |  | **4544** | 4712 | **19391** | 14478 |
| **Financing activities** |  |  |  |  |  |
| Repayment of bank credit facilities and commercial paper, net | 9 | **—** | (1979) | **(1156)** | (6151) |
| Repayment of medium-term notes | 9 | **(18)** |  | **(1498)** |  |
| Repayment of US dollar debt securities | 9 | **(1356)** |  | **(1356)** | (628) |
| Settlement of long-term debt acquired |  | **—** | (183) | **—** | (183) |
| Proceeds on settlement of cross currency swap | 16 | **—** |  | **69** |  |
| Payment of lease liabilities | 610 | **(83)** | (55) | **(232)** | (209) |
| Issue of common shares on exercise of stock options | 12 | **110** | 360 | **442** | 707 |
| Dividends on common shares |  | **(834)** | (552) | **(4926)** | (2170) |
| Purchase of common shares under Normal Course Issuer Bid | 12 | **(746)** | (838) | **(5571)** | (1581) |
| Cash flows used in financing activities |  | **(2927)** | (3247) | **(14228)** | (10215) |
| **Investing activities** |  |  |  |  |  |
| Net (expenditures) proceeds on exploration and evaluation assets | 418 | **(9)** | 4 | **(33)** | (1) |
| Net expenditures on property, plant and equipment | 518 | **(1224)** | (1558) | **(5103)** | (4492) |
| Proceeds from investment |  | **—** |  | **—** | 128 |
| Repayment of North West Redwater Partnership subordinated debt advances |  | **—** |  | **—** | 555 |
| Net change in non-cash working capital |  | **(29)** | (61) | **149** | 107 |
| Cash flows used in investing activities |  | **(1262)** | (1615) | **(4987)** | (3703) |
| **Increase (decrease) in cash and cash equivalents** | **Increase (decrease) in cash and cash equivalents** | **355** | (150) | **176** | 560 |
| **Cash and cash equivalents – beginning of period** | **Cash and cash equivalents – beginning of period** | **565** | 894 | **744** | 184 |
| **Cash and cash equivalents – end of period** |  | $**920** | $744 | $**920** | $744 |
| **Interest paid on long-term debt, net** |  | $**131** | $122 | $**613** | $672 |
| **Income taxes paid (received), net** |  | $**575** | $32 | $**3057** | $(62) |

---

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

Canadian Natural Resources Limited 4 Three months and year ended December 31, 2022

------

**NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS**

*(tabular amounts in millions of Canadian dollars, unless otherwise stated, unaudited)*

**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 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.

These interim 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"), applicable to the preparation of interim financial statements, including International Accounting Standard ("IAS") 34 "Interim Financial Reporting", following the same accounting policies as the audited consolidated financial statements of the Company as at December 31, 2021, except as disclosed in note 2. These interim consolidated financial statements contain disclosures that are supplemental to the Company's annual audited consolidated financial statements. Certain disclosures normally required to be included in the notes to the annual audited consolidated financial statements have been condensed. These interim consolidated financial statements should be read in conjunction with the Company's audited consolidated financial statements and notes thereto for the year ended December 31, 2021.

**Critical Accounting Estimates and Judgements**

The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of these interim consolidated financial statements, primarily related to unsettled transactions and events as of the date of these interim consolidated financial statements. Accordingly, actual results may differ from estimated amounts, and those differences may be material.

**2. CHANGE IN ACCOUNTING POLICIES**

In May 2020, the IASB issued amendments to IAS 16 "Property, Plant and Equipment" to require proceeds received from selling items produced while the entity is preparing the asset for its intended use to be recognized in net earnings, rather than as a reduction in the cost of the asset. The amendments were adopted January 1, 2022 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. The amendments are effective January 1, 2024 with early adoption permitted. The amendments are required to be adopted retrospectively. The Company is assessing the impact of all amendments on its consolidated financial statements.

Canadian Natural Resources Limited 5 Three months and year ended December 31, 2022

------

**4. EXPLORATION AND EVALUATION ASSETS**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Exploration and Production** | **Exploration and Production** | **Exploration and Production** | **Oil Sands<br>Mining and<br>Upgrading** | **Total** |
| | **North<br>America** | **North<br>Sea** | **Offshore<br>Africa** | | |
| **Cost** | | | | | |
| At December 31, 2021 | $2057 | $— | $91 | $102 | $2250 |
| Additions | **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 | $**2026** | $**—** | $**98** | $**102** | $**2226** |

---

 **5. PROPERTY, PLANT AND EQUIPMENT**

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Exploration and Production** | **Exploration and Production** | **Exploration and Production** | **Oil Sands<br>Mining and<br>Upgrading** | **Midstream and<br>Refining** | **Head<br>Office** | **Total** |
| | **North<br>America** | **North<br>Sea** | **Offshore<br>Africa** | | | | |
| **Cost** | | | | | | | |
| At December 31, 2021 | $77834 | $7438 | $3980 | $46856 | $466 | $508 | $137082 |
| Additions / Acquisitions | **3136** | **127** | **119** | **1759** | **9** | **25** | **5175** |
| Transfers from exploration & evaluation assets | **71** | **—** | **—** | **—** | **—** | **—** | **71** |
| Change in asset retirement obligation estimates | **428** | **177** | **(44)** | **(379)** | **(1)** | **—** | **181** |
| Derecognitions <sup>(1)</sup> | **(394)** | **(1)** | **—** | **(469)** | **—** | **—** | **(864)** |
| Disposals | **—** | **—** | **—** | **(35)** | **—** | **—** | **(35)** |
| Foreign exchange adjustments and other | **—** | **517** | **277** | **—** | **—** | **3** | **797** |
| At December 31, 2022 | $**81075** | $**8258** | $**4332** | $**47732** | $**474** | $**536** | $**142407** |
| **Accumulated depletion and depreciation** | **Accumulated depletion and depreciation** | **Accumulated depletion and depreciation** |  |  |  |  |  |
| At December 31, 2021 | $52732 | $5951 | $2923 | $8499 | $183 | $394 | $70682 |
| Expense | **3502** | **117** | **148** | **1684** | **15** | **23** | **5489** |
| Derecognitions <sup>(1)</sup> | **(394)** | **(1)** | **—** | **(469)** | **—** | **—** | **(864)** |
| Disposals | **—** | **—** | **—** | **(2)** | **—** | **—** | **(2)** |
| Recoverability charge | **—** | **1620** | **—** | **—** | **—** | **—** | **1620** |
| Foreign exchange adjustments and other | **(5)** | **419** | **206** | **—** | **—** | **3** | **623** |
| At December 31, 2022 | $**55835** | $**8106** | $**3277** | $**9712** | $**198** | $**420** | $**77548** |
| **Net book value** |  |  |  |  |  |  |  |
| **At December 31, 2022** | $**25240** | $**152** | $**1055** | $**38020** | $**276** | $**116** | $**64859** |
| At December 31, 2021 | $25102 | $1487 | $1057 | $38357 | $283 | $114 | $66400 |

---

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

During the year ended December 31, 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.

Canadian Natural Resources Limited 6 Three months and year ended December 31, 2022

------

Prevailing regulatory and economic conditions in 2022 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. 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.

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, net of deferred tax recoveries of $969 million.

As at December 31, 2022, 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.

**6. LEASES**

**Lease assets**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Product<br>transportation<br>and storage** | **Field<br>equipment <br>and power** | **Offshore<br>vessels and<br>equipment** | **Office leases<br>and other** | **Total** |
| At December 31, 2021 | $974 | $354 | $99 | $81 | $1508 |
| Additions | **44** | **110** | **28** | **—** | **182** |
| Depreciation | **(106)** | **(86)** | **(31)** | **(21)** | **(244)** |
| Foreign exchange adjustments and other | **—** | **(1)** | **1** | **1** | **1** |
| At December 31, 2022 | $**912** | $**377** | $**97** | $**61** | $**1447** |

---

**Lease liabilities**

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

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Lease liabilities | $**1540** | $1584 |
| Less: current portion | **244** | 185 |
|  | $**1296** | $1399 |

---

Total cash outflows for leases for the three months ended December 31, 2022, including payments related to short-term leases not reported as lease assets, were $322 million (three months ended December 31, 2021 – $258 million; year ended December 31, 2022 – $1,204 million; year ended December 31, 2021 – $1,089 million). Interest expense on leases for the three months ended December 31, 2022 was $15 million (three months ended December 31, 2021 – $15 million; year ended December 31, 2022 – $60 million; year ended December 31, 2021 – $62 million).

Canadian Natural Resources Limited 7 Three months and year ended December 31, 2022

------

**7. INVESTMENTS**

As at December 31, 2022, the Company had the following investment:

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Investment in PrairieSky Royalty Ltd. | $**491** | $309 |

---

The gain from investments was comprised as follows:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021<sup>(1)</sup> |
| Gain from investments | $**(88)** | $(3) | $**(182)** | $(132) |
| Dividend income | **(5)** | (2) | **(14)** | (9) |
|  | $**(93)** | $(5) | $**(196)** | $(141) |

---

*(1) Includes the gain and dividend income from the Company's investment in Inter Pipeline Ltd.*

The Company's 22.6 million share investment in PrairieSky Royalty Ltd. 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, 2022, the market price per common share was $21.70 (December 31, 2021 – $13.63).

**8. OTHER LONG-TERM ASSETS**

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Prepaid cost of service tolls | $**199** | $157 |
| Long-term inventory | **137** | 126 |
| Risk management (note 16) | **9** | 140 |
| Long-term contracts, prepayments and other <sup>(1)</sup> | **269** | 177 |
|  | **614** | 600 |
| Less: current portion | **61** | 35 |
|  | $**553** | $565 |

---

*(1)Includes physical product sales contracts assumed in the acquisition of Painted Pony Energy Ltd. ("Painted Pony") in the fourth quarter of 2020, accrued interest on the deferred PRT recovery, and the unamortized portion of the Company's share bonus program*.***

The Company has a 50% equity investment in 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 17). Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment (note 18).

During the third quarter of 2022, NWRP extended its $3,000 million syndicated credit facility and increased it to $3,175 million. The revolving portion of the credit facility was increased to $2,175 million, with $118 million maturing in June 2023, and $2,057 million maturing in June 2025. The $1,000 million non-revolving portion of the credit facility was extended, with $60 million maturing in June 2023, and $940 million maturing in June 2025. During the third quarter of 2022, NWRP also entered into a $150 million facility to support letters of credit.

The carrying value of the Company's interest in NWRP is $nil, and as at December 31, 2022, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $551 million (December 31, 2021 – $562 million). For the three months ended December 31, 2022, the Company's recovery of its share of unrecognized equity losses was $37 million (year ended December 31, 2022 – recovery of unrecognized equity losses of $11 million; three months ended December 31, 2021 – unrecognized equity loss of $12 million; year ended December 31, 2021 – unrecognized equity loss of $9 million and partnership distributions of $400 million).

Canadian Natural Resources Limited 8 Three months and year ended December 31, 2022

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**9. LONG-TERM DEBT**

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Canadian dollar denominated debt, unsecured** |  |  |
| Medium-term notes | $**1702** | $3200 |
| **US dollar denominated debt, unsecured** |  |  |
| Bank credit facilities (December 31, 2022 – US$nil;<br>&nbsp;&nbsp;&nbsp;&nbsp; December 31, 2021 – US$901 million) | **—** | 1140 |
| US dollar debt securities (December 31, 2022 – US$7,250 million; <br>&nbsp;&nbsp;&nbsp;&nbsp; December 31, 2021 – US$8,250 million) | **9812** | 10441 |
|  | **9812** | 11581 |
| Long-term debt before transaction costs and original issue discounts, net | **11514** | 14781 |
| Less: original issue discounts, net <sup>(1)</sup> | **13** | 15 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;transaction costs <sup>(1) (2)</sup> | **56** | 72 |
|  | **11445** | 14694 |
| Less: current portion of other long-term debt <sup>(1) (2)</sup> | **404** | 1000 |
|  | $**11041** | $13694 |

---

*(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.*

**Bank Credit Facilities and Commercial Paper**

As at December 31, 2022, the Company had undrawn revolving bank credit facilities of $5,520 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 2024;

• a $2,425 million revolving syndicated credit facility, maturing June 2024; and

• a $2,495 million revolving syndicated credit facility, with $70 million maturing June 2023, and $2,425 million maturing June 2025.

During the second quarter of 2022, the Company repaid and cancelled the $500 million non-revolving portion of the $1,000 million term credit facility, reducing the remaining facility to the $500 million revolving facility maturing February 2023. In the fourth quarter of 2022, this facility was extended from February 2023 to February 2024.

During the first quarter of 2022, the Company repaid $500 million of the $1,150 million non-revolving term credit facility maturing February 2023. During the second quarter of 2022, the Company repaid the remaining $650 million and the facility was cancelled.

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, LIBOR, SOFR, US base rate or Canadian prime rate.

During the first quarter of 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. 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, 2022 was 4.3% (December 31, 2021 – 3.5%).

As at December 31, 2022, letters of credit and guarantees aggregating to $637 million were outstanding.

Canadian Natural Resources Limited 9 Three months and year ended December 31, 2022

------

**Medium-Term Notes**

In July 2021, 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 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 the fourth quarter of 2022, the Company repaid through market purchases $18 million of medium-term notes with interest rates ranging from 1.45% to 3.55%, originally due between 2023 and 2028 (year ended December 31, 2022 - $498 million).

During the first quarter of 2022, the Company repaid $1,000 million of 3.31% medium-term notes.

**US Dollar Debt Securities**

In July 2021, 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 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 the fourth quarter of 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023.

**10. OTHER LONG-TERM LIABILITIES**

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Asset retirement obligations | $**6908** | $6806 |
| Lease liabilities (note 6) | **1540** | 1584 |
| Share-based compensation | **832** | 489 |
| Transportation and processing contracts | **159** | 241 |
| Risk management (note 16) | **3** | 85 |
| Other  | **92** | 127 |
|  | **9534** | 9332 |
| Less: current portion | **1373** | 948 |
|  | $**8161** | $8384 |

---

Canadian Natural Resources Limited 10 Three months and year ended December 31, 2022

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**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 5.6% (December 31, 2021 – 4.0%) and inflation rates of up to 2% (December 31, 2021 – up to 2%). Reconciliations of the discounted asset retirement obligations were as follows:

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Balance – beginning of year | $**6806** | $5861 |
| &nbsp;&nbsp;&nbsp;&nbsp;Liabilities incurred | **20** | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Liabilities acquired, net | **11** | 76 |
| &nbsp;&nbsp;&nbsp;&nbsp;Liabilities settled | **(449)** | (307) |
| &nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligation accretion | **281** | 185 |
| &nbsp;&nbsp;&nbsp;&nbsp;Revision of cost, inflation and timing estimates <sup>(1)</sup> | **897** | 508 |
| &nbsp;&nbsp;&nbsp;&nbsp;Impact of regulatory changes <sup>(2)</sup> | **982** | 1208 |
| &nbsp;&nbsp;&nbsp;&nbsp;Change in discount rates | **(1698)** | (723) |
| &nbsp;&nbsp;&nbsp;&nbsp;Foreign exchange adjustments | **58** | (7) |
| Balance – end of year | **6908** | 6806 |
| Less: current portion | **495** | 249 |
|  | $**6413** | $6557 |

---

*(1)Includes normal course revisions of cost, inflation and timing estimates, as well as revisions related to the acceleration of the abandonment of Ninian field assets in the North Sea at December 31, 2022.*

*(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.*

**Share-Based Compensation**

The liability for share-based compensation includes costs incurred under the Company's Stock Option Plan and Performance Share Unit ("PSU") plans. The Company's Stock 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 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.

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Balance – beginning of year | $**489** | $160 |
| &nbsp;&nbsp;&nbsp;&nbsp;Share-based compensation expense | **804** | 514 |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash payment for stock options surrendered and PSUs vested | **(79)** | (48) |
| &nbsp;&nbsp;&nbsp;&nbsp;Transferred to common shares | **(387)** | (139) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **5** | 2 |
| Balance – end of year | **832** | 489 |
| Less: current portion | **559** | 329 |
|  | $**273** | $160 |

---

Canadian Natural Resources Limited 11 Three months and year ended December 31, 2022

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**11. INCOME TAXES**

The provision for income tax was as follows:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| **Expense (recovery)** | **Dec 31<br>2022** | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Current corporate income tax – North America | $**345** | $691 | $**2789** | $1841 |
| Current corporate income tax – North Sea | **33** | (3) | **69** | 7 |
| Current corporate income tax – Offshore Africa | **23** | 3 | **74** | 21 |
| Current PRT <sup>(1)</sup> – North Sea | **(5)** | (12) | **(42)** | (34) |
| Other taxes | **3** | 4 | **16** | 13 |
| Current income tax | **399** | 683 | **2906** | 1848 |
| Deferred corporate income tax | **(148)** | 193 | **302** | 399 |
| Deferred PRT <sup>(1)</sup> – North Sea | **(441)** |  | **(441)** |  |
| Deferred income tax | **(589)** | 193 | **(139)** | 399 |
| Income tax | $**(190)** | $876 | $**2767** | $2247 |

---

*(1)Petroleum Revenue Tax*

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 5), 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.

**12. SHARE CAPITAL**

**Authorized**

Preferred shares issuable in a series.

Unlimited number of common shares without par value.

---

| | | |
|:---|:---|:---|
| | Year Ended Dec 31, 2022 | Year Ended Dec 31, 2022 |
| **Issued Common Shares** | **Number of shares**<br>(thousands) | **Amount** |
| Balance – beginning of year | **1168369** | $**10168** |
| &nbsp;&nbsp;&nbsp;&nbsp;Issued upon exercise of stock options | **11605** | **442** |
| &nbsp;&nbsp;&nbsp;&nbsp;Previously recognized liability on stock options exercised for common shares | **—** | **387** |
| &nbsp;&nbsp;&nbsp;&nbsp;Purchase of common shares under Normal Course Issuer Bid | **(77338)** | **(703)** |
| Balance – end of year | **1102636** | $**10294** |

---

**Dividend Policy**

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 March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share, beginning with the dividend payable on April 5, 2023.

On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share, beginning with the dividend paid on January 5, 2023.

On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share, paid on August 31, 2022.

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.

Canadian Natural Resources Limited 12 Three months and year ended December 31, 2022

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**Normal Course Issuer Bid**

On March 8, 2022, the Company's application was approved for a Normal Course Issuer Bid ("NCIB") to purchase through the facilities of the Toronto Stock Exchange, alternative Canadian trading platforms, and the New York Stock Exchange, up to 101,574,207 common shares, representing 10% of the public float, over a 12-month period commencing March 11, 2022 and ending March 10, 2023.

For the year ended December 31, 2022, the Company purchased 77,338,200 common shares at a weighted average price of $72.03 per common share for a total cost of $5,571 million. Retained earnings were reduced by $4,868 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2022, up to and including February 28, 2023, the Company purchased 6,000,000 common shares at a weighted average price of $77.72 per common share for a total cost of $466 million.

On March 1, 2023, 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-Based Compensation – Stock Options**

The following table summarizes information relating to stock options outstanding as at December 31, 2022:

---

| | | |
|:---|:---|:---|
| | Year Ended Dec 31, 2022 | Year Ended Dec 31, 2022 |
| | **Stock options**<br>(thousands) | **Weighted<br> average<br> exercise price** |
| Outstanding – beginning of year | **38327** | $**35.88** |
| &nbsp;&nbsp;&nbsp;&nbsp;Granted | **7547** | $**68.15** |
| &nbsp;&nbsp;&nbsp;&nbsp;Exercised for common shares | **(11605)** | $**38.06** |
| &nbsp;&nbsp;&nbsp;&nbsp;Surrendered for cash settlement | **(441)** | $**38.43** |
| &nbsp;&nbsp;&nbsp;&nbsp;Forfeited | **(2678)** | $**41.43** |
| Outstanding – end of year | **31150** | $**42.37** |
| Exercisable – end of year | **5522** | $**37.60** |

---

The Stock 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.

**13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)**

The components of accumulated other comprehensive income (loss), net of taxes, were as follows:

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Derivative financial instruments designated as cash flow hedges | $**75** | $77 |
| Foreign currency translation adjustment | **134** | (78) |
|  | $**209** | $(1) |

---

Canadian Natural Resources Limited 13 Three months and year ended December 31, 2022

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**14. 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 arithmetic 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%. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may be below the low end of the targeted range when cash flow from operating activities is greater than current investment activities. As at December 31, 2022, the ratio was below the target range at 21.6%.

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.

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Dec 31<br>2022** | **Dec 31<br>2022** | Dec 31<br>2021 | Dec 31<br>2021 |
| Long-term debt | **$** | **11445** | $| 14694 |
| Less: cash and cash equivalents | **920** | **920** | 744 | 744 |
| Long-term debt, net | **$** | **10525** | $| 13950 |
| Total shareholders' equity | **$** | **38175** | $| 36945 |
| Debt to book capitalization | **21.6%** | **21.6%** | 27.4% | 27.4% |

---

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, 2022, the Company was in compliance with this covenant.

**15. NET EARNINGS PER COMMON SHARE**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | | **Dec 31<br>2022** | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average common shares outstanding<br>&nbsp;&nbsp;&nbsp;&nbsp;– basic (thousands of shares) | &nbsp;&nbsp;&nbsp;&nbsp;Weighted average common shares outstanding<br>&nbsp;&nbsp;&nbsp;&nbsp;– basic (thousands of shares) | **1106042** | 1174683 | **1134960** | 1181250 |
| Effect of dilutive stock options (thousands of shares) | Effect of dilutive stock options (thousands of shares) | **13529** | 11150 | **14222** | 5307 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average common shares outstanding<br>&nbsp;&nbsp;&nbsp;&nbsp;– diluted (thousands of shares) | &nbsp;&nbsp;&nbsp;&nbsp;Weighted average common shares outstanding<br>&nbsp;&nbsp;&nbsp;&nbsp;– diluted (thousands of shares) | **1119571** | 1185833 | **1149182** | 1186557 |
| Net earnings | Net earnings | $**1520** | $2534 | $**10937** | $7664 |
| Net earnings per common share | – basic | $**1.37** | $2.16 | $**9.64** | $6.49 |
|  | – diluted | $**1.36** | $2.14 | $**9.52** | $6.46 |

---

Canadian Natural Resources Limited 14 Three months and year ended December 31, 2022

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**16. FINANCIAL INSTRUMENTS**

The carrying amounts of the Company's financial instruments by category were as follows:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Dec 31, 2022** | **Dec 31, 2022** | **Dec 31, 2022** | **Dec 31, 2022** | **Dec 31, 2022** |
| **Asset (liability)** | **Financial<br> assets at <br>amortized<br> cost** | **Fair value<br> through<br>profit or loss** | **Derivatives<br> used for<br> hedging** | **Financial<br> liabilities at<br> amortized<br>cost** | **Total** |
| Cash and cash equivalents | $**920** | $**—** | $**—** | $**—** | $**920** |
| Accounts receivable | **3555** | **—** | **—** | **—** | **3555** |
| Investments | **—** | **491** | **—** | **—** | **491** |
| Other long-term assets | **—** | **9** | **—** | **—** | **9** |
| Accounts payable | **—** | **—** | **—** | **(1341)** | **(1341)** |
| Accrued liabilities | **—** | **—** | **—** | **(4209)** | **(4209)** |
| Other long-term liabilities <sup>(1)</sup> | **—** | **(3)** | **—** | **(1540)** | **(1543)** |
| Long-term debt <sup>(2)</sup> | **—** | **—** | **—** | **(11445)** | **(11445)** |
|  | $**4475** | $**497** | $**—** | $**(18535)** | $**(13563)** |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Dec 31, 2021 | Dec 31, 2021 | Dec 31, 2021 | Dec 31, 2021 | Dec 31, 2021 |
| Asset (liability) | Financial<br> assets at <br>amortized<br> cost | Fair value<br> through<br>profit or loss | Derivatives<br> used for<br> hedging | Financial<br> liabilities at<br> amortized<br>cost | Total |
| Cash and cash equivalents | $744 | $— | $— | $— | $744 |
| Accounts receivable | 3111 |  |  |  | 3111 |
| Investments |  | 309 |  |  | 309 |
| Other long-term assets |  |  | 140 |  | 140 |
| Accounts payable |  |  |  | (803) | (803) |
| Accrued liabilities |  |  |  | (3064) | (3064) |
| Other long-term liabilities <sup>(1)</sup> |  | (64) | (21) | (1632) | (1717) |
| Long-term debt <sup>(2)</sup> |  |  |  | (14694) | (14694) |
|  | $3855 | $245 | $119 | $(20193) | $(15974) |

---

*(1)Includes $1,540 million of lease liabilities (December 31, 2021 – $1,584 million).*

*(2)Includes the current portion of long-term debt.*

Canadian Natural Resources Limited 15 Three months and year ended December 31, 2022

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The carrying amounts of the Company's financial instruments approximated their fair value, except for fixed rate long-term debt. The fair values of the Company's investments, recurring other long-term assets (liabilities) and fixed rate long-term debt are outlined below:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Dec 31, 2022** | **Dec 31, 2022** | **Dec 31, 2022** | **Dec 31, 2022** |
| | **Carrying amount** | **Fair value** | **Fair value** | **Fair value** |
| **Asset (liability)** <sup>(1) (2)</sup> | | **Level 1** | **Level 2** | **Level 3** |
| Investments <sup>(3)</sup> | $**491** | $**491** | $**—** | $**—** |
| Other long-term assets | $**9** | $**—** | $**9** | $**—** |
| Other long-term liabilities | $**(3)** | $**—** | $**(3)** | $**—** |
| Fixed rate long-term debt <sup>(4) (5)</sup> | $**(11445)** | $**(10796)** | $**—** | $**—** |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Dec 31, 2021 | Dec 31, 2021 | Dec 31, 2021 | Dec 31, 2021 |
| | Carrying amount | Fair value | Fair value | Fair value |
| Asset (liability) <sup>(1) (2)</sup> |  | Level 1 | Level 2 | Level 3 |
| Investments <sup>(3)</sup> | $309 | $309 | $— | $— |
| Other long-term assets | $140 | $— | $140 | $— |
| Other long-term liabilities | $(133) | $— | $(85) | $(48) |
| Fixed rate long-term debt <sup>(4) (5)</sup> | $(13554) | $(15420) | $— | $— |

---

*(1)Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities).*

*(2)There were no transfers between Level 1, 2 and 3 financial instruments.*

*(3)The fair values of the investments are based on quoted market prices.*

*(4)The fair value of fixed rate long-term debt has been determined based on quoted market prices.*

*(5)Includes the current portion of fixed rate long-term debt.*

**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)** | **Dec 31<br>2022** | Dec 31<br>2021 |
| **Derivatives held for trading** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas <sup>(1)</sup> | $**3** | $(41) |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil and NGLs <sup>(1)</sup> | **—** | (10) |
| &nbsp;&nbsp;&nbsp;&nbsp;Foreign currency forward contracts | **3** | (13) |
| **Cash flow hedges** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Foreign currency forward contracts | **—** | (21) |
| &nbsp;&nbsp;&nbsp;&nbsp;Cross currency swaps | **—** | 140 |
|  | $**6** | $55 |
| Included within: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Current portion of other long-term assets | $**3** | $5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current portion of other long-term liabilities | **(3)** | (72) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other long-term assets | **6** | 135 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other long-term liabilities | **—** | (13) |
|  | $**6** | $55 |

---

*(1)Commodity financial instruments assumed in the acquisitions of Storm Resources Ltd. ("Storm") and Painted Pony in the fourth quarter of 2021 and 2020, respectively.*

Canadian Natural Resources Limited 16 Three months and year ended December 31, 2022

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The estimated fair values of derivative financial instruments in Level 2 at each measurement date have been determined based on appropriate internal valuation methodologies and/or third party indications. Level 2 fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows and discount rates. In determining these assumptions, the Company primarily relied on external, readily-observable quoted market inputs as applicable, including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States interest rate yield curves, and Canadian and United States forward foreign exchange rates, discounted to present value as appropriate. 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.

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)** | **Dec 31<br>2022** | Dec 31<br>2021 |
| Balance – beginning of year | $**55** | $(24) |
| Net change in fair value of outstanding derivative financial instruments recognized in: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Risk management activities | **70** | (12) |
| &nbsp;&nbsp;&nbsp;&nbsp;Foreign exchange | **(119)** | 82 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other comprehensive income | **—** | 9 |
| Balance – end of year | **6** | 55 |
| Less: current portion | **—** | (67) |
|  | $**6** | $122 |

---

Net loss (gain) from risk management activities were as follows:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | **Dec 31<br>2022** | Dec 31<br>2021 | **Dec 31<br>2022** | Dec 31<br>2021 |
| Net realized risk management (gain) loss | $**(2)** | $(6) | $**(7)** | $17 |
| Net unrealized risk management loss (gain) | **15** | 8 | **(28)** | 19 |
|  | $**13** | $2 | $**(35)** | $36 |

---

**Financial Risk Factors**

**a) &nbsp;&nbsp;&nbsp;&nbsp;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 rate 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. As at December 31, 2022, the Company had no significant interest rate swap contracts outstanding.

Canadian Natural Resources Limited 17 Three months and year ended December 31, 2022

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**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. As at December 31, 2022, the Company had no cross currency swap contracts outstanding.

During the second quarter of 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, 2022, the Company had US$1,017 million of foreign currency forward contracts outstanding, with original terms of up to 90 days, all of which were designated as derivatives held for trading.

**b) &nbsp;&nbsp;&nbsp;&nbsp;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. As at December 31, 2022, substantially all of the Company's accounts receivable were due within normal trade terms.

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, 2022, the Company had net risk management assets of $7 million with specific counterparties related to derivative financial instruments (December 31, 2021 – $140 million).

The carrying amount of financial assets approximates the maximum credit exposure.

**c) &nbsp;&nbsp;&nbsp;&nbsp;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.

As at December 31, 2022, the maturity dates of the Company's financial liabilities were as follows:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Less than<br>1 year | 1 to less than<br>2 years | 2 to less than<br>5 years | Thereafter |
| Accounts payable | $1341 | $— | $— | $— |
| Accrued liabilities | $4209 | $— | $— | $— |
| Long-term debt <sup>(1)</sup> | $404 | $1009 | $3757 | $6344 |
| Other long-term liabilities <sup>(2)</sup> | $247 | $156 | $416 | $724 |
| Interest and other financing expense <sup>(3)</sup> | $584 | $577 | $1410 | $3790 |

---

*(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, $244 million; one to less than two years, $156 million; two to less than five years, $416 million; and thereafter, $724 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, 2022.*

Canadian Natural Resources Limited 18 Three months and year ended December 31, 2022

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**17. 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, 2022:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter |
| Product transportation and processing <sup>(1)</sup> | $1171 | $1349 | $1168 | $1102 | $1052 | $11095 |
| North West Redwater Partnership service toll <sup>(2)</sup> | $151 | $152 | $151 | $133 | $118 | $4884 |
| Offshore vessels and equipment  | $44 | $35 | $— | $— | $— | $— |
| Field equipment and power | $36 | $27 | $24 | $23 | $22 | $215 |
| Other | $23 | $24 | $21 | $16 | $— | $— |

---

*(1)Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion.*

*(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 $2,863 million of interest payable over the 40-year tolling period, ending in 2058 (note 8).*

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.

Canadian Natural Resources Limited 19 Three months and year ended December 31, 2022

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**18. SEGMENTED INFORMATION**

---

| | | | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **North America** | **North America** | **North America** | **North America** | **North Sea** | **North Sea** | **North Sea** | **North Sea** | **Offshore Africa** | **Offshore Africa** | **Offshore Africa** | **Offshore Africa** | **Total Exploration and Production** | **Total Exploration and Production** | **Total Exploration and Production** | **Total Exploration and Production** |
| | Three Months Ended | Three Months Ended | Year Ended | Year Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 |
| &nbsp;&nbsp;(millions of Canadian dollars, <br>unaudited) | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 |
| **Segmented product sales** |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Crude oil and NGLs | **4124** | 4431 | **20755** | 14478 | **228** | 197 | **623** | 607 | **153** | 39 | **694** | 420 | **4505** | 4667 | **22072** | 15505 |
| Natural gas | **1234** | 901 | **4931** | 2484 | **4** | 2 | **13** | 5 | **8** | 11 | **55** | 31 | **1246** | 914 | **4999** | 2520 |
| Other income and revenue <sup>(1)</sup> | **19** | 38 | **217** | 119 | **(3)** | (1) | **—** | (1) | **2** | 1 | **8** | 7 | **18** | 38 | **225** | 125 |
| **Total segmented product sales** | **5377** | 5370 | **25903** | 17081 | **229** | 198 | **636** | 611 | **163** | 51 | **757** | 458 | **5769** | 5619 | **27296** | 18150 |
| Less: royalties | **(725)** | (566) | **(3918)** | (1694) | **—** |  | **(1)** | (1) | **(21)** | (3) | **(71)** | (21) | **(746)** | (569) | **(3990)** | (1716) |
| **Segmented revenue** | **4652** | 4804 | **21985** | 15387 | **229** | 198 | **635** | 610 | **142** | 48 | **686** | 437 | **5023** | 5050 | **23306** | 16434 |
| **Segmented expenses** |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Production | **983** | 794 | **3754** | 2963 | **196** | 130 | **437** | 383 | **36** | 14 | **114** | 91 | **1215** | 938 | **4305** | 3437 |
| Transportation, blending and feedstock | **1505** | 1459 | **6394** | 4772 | **1** | 2 | **6** | 7 | **—** |  | **1** | 1 | **1506** | 1461 | **6401** | 4780 |
| Depletion, depreciation and amortization (note 5) | **949** | 939 | **3595** | 3569 | **1653** | 33 | **1747** | 160 | **41** | 19 | **173** | 142 | **2643** | 991 | **5515** | 3871 |
| Asset retirement obligation accretion | **51** | 25 | **171** | 101 | **10** | 5 | **33** | 21 | **2** | 2 | **7** | 6 | **63** | 32 | **211** | 128 |
| Risk management activities (commodity derivatives) | **12** | (3) | **18** | 29 | **—** |  | **—** |  | **—** |  | **—** |  | **12** | (3) | **18** | 29 |
| Gain on acquisitions | **—** |  | **—** | (478) | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** | (478) |
| Income from North West Redwater Partnership | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  |
| **Total segmented expenses** | **3500** | 3214 | **13932** | 10956 | **1860** | 170 | **2223** | 571 | **79** | 35 | **295** | 240 | **5439** | 3419 | **16450** | 11767 |
| **Segmented earnings (loss)** | **1152** | 1590 | **8053** | 4431 | **(1631)** | 28 | **(1588)** | 39 | **63** | 13 | **391** | 197 | **(416)** | 1631 | **6856** | 4667 |
| **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** |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

---

Canadian Natural Resources Limited 20 Three months and year ended December 31, 2022

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---

| | | | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Oil Sands Mining and Upgrading** | **Oil Sands Mining and Upgrading** | **Oil Sands Mining and Upgrading** | **Oil Sands Mining and Upgrading** | **Midstream and Refining** | **Midstream and Refining** | **Midstream and Refining** | **Midstream and Refining** | **Inter–segment**<br>**elimination and other** | **Inter–segment**<br>**elimination and other** | **Inter–segment**<br>**elimination and other** | **Inter–segment**<br>**elimination and other** | **<br>Total** | **<br>Total** | **<br>Total** | **<br>Total** |
| | Three Months Ended | Three Months Ended | Year Ended | Year Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended | Three Months Ended | Three Months Ended | Year Ended | Year Ended |
| | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 | Dec 31 |
| &nbsp;&nbsp;(millions of Canadian dollars, <br>unaudited) | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 |
| **Segmented product sales** |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Crude oil and NGLs <sup>(2)</sup> | **4935** | 4408 | **20804** | 14033 | **21** | 17 | **80** | 78 | **47** | (113) | **53** | (360) | **9508** | 8979 | **43009** | 29256 |
| Natural gas | **—** |  | **—** |  | **—** |  | **—** |  | **41** | 44 | **237** | 196 | **1287** | 958 | **5236** | 2716 |
| Other income and revenue <sup>(1)</sup> | **(2)** | 18 | **149** | 73 | **205** | 200 | **906** | 681 | **(4)** | (3) | **5** | 3 | **217** | 253 | **1285** | 882 |
| **Total segmented product sales** | **4933** | 4426 | **20953** | 14106 | **226** | 217 | **986** | 759 | **84** | (72) | **295** | (161) | **11012** | 10190 | **49530** | 32854 |
| Less: royalties | **(577)** | (408) | **(3242)** | (1081) | **—** |  | **—** |  | **—** |  | **—** |  | **(1323)** | (977) | **(7232)** | (2797) |
| **Segmented revenue** | **4356** | 4018 | **17711** | 13025 | **226** | 217 | **986** | 759 | **84** | (72) | **295** | (161) | **9689** | 9213 | **42298** | 30057 |
| **Segmented expenses** |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Production | **1017** | 871 | **4076** | 3414 | **63** | 42 | **271** | 234 | **14** | 18 | **60** | 67 | **2309** | 1869 | **8712** | 7152 |
| Transportation, blending and feedstock <sup>(2)</sup> | **867** | 527 | **2652** | 1505 | **155** | 165 | **691** | 550 | **73** | (88) | **229** | (231) | **2601** | 2065 | **9973** | 6604 |
| Depletion, depreciation and amortization (note 5) | **481** | 478 | **1822** | 1838 | **5** | 4 | **16** | 15 | **—** |  | **—** |  | **3129** | 1473 | **7353** | 5724 |
| Asset retirement obligation accretion | **19** | 14 | **70** | 57 | **—** |  | **—** |  | **—** |  | **—** |  | **82** | 46 | **281** | 185 |
| Risk management activities (commodity derivatives) | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **12** | (3) | **18** | 29 |
| Gain on acquisitions | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** |  | **—** | (478) |
| Income from North West Redwater Partnership | **—** |  | **—** |  | **—** |  | **—** | (400) | **—** |  | **—** |  | **—** |  | **—** | (400) |
| **Total segmented expenses** | **2384** | 1890 | **8620** | 6814 | **223** | 211 | **978** | 399 | **87** | (70) | **289** | (164) | **8133** | 5450 | **26337** | 18816 |
| **Segmented earnings (loss)** | **1972** | 2128 | **9091** | 6211 | **3** | 6 | **8** | 360 | **(3)** | (2) | **6** | 3 | **1556** | 3763 | **15961** | 11241 |
| **Non–segmented expenses** |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Administration |  |  |  |  |  |  |  |  |  |  |  |  | **108** | 97 | **415** | 366 |
| Share-based compensation |  |  |  |  |  |  |  |  |  |  |  |  | **319** | 191 | **804** | 514 |
| Interest and other financing expense |  |  |  |  |  |  |  |  |  |  |  |  | **76** | 171 | **549** | 711 |
| Risk management activities (other) |  |  |  |  |  |  |  |  |  |  |  |  | **1** | 5 | **(53)** | 7 |
| Foreign exchange (gain) loss |  |  |  |  |  |  |  |  |  |  |  |  | **(185)** | (106) | **738** | (127) |
| Gain from investments |  |  |  |  |  |  |  |  |  |  |  |  | **(93)** | (5) | **(196)** | (141) |
| **Total non-segmented expenses** |  |  |  |  |  |  |  |  |  |  |  |  | **226** | 353 | **2257** | 1330 |
| **Earnings before taxes** |  |  |  |  |  |  |  |  |  |  |  |  | **1330** | 3410 | **13704** | 9911 |
| Current income tax |  |  |  |  |  |  |  |  |  |  |  |  | **399** | 683 | **2906** | 1848 |
| Deferred income tax |  |  |  |  |  |  |  |  |  |  |  |  | **(589)** | 193 | **(139)** | 399 |
| **Net earnings** |  |  |  |  |  |  |  |  |  |  |  |  | **1520** | 2534 | **10937** | 7664 |

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*(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)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.*

Canadian Natural Resources Limited 21 Three months and year ended December 31, 2022

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**Capital Expenditures** <sup>(1)</sup>

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | Year Ended | Year Ended | Year Ended | Year Ended | Year Ended | Year Ended |
| | **Dec 31, 2022** | **Dec 31, 2022** | **Dec 31, 2022** | Dec 31, 2021 | Dec 31, 2021 | Dec 31, 2021 |
| | **Net expenditures** | **Non-cash**<br>**and fair value changes** <sup>(2)</sup>  | **Capitalized**<br> **costs** | Net expenditures (proceeds) | Non-cash<br>and fair value changes <sup>(2)</sup> | Capitalized<br> costs |
| **Exploration and evaluation assets** |  |  |  |  |  |  |
| Exploration and<br>&nbsp;&nbsp;&nbsp;&nbsp;Production |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North America  | $**28** | $**(59)** | $**(31)** | $(7) | $(36) | $(43) |
| &nbsp;&nbsp;&nbsp;&nbsp;Offshore Africa | **5** | **—** | **5** | 8 |  | 8 |
| Oil Sands Mining and Upgrading | **—** | **—** | **—** |  | (150) | (150) |
|  | **33** | **(59)** | **(26)** | 1 | (186) | (185) |
| **Property, plant and equipment** |  |  |  |  |  |  |
| Exploration and<br>&nbsp;&nbsp;&nbsp;&nbsp;Production |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North America <sup>(3)</sup> | **3105** | **136** | **3241** | 2486 | 1351 | 3837 |
| &nbsp;&nbsp;&nbsp;&nbsp;North Sea | **126** | **177** | **303** | 173 | 38 | 211 |
| &nbsp;&nbsp;&nbsp;&nbsp;Offshore Africa | **119** | **(44)** | **75** | 54 | (6) | 48 |
|  | **3350** | **269** | **3619** | 2713 | 1383 | 4096 |
| Oil Sands Mining and<br>&nbsp;&nbsp;&nbsp;&nbsp;Upgrading <sup>(4)</sup> | **1719** | **(843)** | **876** | 1747 | (601) | 1146 |
| Midstream and Refining | **9** | **(1)** | **8** | 9 |  | 9 |
| Head Office | **25** | **—** | **25** | 23 |  | 23 |
|  | **5103** | **(575)** | **4528** | 4492 | 782 | 5274 |
|  | $**5136** | $**(634)** | $**4502** | $4493 | $596 | $5089 |

---

*(1)This table provides a reconciliation of capitalized costs, reported in note 4 and note 5, 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.*

*(3)Includes cash consideration paid of $771 million for the acquisition of Storm in the fourth quarter of 2021.*

*(4)Net expenditures includes the acquisition of a 5% net carried interest on an existing oil sands lease in the second quarter of 2021.*

**Segmented Assets**

---

| | | |
|:---|:---|:---|
| | **Dec 31<br>2022** | Dec 31<br>2021 |
| Exploration and Production |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North America | $**31135** | $30645 |
| &nbsp;&nbsp;&nbsp;&nbsp;North Sea | **378** | 1561 |
| &nbsp;&nbsp;&nbsp;&nbsp;Offshore Africa | **1322** | 1332 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **54** | 40 |
| Oil Sands Mining and Upgrading | **42102** | 42016 |
| Midstream and Refining | **979** | 886 |
| Head Office | **172** | 185 |
|  | $**76142** | $76665 |

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Canadian Natural Resources Limited 22 Three months and year ended December 31, 2022

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**SUPPLEMENTARY INFORMATION**

**INTEREST COVERAGE RATIOS**

The following financial ratios are provided in connection with the Company's continuous offering of medium-term notes pursuant to the short form prospectus dated July 2021. These ratios are based on the Company's interim consolidated financial statements that are prepared in accordance with accounting principles generally accepted in Canada.

---

| | |
|:---|:---|
| Interest coverage ratios for the twelve month period ended December 31, 2022: |  |
| Interest coverage (times) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net earnings <sup>(1)</sup> | 26.0x |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Adjusted funds flow <sup>(2)</sup> | 42.3x |

---

*(1)Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.*

*(2)Adjusted funds flow plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.*

Canadian Natural Resources Limited 23 Three months and year ended December 31, 2022