40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 40-F

(Check one)

REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

OR

ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022 Commission File Number 1-34513

  

CENOVUS ENERGY INC.

(Exact name of Registrant as specified in its charter)

Not applicable

(Translation of Registrant’s name into English (if applicable))

Canada

(Province or other jurisdiction of incorporation or organization)

1311

(Primary Standard Industrial Classification Code Number (if applicable))

Not applicable

(I.R.S. Employer Identification Number (if applicable))

4100, 225 – 6 Avenue S.W.

Calgary, Alberta, Canada T2P 1N2

(403) 766-200

(Address and telephone number of Registrant’s principal executive offices)

CT Corporation System

28 Liberty Street

New York, NY 10005

(212) 894-8940

(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common shares, no par value (together with associated common share purchase rights)	CVE	New York Stock Exchange
Warrants (each warrant entitles the holder to purchase one common share at an exercise price of C$6.54 per share)	CVE WS	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

For Annual Reports indicate by check mark the information filed with this Form:

 Annual information form Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

    1,909,190,359

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

 Yes    ☐ No

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

 Yes    ☐ No

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

    Emerging growth company ☐

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

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

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

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

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

The annual report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the Registrant’s Registration Statements under the Securities Act of 1933, as amended: Form F-10 (File No. 333-259814), Form S-8 (File Nos. 333-163397 and 333-251886), Form F-3D (File No. 333-202165).

Principal Documents

The following documents, filed as Exhibits 99.1, 99.2, 99.3 and 99.4 to this annual report on Form 40-F, are hereby incorporated by reference in this annual report on Form 40-F:

(a)Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2022.

(b)Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2022.

(c)Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2022.

(d)Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2022.

ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.

(a)Certifications. See Exhibits 99.5 99.6, 99.7 and 99.8 to this annual report on Form 40-F.

(b)Disclosure Controls and Procedures. As of the end of the Registrant’s fiscal year ended December 31, 2022, an evaluation of the effectiveness of the Registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the Registrant’s management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the Registrant’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the Registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (the “Commission”) rules and forms and (ii) accumulated and communicated to the Registrant’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

It should be noted that while the Registrant’s principal executive officer and principal financial officer believe that the Registrant’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Registrant’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c)Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the “Report of Management” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2022, filed as Exhibit 99.3 to this annual report on Form 40-F.

(d)Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Report of Independent Registered Public Accounting Firm (PCAOB 271)” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2022, filed as Exhibit 99.3 to this annual report on Form 40-F.

(e)Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2022, there was no change in the Registrant’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

Notices Pursuant to Regulation BTR.

None.

Audit Committee Financial Expert.

The Registrant’s board of directors has determined that Claude Mongeau and Jane E. Kinney, who are members of the Registrant’s audit committee, each qualify as an “audit committee financial expert” (as such term is defined in paragraph (8) of General Instruction B to Form 40-F), and that each of the following members of the Registrant’s audit committee is “independent” as that term is defined in the rules of the New York Stock Exchange: Claude Mongeau, Jane E. Kinney, Richard J. Marcogliese and Wayne E. Shaw.

Code of Ethics.

The Registrant has adopted a “code of ethics” (as that term is defined in paragraph (9) of General Instruction B to Form 40-F), entitled the “Code of Business Conduct & Ethics”, that applies to all of its employees, including its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

The Code of Business Conduct & Ethics (the “Code”) is available for viewing on the Registrant’s website at www.cenovus.com and is available in print to any person without charge, upon request. Requests for copies of the Code should be made by contacting the Registrant’s Corporate Secretarial Department, Cenovus Energy Inc., 4100,225 - 6 Avenue S.W., P.O. Box 766, Calgary, Alberta, Canada T2P 0M2. Any amendments to the Code from time to time will be posted to the Registrant’s website within five business days of the amendment and will remain available for a twelve-month period. Information on or connected to our website, even if referred to herein, does not constitute part of this annual report on Form 40-F.

Since the adoption of the Code, there have not been any waivers, including implicit waivers, granted from any provision of the Code.

Principal Accountant Fees and Services.

The required disclosure is included under the heading “Audit Committee - External Auditor Service Fees” in the Registrant’s Annual Information Form for the fiscal year ended December 31, 2022, filed as Exhibit 99.1 to this annual report on Form 40-F.

Pre-Approval Policies and Procedures and Percentage of Services Approved by Audit Committee.

The required disclosure is included under the heading “Audit Committee - Pre-Approval Policies and Procedures” and “Audit Committee – External Auditor Service Fees” in the Registrant’s Annual Information Form for the fiscal year ended December 31, 2022, filed as Exhibit 99.1 to this annual report on Form 40-F. All fees have been pre-approved by the Audit Committee and therefore none of the services therein were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

Off-Balance Sheet Arrangements.

The Registrant does not have any commitments or obligations, including contingent obligations, arising from arrangements with unconsolidated entities or persons (which are not otherwise discussed in the Registrant's Management’s Discussion and Analysis for the fiscal year ended December 31, 2022, filed as Exhibit 99.2 to this annual report on Form 40-F), that have or are reasonably likely to have a material current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, cash requirements or capital resources.

Disclosure of Contractual Obligations.

The required disclosure is included under the heading “Liquidity and Capital Resources - Contractual Obligations and Commitments” in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2022, filed as Exhibit 99.2 to this annual report on Form 40-F.

Identification of the Audit Committee.

The Registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Jane E. Kinney, Richard J. Marcogliese, Claude Mongeau (Chair) and Wayne E. Shaw.

Mine Safety Disclosure.

Not applicable.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.Undertaking

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

B.Consent to Service of Process

(1)The Registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

(2)Any change to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the Registrant.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized. 

	CENOVUS ENERGY INC.
Date:   February 16, 2023	/s/ Jeffrey R. Hart
	Name:    Jeffrey R. Hart
	Title:    Executive Vice-President &     Chief Financial Officer

EXHIBIT INDEX

Exhibits	Documents
99.1	Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2022.
99.2	Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2022.
99.3	Consolidated Annual Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2022.
99.4	Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2022.
99.5	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
99.6	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
99.7	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
99.8	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
99.9	Consent of PricewaterhouseCoopers LLP.
99.10	Consent of McDaniel & Associates Consultants Ltd.
99.11	Consent of GLJ Ltd.
101	Interactive data file

EX-99.1

Exhibit 99.1

Cenovus Energy Inc.

Annual Information Form

For the Year Ended December 31, 2022

February 15, 2023

(Canadian Dollars)

Annual Information Form
For the year ended December 31, 2022

TABLE OF CONTENTS

CORPORATE STRUCTURE	3
GENERAL DEVELOPMENT OF THE BUSINESS	3
DESCRIPTION OF THE BUSINESS	7
BUSINESS SEGMENTS	7
UPSTREAM	8
OIL SANDS	8
CONVENTIONAL	10
OFFSHORE	11
DOWNSTREAM	13
CANADIAN MANUFACTURING	13
U.S. MANUFACTURING	15
COMPETITIVE CONDITIONS	16
ENVIRONMENTAL PROTECTION	16
CODE OF BUSINESS CONDUCT AND ETHICS	17
EMPLOYEES	18
RISK FACTORS	18
RESERVES DATA AND OTHER OIL AND GAS INFORMATION	18
DISCLOSURE OF RESERVES DATA	18
DEVELOPMENT OF PROVED AND PROBABLE UNDEVELOPED RESERVES	30
SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA	30
OTHER OIL AND GAS INFORMATION	31
DIVIDENDS	39
DESCRIPTION OF CAPITAL STRUCTURE	39
MARKET FOR SECURITIES	43
DIRECTORS AND EXECUTIVE OFFICERS	46
AUDIT COMMITTEE	51
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	52
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	53
TRANSFER AGENTS AND REGISTRARS	53
MATERIAL CONTRACTS	53
INTERESTS OF EXPERTS	56
ADDITIONAL INFORMATION	56
ACCOUNTING MATTERS	56
ABBREVIATIONS AND CONVERSIONS	56
FORWARD-LOOKING INFORMATION	57
APPENDIX A — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS	60
APPENDIX B — REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION	61
APPENDIX C — AUDIT COMMITTEE MANDATE	62

In this Annual Information Form (“AIF”), dated February 15, 2023, unless otherwise specified or the context otherwise requires, includes references to “the Company”, “the Corporation”, “Cenovus”, “we”, “us”, or “our”, and means Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc., and its subsidiaries. All of the information and statements contained in this AIF are made as of February 15, 2023. This AIF contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Forward-looking Information section of this document for further information and the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information.

For a full discussion of the Company’s material risk factors, see the Risk Management and Risk Factors section in the Company’s 2022 Management’s Discussion and Analysis (“annual 2022 MD&A”), which section of the annual 2022 MD&A is incorporated by reference in this AIF and the risk factors described in other documents the Company files from time to time with securities regulatory authorities in Canada. Additional information about Cenovus, including our annual 2022 MD&A, annual reports and Form 40-F are available on SEDAR at sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Company’s website at cenovus.com. Information on or connected to the Company’s website at cenovus.com does not form part of this AIF unless expressly incorporated by reference herein.

Cenovus Energy Inc. – 2022 Annual Information Form 2

CORPORATE STRUCTURE

Cenovus was formed under the Canada Business Corporations Act (“CBCA”) on November 30, 2009, pursuant to a plan of arrangement under the CBCA. On January 1, 2021, Cenovus and Husky Energy Inc. (“Husky”) closed a transaction to combine the two companies through a plan of arrangement (the “Arrangement”) under the Business Corporations Act (Alberta). Husky became a wholly-owned subsidiary of Cenovus. In connection with the Arrangement, Cenovus amended its articles on December 30, 2020, to create eight series of cumulative redeemable preferred shares. On March 31, 2021, and December 30, 2021, Cenovus amalgamated with its wholly-owned subsidiaries, Husky Energy Inc. and Husky Oil Operations Limited, respectively, by way of a vertical short-form amalgamation.

The Company’s head and registered office is located at 4100, 225 – 6 Avenue S.W., Calgary, Alberta, Canada T2P 1N2.

Intercorporate Relationships

Cenovus’s material subsidiaries and partnerships as at December 31, 2022, are as follows:

	Percentage Owned (1)	Jurisdiction of Incorporation, Continuance, Formation or Organization
FCCL Partnership ("FCCL")	100	Alberta
Sunrise Oil Sands Partnership ("SOSP") (2)	100	Alberta
Lima Refining Company	100	Delaware
Husky Oil Limited Partnership	100	Alberta
Cenovus Energy Marketing Services Ltd.	100	Alberta
Husky Marketing and Supply Company	100	Delaware
Husky Canadian Petroleum Marketing Partnership	100	Alberta
Husky Energy Marketing Partnership	100	Alberta
BP-Husky Refining LLC (3)	50	Delaware
WRB Refining LP ("WRB") (4)	50	Delaware

(1)Reflects all voting securities of all subsidiaries and partnerships beneficially owned or controlled or directed, directly or indirectly, by Cenovus.

(2)Cenovus’s interest is held through Cenovus Energy Inc. and Husky Oil Sands Partnership. On August 31, 2022, Cenovus acquired from BP Canada Energy Group ULC (“BP Canada”) the remaining 50 percent interest in SOSP, increasing Cenovus’s interest in SOSP to 100 percent.

(3)Cenovus’s non-operating interest held through Husky Oil Toledo Company.

(4)Cenovus’s non-operating interest held through Cenovus Energy US LLC and Cenovus GPCo LLC.

As of December 31, 2022, the Company’s remaining subsidiaries and partnerships each account for (i) less than 10 percent of the Company’s consolidated assets as at December 31, 2022 and (ii) less than 10 percent of the Company’s consolidated revenues for the year ended December 31, 2022. In aggregate, Cenovus’s subsidiaries and partnerships not listed above did not exceed 20 percent of the Company’s total consolidated assets or total consolidated revenues as at and for the year ended December 31, 2022.

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”). Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. We are the second largest Canadian-based crude oil and natural gas producer, with upstream operations in Canada and the Asia Pacific region, and the second largest Canadian-based refiner and upgrader, with downstream operations in Canada and the United States (“U.S.”).

Our upstream operations include oil sands projects in northern Alberta; thermal and conventional crude oil, natural gas and natural gas liquids (“NGLs”) projects across Western Canada; crude oil production offshore Newfoundland and Labrador; and natural gas and NGLs production offshore China and Indonesia. Our downstream operations include upgrading and refining operations in Canada and the U.S., and commercial fuel operations across Canada.

Our operations involve activities across the full value chain to develop, produce, refine, transport and market crude oil and natural gas in Canada and internationally. Our physically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil differentials and contribute to our net earnings by capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels.

In 2022, crude oil production from our Oil Sands assets averaged 586.6 thousand barrels per day and total upstream production averaged 786.2 thousand BOE per day. Downstream crude oil throughput was 493.7 thousand barrels per day.

Cenovus Energy Inc. – 2022 Annual Information Form 3

Three Year History

The following describes significant events and conditions that have influenced the development of Cenovus’s business during the last three financial years:

2020

•Environmental, social and governance (“ESG”) targets. In the first quarter, Cenovus announced ESG targets in four key ESG focus areas: climate and greenhouse gas (“GHG”) emissions, Indigenous engagement, land and wildlife and water stewardship.

•Response to the COVID-19 pandemic. In the first quarter, Cenovus took action to protect the health and safety of its staff and ensure the continuity of its business. Following the guidance of public health officials, the Company directed all staff who were able to do so to work from home, established mandatory self-isolation protocols and restricted travel policies. In addition, Cenovus implemented active health screening, physical distancing and advanced cleaning and sanitation measures at its field operations.

•Reduction of capital spending and suspension of crude-by-rail program. On March 9, 2020, Cenovus announced a reduction to its 2020 capital program of approximately 32 percent in response to the significant decline in world benchmark crude oil prices. Cenovus also announced the temporary suspension of the crude-by-rail program and the deferral of final investment decisions on major growth projects.

•Further reduction of capital spending and suspension of the dividend. On April 2, 2020, Cenovus announced a further reduction to its 2020 capital program of $150 million, for a total year-to-date reduction in the 2020 capital program of 43 percent, along with additional cost-saving measures including the temporary suspension of its dividend.

•Temporary additional credit facility liquidity. In April 2020, to further enhance its liquidity, the Company obtained commitments from several of its existing lenders for an additional $1.1 billion committed credit facility. On December 31, 2020, Cenovus cancelled the $1.1 billion committed credit facility prior to the closing of the Arrangement.

•Used dynamic storage to shift production into stronger price environment. In the second quarter of 2020, Cenovus curtailed its oil sands production, storing mobilized bitumen in its reservoirs in response to the significant decline in crude oil prices. Production was ramped up by approximately 60.0 thousand barrels per day in June and subsequent months in an improved price environment.

•Senior notes offering. On July 30, 2020, Cenovus completed a public offering in the U.S. of US$1.0 billion in 5.38 percent senior unsecured notes due 2025.

•Arrangement with Husky. On October 25, 2020, Cenovus and Husky announced the Arrangement, an all-stock transaction valued at $23.6 billion, inclusive of debt, which would combine the two companies.

•Alberta government curtailment program put on hold. While the government’s regulatory authority to curtail crude oil production extended through 2021, starting in December 2020, Alberta’s government lifted the monthly crude oil curtailment.

•Marten Hills asset sale. On December 2, 2020, Cenovus sold its Marten Hills heavy oil assets to Headwater Exploration Inc. (“Headwater”) for a combination of cash, common share equity consideration and share purchase warrants (the “Headwater Warrants”), while retaining a gross overriding royalty interest (“GORR”) in the property.

2021

•Cenovus and Husky combine. On January 1, 2021, Cenovus and Husky closed an all-stock transaction to combine the two companies. As a result of completing the Arrangement, Husky became a wholly-owned subsidiary of Cenovus. Husky common shareholders received 0.7845 of a Cenovus common share and 0.0651 of a Cenovus Warrant, in exchange for each Husky common share. This resulted in the issuance of 788.5 million common shares and 65.4 million Cenovus Warrants. Each whole Cenovus Warrant entitles the holder to acquire one common share at an exercise price of $6.54 at any time up to January 1, 2026. In addition, Husky preferred shareholders exchanged each Husky preferred share for one Cenovus preferred share with substantially identical terms. Cenovus filed a business acquisition report dated March 26, 2021, that provides further details relating to the Arrangement and is available on SEDAR at sedar.com and on EDGAR at sec.gov.

Cenovus Energy Inc. – 2022 Annual Information Form 4

•Disposition of assets. The Company completed several transactions to adjust its portfolio.

◦Marten Hills GORR interest. On May 18, 2021, Cenovus closed the sale of its GORR interest in the Marten Hills area of Alberta for cash proceeds of $102 million.

◦East Clearwater and Kaybob asset sales. Cenovus closed the sale of Conventional assets in the Kaybob area in July 2021 and in the East Clearwater area in August 2021 for combined gross proceeds of $82 million.

◦Headwater share sale. On October 14, 2021, Cenovus sold 50 million common shares of Headwater for gross proceeds of $228 million. The Headwater Warrants were exercised on December 23, 2021. As at December 31, 2021, Cenovus owned 15 million common shares of Headwater. Cenovus sold its 15 million common shares of Headwater on June 8, 2022.

◦Wembley asset sale. On November 30, 2021, Cenovus announced an agreement to sell the majority of its Montney assets in Wembley for cash proceeds of approximately $238 million. The sale closed on February 28, 2022.

◦Husky retail fuels network sale. On November 30, 2021, Cenovus announced agreements to sell 337 gas stations for aggregate cash proceeds of approximately $420 million. Cenovus retained its commercial fuels business, which includes approximately 170 cardlock, bulk plant and travel centre locations. The sales closed on September 13, 2022.

◦Tucker asset sale. On December 16, 2021, Cenovus announced an agreement to sell its Tucker asset for gross cash proceeds of$800 million. The sale closed on January 31, 2022.

◦Atlantic restructuring. Cenovus announced an agreement with its partners to restructure its working interests in the Atlantic region.

◦Terra Nova restructuring. On September 8, 2021, Cenovus’s working interest increased to 34 percent from 13 percent. The Company received $78 million, before closing adjustments, from exiting partners as a contribution towards future decommissioning liabilities related to the field. In addition, the Terra Nova Asset Life Extension (“ALE”) project is proceeding, extending the life of the field to 2033.

◦White Rose restructuring. In the third quarter of 2021, Cenovus entered into an agreement with Suncor Energy Inc. (“Suncor”) to decrease our working interest in the White Rose field and satellite extensions, pending the continuation of the West White Rose project. Cenovus would reduce its working interest in the original field from 72.5 percent to 60.0 percent and in the satellite extensions from 68.875 percent to 56.375 percent. On May 31, 2022, Cenovus and its partners announced it reached an agreement to restart the West White Rose project.

•Oil Sands Pathways to Net Zero initiative. On June 9, 2021, Cenovus announced the Oil Sands Pathways to Net Zero initiative, an alliance of peers working collectively with governments with a goal to achieve net zero GHG from oil sands operations by 2050.

•ESG target refresh. On December 8, 2021, Cenovus published its 2020 ESG report, including refreshed targets in five key ESG focus areas: climate and GHG emissions, water stewardship, biodiversity, Indigenous reconciliation, and inclusion and diversity.

•Credit facility consolidation and reduction. On August 18, 2021, $8.5 billion of committed credit facilities, including those assumed in the Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility. The committed revolving credit facility consists of a $2.0 billion tranche maturing on August 18, 2024, and a $4.0 billion tranche maturing on August 18, 2025.

•Senior notes offering. On September 13, 2021, Cenovus issued US$500 million of 2.65 percent senior unsecured notes due 2032 and US$750 million of 3.75 percent senior unsecured notes due 2052. Proceeds from the offering were used for debt reduction.

•Debt reduction. In 2021, Cenovus repurchased a principal amount of US$2.2 billion unsecured notes through a series of tender offers and redemptions under the indentures governing certain notes.

•Reinstated and increased dividend. In the first quarter, Cenovus reinstated its common share dividend and in November, the Company doubled its dividend to $0.035 per common share for the fourth quarter of 2021.

•Normal Course Issuer Bid (“NCIB”). On November 4, 2021, Cenovus announced that the TSX accepted the Company’s notice of intention to implement a NCIB to purchase for cancellation up to 146.5 million of the Company’s common shares. In 2021, Cenovus purchased 17 million common shares for $265 million.

Cenovus Energy Inc. – 2022 Annual Information Form 5

2022

•Acquisitions.

◦Sunrise. On August 31, 2022, Cenovus closed the acquisition of the remaining 50 percent interest in Sunrise (the “Sunrise Acquisition”) with BP Canada for net proceeds of $394 million, a variable payment with a maximum cumulative value of $600 million expiring in eight quarters subsequent to August 31, 2022 and Cenovus’s 35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador.

◦Toledo Refinery. On August 8, 2022, Cenovus announced an agreement to purchase the remaining 50 percent interest in the Toledo Refinery (the “Toledo Acquisition”) from BP Products North America (“BP”) giving Cenovus full ownership and operatorship and further integrating its heavy oil production and refining capabilities. The transaction is expected to close at the end of February 2023.

•Achieved first oil at Spruce Lake North. Spruce Lake North thermal plant achieved first oil in the third quarter of 2022.

•Commenced commissioning of the Superior Refinery. In December 2022, commissioning for the restart of the Superior Refinery commenced and will progress into the first quarter of 2023. The refinery was taken out of operation in 2018 following an explosion and fire. The restart of the refinery will increase total crude oil processing capacity by 50.0 thousand barrels per day.

•Received regulatory approval. In December 2022, Cenovus received regulatory approval to develop the Ipiatik asset in the Foster Creek area.

•Divestitures.

◦Tucker asset sale. On January 31, 2022, Cenovus sold its Tucker asset in the Oil Sands segment for net proceeds of $730 million.

◦Wembley asset sale. On February 28, 2022, Cenovus sold its Wembley assets in the Conventional segment for net proceeds of $221 million.

◦Restart of West White Rose project. On May 31, 2022, Cenovus and its partners reached an agreement to restart the West White Rose project in the Atlantic region offshore Newfoundland and Labrador. Cenovus transferred 12.5 percent of its working interest in the White Rose field and satellite extensions to Suncor.

◦Headwater share sale. On June 8, 2022, Cenovus sold its investment in Headwater for proceeds of $110 million.

◦Retail fuels network sale. On September 13, 2022, Cenovus closed the sale of 337 gas stations within its retail fuels network for net cash proceeds of $404 million.

•Partial suspension of the crude oil price risk management program. On April 4, 2022, Cenovus announced the suspension of its crude oil price risk management activities related to WTI. Given the strength of its balance sheet and liquidity, the Company determined these programs are no longer required to support financial resilience.

•2021 ESG Report. On July 28, 2022, Cenovus published its 2021 ESG report and continued to focus on its five key ESG areas: climate and GHG emissions, water stewardship, biodiversity, Indigenous reconciliation, and inclusion and diversity.

•First Nations Major Projects Coalition (“FNMPC”). On September 29, 2022, Cenovus joined the FNMPC’s Sustaining Partners Program. This partnership aims to advance FNMPC’s strategies that promote Indigenous inclusion in major developments and articulate Indigenous perspectives concerning ESG investment standards and sustainable business practices.

•Debt reduction. In 2022, Cenovus repurchased principal amounts of US$2.6 billion unsecured notes due between 2023 and 2043, and $750 million unsecured notes due in 2025.

•Increased base dividend. On April 26, 2022, Cenovus tripled the base dividend per common share from $0.035 to $0.105, or $0.42 annually, starting in the second quarter of 2022.

•Updated plan for increased shareholder returns. On April 27, 2022, Cenovus announced a revised capital allocation framework to return incremental cash to shareholders through continued share repurchases and/or the use of a variable dividend mechanism. Shareholder returns are dependent on reaching certain net debt targets and the amount of excess free funds flow.

•Variable dividend. In addition to the Company’s base dividend, Cenovus’s Board of Directors (the “Board”) declared a variable dividend of $0.114 per common share. The variable dividend was paid on December 2, 2022.

Cenovus Energy Inc. – 2022 Annual Information Form 6

•Renewal of NCIB. On November 7, 2022, the Company received approval from the TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period from November 9, 2022, to November 8, 2023. For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares through the NCIBs. From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares.

DESCRIPTION OF THE BUSINESS

BUSINESS SEGMENTS

As at December 31, 2022, the Company’s reportable segments were as follows:

Upstream Segments

•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

•Conventional, includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.

•Offshore, includes offshore operations, exploration and development activities in China and the East Coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Cenovus Energy Inc. – 2022 Annual Information Form 7

Downstream Segments

•Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.

•U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima Refinery and Superior Refinery, the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66) and the jointly-owned Toledo Refinery (jointly owned with operator BP). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel and jet fuel.

Corporate and Eliminations

Corporate and Eliminations, primarily includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada.

For the year ended December 31, 2022, consolidated revenues were $66.9 billion (2021 – $46.4 billion). Products with revenues that exceeded 15 percent of consolidated revenues in 2022 include crude oil in our upstream segment of $29.8 billion or 45 percent of consolidated revenues (2021 – $19.9 billion or 43 percent), gasoline in our downstream segment of $14.1 billion or 21 percent of consolidated revenues (2021 – $10.1 billion or 22 percent) and diesel and distillates in our downstream segment of $11.5 billion or 17 percent of consolidated revenues (2021 – $6.4 billion or 14 percent).

UPSTREAM

Oil Sands

As of December 31, 2022, Cenovus held bitumen and heavy oil rights of approximately 1.6 million gross acres (1.6 million net acres) within the Athabasca and Cold Lake regions of northern Alberta and Saskatchewan, as well as the exclusive rights to lease an additional 603 thousand gross acres on the Cold Lake Air Weapons Range, an active military base.

Development Approach

Cenovus uses steam-assisted gravity drainage (“SAGD”) technology to recover bitumen. The Company does not employ mining techniques for extraction and none of its bitumen reserves are suitable for extraction using mining techniques. SAGD involves injecting steam into the reservoir to enable bitumen to be pumped to the surface.

At Cenovus’s Lloydminster conventional heavy oil assets, the Company employs a combination of production technologies including cold heavy oil production with sand (“CHOPS”), horizontal wells and enhanced oil recovery (“EOR”). EOR is defined as the increased recovery from a crude oil pool achieved by artificial means or by the application of energy extrinsic to the pool.

Technology

Cenovus leverages innovation and technology across our operations to help further reduce our environmental impact, upgrade the tools and processes we use in our day-to-day operations, maximize our financial performance and enhance our product value. Additionally, the Company looks for opportunities to collaborate with others and accelerate the development of technologies to reduce our impact on air, land and water resources.

Foster Creek

Cenovus has a 100 percent working interest in Foster Creek, located on the Cold Lake Air Weapons Range, which is 72 kilometres northwest of Cold Lake, Alberta. Foster Creek produces from the McMurray formation, with a reservoir depth of up to 500 metres, using SAGD technology.

Bitumen production at Foster Creek averaged 191.0 thousand barrels per day in 2022 (2021 – 179.9 thousand barrels per day).

Cenovus Energy Inc. – 2022 Annual Information Form 8

Cenovus operates a 100-megawatt natural gas-fired cogeneration facility at Foster Creek. The steam and power generated by the facility is used within the SAGD operation and any excess power generated is sold into the Alberta power pool.

In December 2022, Cenovus received regulatory approval to develop the Ipiatik asset in the Foster Creek area. Cenovus has a 90 percent working interest in Ipiatik which has reservoir depths of up to 505 metres. The Ipiatik asset will provide future bitumen feedstock to the Foster Creek plant. Pad construction is expected to commence in 2024 with first steam expected in 2029.

Christina Lake

Cenovus has a 100 percent working interest in Christina Lake, which is located approximately 150 kilometres southeast of Fort McMurray, Alberta. Christina Lake produces from the McMurray formation, with a reservoir depth of up to 375 metres, using SAGD technology.

Bitumen production at Christina Lake averaged 246.5 thousand barrels per day in 2022 (2021 – 236.8 thousand barrels per day).

Cenovus operates a 100-megawatt natural gas-fired cogeneration facility at Christina Lake. The steam and power generated by the facility is used within the SAGD operation and any excess power generated is sold into the Alberta power pool.

Cenovus has a 100 percent working interest in Narrows Lake, which is located adjacent to Christina Lake and has a reservoir depth of up to 375 metres. In 2021, the Narrows Lake field commenced tieback into the Christina Lake plant and the work continued in 2022. The expansion of the Christina Lake development area to include Narrows Lake will provide future sustaining pad locations for feedstock into the Christina Lake plant. First steam from Narrows Lake is expected in 2025.

Sunrise

On August 31, 2022, Cenovus acquired the remaining 50 percent interest in Sunrise from BP Canada, giving Cenovus full ownership. Sunrise is located approximately 60 kilometres northeast of Fort McMurray, Alberta. Sunrise produces from the McMurray formation, with a reservoir depth of up to 200 metres, using SAGD technology. In 2022, bitumen production at Sunrise averaged 31.3 thousand barrels per day (2021 – 25.9 thousand barrels per day). Following the Sunrise Acquisition, bitumen production averaged 45.3 thousand barrels per day from September 1, 2022 to December 31, 2022.

Lloydminster Thermal

Lloydminster thermal consists of 12 producing thermal plants, which are 100 percent owned by Cenovus and produce bitumen. The plants are located in the Lloydminster region of Saskatchewan. Each plant has a number of production pads and uses SAGD technology. The Spruce Lake North thermal plant achieved first oil in September 2022. Production averaged approximately 12.0 thousand barrels per day in the fourth quarter. Total bitumen production from Lloydminster thermal averaged 99.9 thousand barrels per day in 2022 (2021 – 97.7 thousand barrels per day).

Lloydminster Conventional Heavy Oil

Lloydminster conventional heavy oil uses a combination of production technologies including CHOPS, horizontal wells and EOR in the Lloydminster region of Alberta and Saskatchewan. Heavy oil production averaged 16.3 thousand barrels per day in 2022 (2021 – 20.2 thousand barrels per day) and conventional natural gas production averaged 9.9 MMcf per day in 2022 (2021 –10.6 MMcf per day).

Husky Midstream Limited Partnership

The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power Assets Holdings Ltd. holding a 49 percent interest and CK Infrastructure Holdings Ltd. holding a 16 percent interest in HMLP. HMLP has approximately 2,300 kilometres of pipeline in the Lloydminster region and 5.9 million barrels of storage capacity at Hardisty and Lloydminster.The assets play an integral role in the transportation of heavy oil production to end markets by providing connections to the Lloydminster Upgrader and the Lloydminster Refinery, third-party terminals and pipelines through the Hardisty terminal.

The Lloydminster terminal, with a total storage capacity of 1.0 million barrels, serves as a hub for the gathering systems. The pipeline systems transport blended heavy crude oil to the Lloydminster terminal for delivery to the Company’s Lloydminster Upgrader and Lloydminster Refinery. Blended heavy crude oil from the field and synthetic crude oil from the upgrading operations are transported south to Hardisty, Alberta to a connection with the major export trunk pipelines.

The Hardisty terminal, with a total storage capacity of 4.9 million barrels, acts as the exclusive blending hub for WCS, the largest heavy oil benchmark pricing point in North America.

In addition, HMLP owns and Cenovus operates the Ansell Corser gas processing plant located in west-central Alberta. The gas processing plant has a capacity of 120 MMcf per day and supports our Conventional segment.

HMLP has its own board of directors and independent financing that supports both growth projects under construction and planned future expansions.

Cenovus Energy Inc. – 2022 Annual Information Form 9

Conventional

Cenovus’s Conventional assets include approximately 6.4 million net acres with an average 82 percent working interest. In addition, the Conventional assets include interests in numerous natural gas processing facilities with an estimated net processing capacity of 1.2 Bcf per day.

Elmworth-Wapiti

Cenovus is one of the largest producers in the Elmworth-Wapiti area, located in northwest Alberta and northeast British Columbia. As of December 31, 2022, Cenovus held leasehold rights of 1.2 million net acres in this area.

The Elmworth-Wapiti area provides production potential from more than 10 target formations, with the most prospective being the Falher and Dunvegan formations, having reservoir depths up to 3,000 metres. This is a mature area that was historically developed with conventional vertical well technology. Cenovus has shifted to horizontal drilling in its development programs with a view to unlock the vast resource potential in the tight sand plays.

The primary processing facility in the area is the Cenovus-operated Elmworth plant. The Company holds significant working interests in four other major natural gas processing facilities in the region.

On February 28, 2022, Cenovus sold its Wembley assets in the Elmworth area for net proceeds of $221 million.

Net Production for the Elmworth-Wapiti Area	2022	2021
Light Crude Oil (Mbbls/d)	1.8	1.7
NGLs (Mbbls/d)	8.0	8.1
Conventional Natural Gas (MMcf/d)	144.7	151.5
TotalProduction(MBOE/d)	33.9	35.1

Kaybob-Edson

As of December 31, 2022, Cenovus held leasehold rights of approximately 1.0 million net acres in the Kaybob-Edson area, which is situated in west-central Alberta. Target development is focused in the Cretaceous formations with reservoir depths ranging from 2,500 metres to 3,200 metres. Cenovus owns and operates two major natural gas facilities in the area, the Peco and Wolf plants, in addition to holding significant working interest in two other major natural gas processing facilities in the region. The Ansell Corser plant is owned by HMLP and operated by Cenovus.

Net Production for the Kaybob-Edson Area	2022	2021
Light Crude Oil (Mbbls/d)	1.1	1.1
NGLs (Mbbls/d)	7.2	7.4
Conventional Natural Gas (MMcf/d)	237.7	240.2
TotalProduction(MBOE/d)	47.9	48.6

Clearwater

The Clearwater area is situated in west-central Alberta, south of Kaybob-Edson. As of December 31, 2022, Cenovus held leasehold rights of approximately 0.6 million net acres. Cenovus’s assets in the Clearwater area target the Cretaceous and Jurassic formations with reservoirs at depths ranging from 1,790 metres to 3,000 metres producing both NGLs and natural gas. This is a mature area historically developed with conventional vertical well technology, providing Cenovus with a series of lower risk horizontal drilling development programs. Cenovus operates two major natural gas processing facilities in the area, the Sand Creek and Alder plants.

Net Production for the Clearwater Area	2022	2021
Light Crude Oil (Mbbls/d)	2.2	2.3
NGLs (Mbbls/d)	5.3	7.2
Conventional Natural Gas (MMcf/d)	101.5	119.0
TotalProduction(MBOE/d)	24.4	29.3

Cenovus Energy Inc. – 2022 Annual Information Form 10

Rainbow Lake

Rainbow Lake is located approximately 900 kilometres northwest of Edmonton, Alberta. As of December 31, 2022, Cenovus held leasehold rights of approximately 0.4 million net acres. Rainbow Lake consists of two distinct areas, Rainbow Lake and Bivouac, with assets including two natural gas plants, multiple field facilities and compressor stations, and over 1,100 kilometres of pipelines for gathering, injection and disposal operations. Rainbow Lake makes up the majority of the asset production, primarily from the deeper Devonian formations, such as Keg River and Muskeg with reservoir depths ranging from 1,700 metres to 2,000 metres. Bivouac produces mainly sweet gas from the Jean Marie formation with reservoir depths up to 1,400 metres.

Net Production for the Rainbow Lake Area	2022	2021
Light Crude Oil (Mbbls/d)	2.4	3.2
NGLs (Mbbls/d)	3.3	2.9
Conventional Natural Gas (MMcf/d)	92.2	87.0
Total Production(MBOE/d)	21.0	20.6

The Company holds a 50 percent interest in a 90-megawatt natural gas-fired cogeneration facility adjacent to its Rainbow Lake processing plant. The cogeneration facility produces electricity and steam for the Rainbow Lake processing plant, and any excess power generated is sold into the Alberta power pool.

Offshore

Asia Pacific

China

Liwan Gas Project

The Liwan Gas Project is located approximately 300 kilometres southeast of the Hong Kong Special Administrative Region and was the first deepwater gas project offshore China. The Liwan Gas Project includes the natural gas discoveries at the Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields within the Contract Area 29/26 located in the Pearl River Mouth Basin of the South China Sea. Cenovus has a 49 percent working interest in the Liwan 3-1 and Liuhua 34-2 fields as well as a 75 percent working interest in the Liuhua 29-1 field. The remaining working interest is owned by China National Offshore Oil Corporation through subsidiaries (“CNOOC”).

The Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields share a subsea production system, subsea pipeline transportation and onshore gas processing infrastructure. Cenovus is the operator of the deepwater infrastructure and CNOOC operates the shallow water facilities including the platform, subsea pipeline to shore and the Gaolan Onshore Gas Plant (“OSGP”). The OSGP extracts condensate and NGLs and compresses and transports the natural gas to commercial markets in mainland China.

In 2022, the Company’s working interest share of production from the Liwan Gas Project was 230.1 MMcf per day of conventional natural gas and 9.8 thousand barrels per day of NGLs (2021 – 244.1 MMcf per day of conventional natural gas and 10.0 thousand barrels per day of NGLs).

Block 15/33

The Company holds a production sharing contract (“PSC”) for Block 15/33 which is located in the Pearl River Mouth Basin of the South China Sea, east of the Leizhou Peninsula, approximately 140 kilometres southeast of the Hong Kong Special Administrative Region. Cenovus is the operator of the block and has a working interest of 100 percent.

In 2022, Cenovus decided not to fund the development at Block 15/33 in China.

Block 16/25

The Company holds a PSC for Block 16/25 which is located in the Pearl River Mouth Basin of the South China Sea, east of the Leizhou Peninsula, about 150 kilometres southeast of the Hong Kong Special Administrative Region. The Company is the operator of the block with a 100 percent working interest during the exploration phase.

An amendment agreement signed in 2021 between the Company and CNOOC extended the first phase of the exploration period to December 31, 2022. As of the end of 2022, no decision was reached to terminate the PSC. Discussions are underway to complete the remaining obligatory exploration well in an area to be agreed by all parties.

Block 23/07

Cenovus held a PSC for the 23/07 exploration block in the Beibu Gulf area of the South China Sea, west of the Leizhou Peninsula. The PSC was terminated in 2022.

Cenovus Energy Inc. – 2022 Annual Information Form 11

Taiwan

Block DW-1

The Company and CPC Corporation, through a joint agreement, have rights to an exploration block covering approximately 7,700 square kilometres located southwest of the Taiwan Area offshore. The Company holds a 75 percent working interest during exploration. CPC Corporation has the right to participate in any future development programs up to a 50 percent interest by paying its proportionate share of all development costs. During 2022, the three-dimensional seismic exploration period was extended for another two years and expires on December 17, 2024.

Indonesia

Madura Strait

The Company has a 40 percent interest in the HCML joint venture, which holds the Madura Strait PSC. The Madura Strait PSC encompasses approximately 2,500 square kilometres in the Madura Strait area, located off the coast of East Java, Indonesia.

The Madura Strait includes the producing BD, MBH and MDA shallow water fields. It also contains shallow water MAC and MDK fields which are under development and are expected to start production in 2023 and 2025, respectively.

In 2022, the Company’s working interest share of production was 47.6 MMcf per day of conventional natural gas and 2.6 thousand barrels per day of condensate (2021 – 41.2 MMcf per day and 2.7 thousand barrels per day, respectively).

Liman

The Company signed a PSC in December 2021 with the Government of Indonesia for the Liman contract area, which is located onshore in East Java, Indonesia. The Company holds a 100 percent working interest during the exploration phase. Pertamina, an Indonesian state-owned enterprise, has the right to farm in on a business-to-business basis, for 15 percent of the PSC under government regulations.

Atlantic

Canada

Terra Nova Field

The Terra Nova field is located approximately 350 kilometres southeast of St. John’s, Newfoundland and Labrador in the Jeanne d’Arc Basin. The Terra Nova field is divided into three distinct areas, known as the Graben, the East Flank and the Far East. Cenovus has a working interest in the Terra Nova field of 34 percent and is not the operator. Production at the Terra Nova field has been suspended since December 2019. In September 2021, Cenovus and its partners finalized agreements (the “Atlantic Restructuring”) to restructure its working interest in Terra Nova, increasing Cenovus’s working interest to 34 percent from 13 percent, and if a decision was taken to restart the West White Rose project, would reduce the Company’s working interest in the White Rose field. The agreements included the decision to move forward with the Asset Life Extension Project which is expected to extend production life by approximately 10 years and produce an additional 70 million barrels, 23.8 million barrels net to Cenovus. The Terra Nova field is expected to resume production in the second quarter of 2023.

White Rose Field and Satellite Extensions

The White Rose field is located about 350 kilometres east off the coast of Newfoundland and Labrador on the eastern flank of the Jeanne d’Arc Basin. The Company is the operator of the main White Rose field and satellite tiebacks, including the North Amethyst, West White Rose and South White Rose extensions. The North Amethyst and South White Rose extensions were developed via subsea tieback infrastructure which produce back to the SeaRose floating production storage and offloading unit (“FPSO”).

The West White Rose project is designed to use a drilling and wellhead platform to access resources to the west of the main field and will also produce back to the SeaRose FPSO. On May 31, 2022, Cenovus and its partners announced the restart of the West White Rose project offshore Newfoundland and Labrador. As part of the 2021 Atlantic Restructuring plan, the decision to restart the West White Rose project on May 31, 2022, resulted in the transfer of a 12.5 percent working interest in the White Rose field and satellite extensions from Cenovus to Suncor, lowering Cenovus’s working interest to 60 percent in the main field and 56.375 percent in the satellite extensions. The West White Rose project is anticipated to have peak production of 80 thousand barrels per day (45 thousand barrels per day, net to Cenovus) with first oil expected in the first half of 2026.

In 2022, light crude oil production averaged 11.6 thousand barrels per day (2021 – 14.1 thousand barrels per day).

Cenovus Energy Inc. – 2022 Annual Information Form 12

East Coast Exploration

The Company holds working interests ranging from six percent to 100 percent in multiple discovery areas and 22 percent to 100 percent in exploration licenses within the Jeanne d’Arc Basin, Baffin Island and Eastern Newfoundland regions. On August 31, 2022 Cenovus closed the acquisition of Sunrise and disposed of its 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador, which includes the Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries in the Flemish Pass Basin.

DOWNSTREAM

Canadian Manufacturing

The following table summarizes key operational results for the assets:

	2022	2021
Heavy Crude Oil Throughput Capacity (Mbbls/d)	110.5	110.5
Lloydminster Upgrader	81.5	81.5
Lloydminster Refinery	29.0	29.0
Heavy Crude Oil Throughput(Mbbls/d)	92.9	106.5
Lloydminster Upgrader	68.7	79.0
Lloydminster Refinery	24.2	27.5
Crude Utilization (1)(percent)	84	96
Refined Products Output (2)(Mbbls/d)	93.4	107.9
Distillate	9.3	10.0
Synthetic Crude Oil	46.0	54.9
Asphalt	13.5	15.5
Other	24.6	27.5
Crude-by-Rail Operations
Volumes Loaded (3)(Mbbls/d)	1.8	12.1
Ethanol Production (millions of litres/d)	0.8	0.7
Fuel Sales Volumes (4) (5) (millions of litres/d)	6.2	6.9
Gasoline	2.0	2.6
Diesel Fuel	4.2	4.2
Liquefied Petroleum Gas	—	0.1

(1)Based on crude throughput volumes and results of operations at the Lloydminster Upgrader and Refinery.

(2)Includes refined product output at the Lloydminster Upgrader and Refinery.

(3)Volumes transported outside of Alberta.

(4)Total fuel sales volumes include the historical retail business and the remaining commercial fuels business. For the period of September 14, 2022 to December 31, 2022, the commercial fuels business averaged 0.7 million litres per day of gasoline sales volumes and 4.6 million litres per day of diesel fuel sales volumes, for a total of 5.3 million litres per day of sales volumes.

(5)Fuel sales volumes include the sale of refined petroleum products purchased from third parties and those produced at our Lloydminster Upgrader.

Lloydminster Upgrader

The Lloydminster Upgrader, located outside Lloydminster, Saskatchewan, is designed to process blended heavy crude oil feedstock (including bitumen), creating Husky Synthetic Blend (“HSB”), ultra-low sulphur diesel and other ancillary products. In addition, the upgrader recovers diluent from the feedstock for reuse in the Company’s heavy crude oil production assets and transportation. Synthetic crude oil is used as refinery feedstock for the production of transportation fuels in Canada and the U.S.

Lloydminster Refinery

The Lloydminster Refinery, located in Lloydminster, Alberta, processes blended heavy crude oil into asphalt products used in road construction and maintenance. The Lloydminster Refinery also produces condensate, bulk distillates and industrial products. Condensate is removed and re-circulated into HMLP’s pipeline network as diluent. Distillates are transferred to the Lloydminster Upgrader and blended into the HSB stream or sold as industrial products. Industrial products are a blend of medium and light distillate and vacuum gas oil, which are typically sold directly to customers as refinery feedstock, drilling and well-fracturing fluids, or used in asphalt cutbacks and emulsions.

Cenovus Energy Inc. – 2022 Annual Information Form 13

Due to the seasonal demand for asphalt products, many asphalt refineries typically operate at full capacity only during the paving season in Canada and the northern U.S. The Company has implemented various strategies to increase refinery throughput outside of the paving season, such as increasing storage capacity and developing U.S. markets for asphalt products. This allows the Lloydminster Refinery to run at or near full capacity throughout the year.

In addition to sales directly from the Lloydminster Refinery, the Company owns an asphalt distribution network composed of four asphalt terminals located in: Kamloops, British Columbia; Edmonton, Alberta; Yorkton, Saskatchewan; and Winnipeg, Manitoba. The Company also owns an emulsion plant located in Saskatoon, Saskatchewan.

Bruderheim Crude-by-Rail Terminal

The Company owns a crude-by-rail loading facility near Edmonton, Alberta. The Bruderheim crude-by-rail terminal has a storage tank capacity of 240.0 thousand barrels and a loading capacity of 120.0 thousand barrels per day and is part of the Company’s strategy to create additional transportation options for our products and is designed to help us capture global prices for our crude oil production. The Company has hired a third-party service provider to assist in operating the rail terminal. The Company leases a fleet of coiled and insulated rail cars to safely transport our products to market.

Ethanol Plants

The Company owns and operates two ethanol plants, located in Lloydminster, Saskatchewan and Minnedosa, Manitoba. Fuel grade ethanol is produced from grain-based feedstock. Each ethanol plant has an annual nameplate capacity of 130 million litres.

The Lloydminster ethanol plant captures carbon dioxide for use in the Company’s Lloydminster conventional heavy oil assets and ethanol produced at the plant has a low carbon intensity designation. At the Minnedosa ethanol plant, the Company is progressing a Carbon Capture and Sequestration project to also achieve lower carbon intensity ethanol production.

Commercial Fuels Business

In September 2022, Cenovus divested the majority of its retail fuels network, selling 337 gas stations. Cenovus retained its commercial fuels business, which includes approximately 170 cardlock, bulk plant and travel centre locations. Cenovus’s commercial operating model is balanced by corporate owned/dealer operated and branded dealer-owned-and-operated sites. The network consists of travel centres and cardlocks serving urban and rural markets across Canada and bulk distributors offering direct sales to commercial and agricultural markets in the prairie provinces.

The following table shows the number of locations by province as at December 31, 2022:

	British Columbia	Alberta	Saskatchewan	Manitoba	Ontario	Quebec	Nova Scotia	Total
Cardlocks	34	24	4	7	24	6	1	100
Bulk Plants	3	8	2	1	—	—	—	14
Travel Centres (1)	15	16	3	3	19	—	—	56
Total	52	48	9	11	43	6	1	170

(1)Includes five retail locations.

Cenovus Energy Inc. – 2022 Annual Information Form 14

U.S. Manufacturing

The following table summarizes key operational results for the refineries:

	2022	2021
Crude Oil Throughput Capacity (Mbbls/d)	552.5	502.5
Lima Refinery	175.0	175.0
Superior Refinery (1)	50.0	—
Toledo Refinery (2)	80.0	80.0
Wood River and Borger Refineries (2)	247.5	247.5
Crude Oil Throughput (Mbbls/d)	400.8	401.5
Lima Refinery	157.9	126.9
Toledo Refinery (2)	36.3	69.9
Wood River and Borger Refineries (2)	206.6	204.7
Throughput by Product (Mbbls/d)
Heavy Crude Oil	116.1	138.7
Light and Medium Crude Oil	284.7	262.8
Crude Utilization (3)(percent)	80	80
Refined Products Output (Mbbls/d)	420.5	418.6
Gasoline	200.0	205.3
Distillate	153.5	145.3
Other	67.0	68.0

(1)The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d and is not included in the crude utilization calculation.

(2)Represents Cenovus’s 50 percent of Wood River, Borger and Toledo refinery operations.

(3)Based on crude oil name plate capacity. Excludes the permitted capacity of Superior.

Lima Refinery

The Lima Refinery is located in Lima, Ohio, approximately 150 kilometres northwest of Columbus, Ohio. The Lima Refinery processes both light sweet crude oil and heavy crude oil feedstock sourced from the U.S. and Canada, which includes Canadian synthetic crude oil, including HSB produced by the Lloydminster Upgrader. The Lima Refinery produces low-sulphur gasoline, gasoline blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products. The feedstocks are received via the Mid-Valley and Marathon Pipelines, and the refined products are transported via the Buckeye, Inland and Energy Transfer Partners pipeline systems and by railcar to primary markets in Ohio, Illinois, Indiana, Pennsylvania and southern Michigan.

Production at the Lima Refinery averaged 77.4 thousand barrels per day of gasoline, 65.0 thousand barrels per day of distillates and 21.4 thousand barrels per day of other products in 2022 (2021 – 62.2 thousand barrels per day, 50.7 thousand barrels per day and 18.3 thousand barrels per day, respectively). Approximately 13 percent of the crude oil processed at the Lima refinery consisted of Canadian heavy crude oil in 2022 (2021 – eight percent).

Toledo Refinery

The Toledo Refinery is located near Toledo, Ohio. Products from the refinery include gasoline, diesel, jet fuel and other products. A portion of the Toledo Refinery’s capacity is used to process high total acid number crude oil to support production from Sunrise. The feedstocks are received via the Mid-Valley, Marathon and Enbridge Mainline Pipelines, and the refined products are transported via the Buckeye, Inland and Energy Transfer Partners pipeline systems and by barge and railcar to primary markets in Ohio, Illinois, Indiana, Pennsylvania and southern Michigan.

On August 8, 2022, Cenovus announced an agreement to purchase the remaining 50 percent interest in the Toledo Refinery from BP, giving Cenovus full ownership and further integrating its heavy oil production and refining capabilities. The transaction is expected to close at the end of February 2023.

On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state. Production at the Toledo Refinery averaged 21.8 thousand barrels per day of gasoline, 11.9 thousand barrels per day of distillates and 6.0 thousand barrels per day of other products in 2022 (2021 – 42.5 thousand barrels per day, 22.6 thousand barrels per day and 9.7 thousand barrels per day, respectively). Of the crude oil processed at the Toledo Refinery in 2022, approximately 43 percent consisted of Canadian heavy crude oil and approximately 5 percent consisted of U.S. heavy crude oil (2021 – 38 percent and 11 percent, respectively).

Cenovus Energy Inc. – 2022 Annual Information Form 15

Wood River Refinery

The Wood River Refinery ranks in the top 10 percent of approximately 130 refineries in the U.S. based on total crude oil capacity. It is located in Roxana, Illinois, approximately 25 kilometres northeast of St. Louis, Missouri. The Wood River Refinery processes light low-sulphur and heavy high-sulphur crude oil that it receives via the Keystone, Capline, Ozark and Capwood Pipelines to produce gasoline, diesel and jet fuel, petrochemical feedstock as well as petroleum coke and asphalt. The gasoline, diesel and jet fuel are transported via the Explorer, Buckeye, and Marathon Pipelines to markets in the upper U.S. Midwest. Other products are transported via pipeline, truck, barge and railcar to various markets.

In December 2022, an incident occurred at the Wood River Refinery that reduced throughput. Crude utilization has steadily increased since the first week of January 2023, and the refinery is currently operating at a substantial proportion of normal throughput. The refinery is expected to return to normal rates in the second quarter of 2023. The Wood River Refinery’s total stated crude oil processing capacity for 2022 was 346.0 thousand barrels per day. Cenovus’s share of production at the Wood River Refinery averaged 64.9 thousand barrels per day of gasoline, 49.0 thousand barrels per day of distillates and 31.7 thousand barrels per day of other products in 2022 (2021 – 65.9 thousand barrels per day, 47.1 thousand barrels per day and 33.2 thousand barrels per day, respectively).

Borger Refinery

The Borger Refinery is located in Borger, Texas, approximately 80 kilometres north of Amarillo, Texas. The Borger Refinery processes mainly medium and heavy high-sulphur crude oil that it receives via the WA/80 and Borger Express pipelines to produce gasoline, diesel and jet fuel, along with solvents and other products. The refined products are transported via the Denver, Powder River, Amarillo and Gold Line Pipelines and by truck and railcar to markets in Texas, New Mexico, Colorado and the U.S. mid-continent.

The Borger Refinery’s total stated crude oil processing capacity for 2022 was 149.0 thousand barrels per day. Cenovus’s share of production at the Borger Refinery averaged 35.9 thousand barrels per day of gasoline, 27.6 thousand barrels per day of distillates and 7.9 thousand barrels per day of other products in 2022 (2021 – 34.7 thousand barrels per day, 25.0 thousand barrels per day and 6.8 thousand barrels per day, respectively).

Superior Refinery

The Superior Refinery is located in Superior, Wisconsin, approximately 250 kilometres northeast of Minneapolis, Minnesota. On April 26, 2018, the Superior Refinery experienced an incident while preparing for a major turnaround and was taken out of operation. The rebuild work commenced in March 2019 and commissioning for restart of the refinery started in December 2022 and will progress in the first quarter of 2023. Cenovus recovered the majority of the rebuild investment through insurance proceeds. The refinery has associated infrastructure including five storage and distribution terminals that are strategically located throughout the northern U.S. See the Storage and Distribution Network section below for details.

The Superior Refinery has a stated crude oil permitted capacity of 50.0 thousand barrels per day, including capability to process up to 34.0 thousand barrels per day of heavy oil while producing asphalt, gasoline and diesel.

Storage and Distribution Network

The Company has refined product storage and a U.S. asphalt distribution network composed of five terminals. These terminals include: the Superior Products Terminal in Superior, Wisconsin (where refinery products are unloaded); the Duluth Terminal in Duluth/Esko, Minnesota (storage capacity – 180.0 thousand barrels); the Duluth Marine Terminal in Duluth, Minnesota (storage capacity – 14.0 thousand barrels); the Rhinelander Asphalt Terminal in Rhinelander, Wisconsin (storage capacity – 157.0 thousand barrels); and the Crookston Asphalt Terminal in Crookston, Minnesota (storage capacity – 136.0 thousand barrels). In addition, the Superior Refinery has a working tank capacity of 2.6 million barrels. The Company also markets asphalt from independently operated terminals located in the states of Minnesota, Wisconsin and Ohio.

COMPETITIVE CONDITIONS

All aspects of the energy industry are highly competitive, including attracting and retaining skilled and knowledgeable personnel. For further information on the competitive conditions affecting Cenovus, refer to the section entitled Risk Management and Risk Factors in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and available on SEDAR at sedar.com and EDGAR at sec.gov.

ENVIRONMENTAL PROTECTION

All phases of crude oil, natural gas, NGLs and refining operations are subject to environmental regulation pursuant to a variety of federal, provincial, territorial, state, regional and municipal laws and regulations in the jurisdictions in which Cenovus operates. For further information on the environmental regulations affecting Cenovus, refer to the section entitled Risk Management and Risk Factors in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and available on SEDAR at sedar.com and EDGAR at sec.gov.

Cenovus Energy Inc. – 2022 Annual Information Form 16

CODE OF BUSINESS CONDUCT AND ETHICS

Cenovus has established policies and standards relating to the conduct of business in a safe, ethical, legal and sustainable manner. Cenovus’s commitment in these areas is reflected in the Code of Business Conduct & Ethics (the “Code”) which is approved by the Board of Directors, our highest level of governance. The Code applies to the Company’s directors, officers, employees, and contractors who are regularly required to review the Code to confirm they understand their individual responsibilities and that they conform to its requirements. Suppliers who conduct activities for, or on behalf of, Cenovus are expected to review the Code and align with the principles and guidance it provides. The Code addresses Cenovus’s expectations concerning its values and reputation, acting with integrity (including the Company’s approach to lobbying and public advocacy), responsible information use, compliance with laws and regulations and speaking up about deviations from the Code. The Code uses plain language and includes a message from Cenovus’s President & Chief Executive Officer and examples to address the expectations of the Code. The Code is readily accessible on Cenovus’s intranet and on the Company’s website at cenovus.com.

Sustainability Policy

Cenovus’s Sustainability Policy addresses business conduct to help ensure the Company’s activities are undertaken in a responsible, transparent and respectful manner and in compliance with all applicable laws, regulations and industry standards in the jurisdictions in which Cenovus operates. The Sustainability Policy specifically references the following matters: governance and leadership, people, environment, stakeholder engagement, Indigenous reconciliation and community involvement and investment.

With respect to the environment, the Sustainability Policy provides that Cenovus recognizes the importance of: integrating environmental considerations into Cenovus’s business plans, spending decisions, performance management, project development, operations, communications and stakeholder relations. It also provides for the tracking and reporting on a broad range of environmental metrics in respect of Cenovus limiting its impact on climate, air, water, land and wildlife by investing in technology, continuously improving its operating practices and collaborating with third parties to find innovative solutions to minimize Cenovus’s environmental impact and maximize business value.

With respect to social aspects, the Sustainability Policy provides that Cenovus recognizes the importance of prioritizing the health and safety of all workers involved in its operations, as well as the residents of the communities where Cenovus works. In addition, it discusses the importance of treating workers with dignity, fairness and respect in order to support an inclusive and diverse workplace and evidences Cenovus’s support for the principles of the Universal Declaration of Human Rights. The Sustainability Policy also addresses the importance of Cenovus fostering positive relationships with Indigenous communities and other stakeholders through communication based on honesty, trust and respect with the objective of building and maintaining long-term, mutually beneficial relationships. In furtherance of this, and in an effort to create a positive impact for both Cenovus and the communities in which it operates, the Sustainability Policy also acknowledges the importance of investments by Cenovus in organizations and initiatives that improve people’s quality of life.

Additional Policy Information

In addition to the Code and Sustainability Policy, Cenovus has established other policies, including the Human Rights and Indigenous Relations policies, and practices that in some instances relate to environmental or social aspects of Cenovus’s business. The Human Rights Policy formalizes our commitment to human rights, reflects our values and behaviors and further supports the sustainable operation of our business. The Indigenous Relations Policy aims to ensure Indigenous relations across the Company are supported by a consistent approach based on respect, honesty and integrity. Cenovus’s directors, management, employees and contractors are periodically required to complete policy training to review and commit to the Sustainability Policy, the Code, and other key policies and standards. Stakeholders, employees and contractors are encouraged to report any business conduct concerns, including violations of applicable laws or any Cenovus policy, through the Company’s anonymous Integrity Helpline. Employees and contractors may also report any such concerns to their supervisor, a human resources business partner or a member of the Investigations Committee.

The aforementioned policies are accessible on the Company’s website at cenovus.com, as is Cenovus’s ESG report. The ESG report is published annually to detail management’s efforts and performance across environment, social and governance topics that are important to its stakeholders.

Cenovus Energy Inc. – 2022 Annual Information Form 17

EMPLOYEES

The following table summarizes Cenovus’s full-time equivalent (“FTE”) employees as at December 31, 2022:

	2022
Upstream Operations	2,766
Downstream Operations	1,629
Corporate (1)	1,603
Total FTE Employees	5,998

(1)    Includes employees within Corporate and Operations Services, Finance and Risk, People and Services, Strategy and Corporate Development, Sustainability and Stakeholder Engagement, and Legal.

Cenovus also engages contractors and service providers. For further information on employee and other workforce related risks affecting Cenovus, refer to the section entitled Risk Management and Risk Factors in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and available on SEDAR at sedar.com and EDGAR at sec.gov.

RISK FACTORS

A discussion of risk factors can be found in the section entitled Risk Management and Risk Factors in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and is available on SEDAR at sedar.com and EDGAR at sec.gov.

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

As a Canadian issuer, Cenovus is subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of the Company’s reserves in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”).

As at December 31, 2022, the Company’s reserves were located in Canada, China and Indonesia. Cenovus retained two independent qualified reserves evaluators (“IQREs”), McDaniel & Associates Consultants Ltd. (“McDaniel”) and GLJ Ltd. (“GLJ”), to evaluate and prepare reports on 100 percent of its bitumen, heavy crude oil, light crude oil and medium crude oil combined (“light and medium oil”), NGLs, conventional natural gas and shale gas proved and probable reserves. McDaniel evaluated approximately 94 percent of Cenovus’s total proved reserves, located in Canada (in Alberta, Saskatchewan and Newfoundland and Labrador), China and Indonesia. GLJ evaluated approximately six percent of the Company’s total proved reserves, located in Alberta and British Columbia, Canada.

The Safety, Sustainability and Reserves Committee (“SSR Committee”), composed entirely of independent directors, reviews, among other things, the qualifications and appointment of the IQREs, the procedures for providing information to the IQREs and the procedures relating to the disclosure of information with respect to oil and gas activities. The SSR Committee meets independently with the management of Cenovus and each IQRE to determine whether any restrictions affected the ability of the IQREs to report on the reserves data without reservation. In addition, the SSR Committee reviews the reserves data and the report of the IQREs and provides a recommendation regarding approval of the reserves disclosure to the Board.

Classifications of reserves as proved or probable are only attempts to define the degree of certainty associated with the estimates. There are numerous uncertainties inherent in estimating quantities of petroleum reserves. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. Readers should review the definitions and information contained in “Additional Notes to Reserves Data Tables”, “Definitions” and “Pricing Assumptions” in conjunction with the reserves disclosure. The reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates disclosed. For additional information, see the section entitled Risk Management and Risk Factors in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF, and is available on SEDAR at sedar.com and EDGAR at sec.gov.

Cenovus’s reserves data and other oil and gas information contained in this AIF is dated February 14, 2023, with an effective date of December 31, 2022. McDaniel’s and GLJ’s preparation date of the information is January 21, 2023.

Disclosure of Reserve Data

The reserves data presented summarizes the Company’s bitumen, heavy crude oil, light and medium oil, NGLs, conventional natural gas, shale gas and total reserves, and the net present value (“NPV”) and future net revenue (“FNR”) for these reserves. The reserves data uses forecast prices and costs prior to provision for interest, general and administrative expenses or the impact of any hedging activities. Estimates of FNR have been presented on a before and after income tax basis.

Cenovus Energy Inc. – 2022 Annual Information Form 18

Summary of Oil and Gas Reserves as at December 31, 2022

Gross Reserves (1)	Bitumen (2) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (3) (Bcf)	Total (MMBOE)
Canada
Proved
Developed Producing	1,012	17	51	1,253	1,289
Developed Non-Producing	138	21	2	45	168
Undeveloped	4,442	4	13	382	4,523
Total Proved	5,592	42	66	1,680	5,980
Probable	2,448	129	35	897	2,762
Total Proved Plus Probable	8,040	171	101	2,577	8,742
China
Proved
Developed Producing	—	—	12	331	67
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	12	331	67
Probable	—	—	2	65	13
Total Proved Plus Probable	—	—	14	396	80
Indonesia (4)
Proved
Developed Producing	—	—	4	183	35
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	4	183	35
Probable	—	—	2	67	12
Total Proved Plus Probable	—	—	6	250	47
Total Company
Proved
Developed Producing	1,012	17	67	1,767	1,391
Developed Non-Producing	138	21	2	45	168
Undeveloped	4,442	4	13	382	4,523
Total Proved	5,592	42	82	2,194	6,082
Probable	2,448	129	39	1,029	2,787
Total Proved Plus Probable	8,040	171	121	3,223	8,869

(1)Cenovus’s interest (operated or non-operated) before deduction of royalties and excludes royalty interests.

(2)Includes heavy crude oil that is not material, representing less than one percent of bitumen on a total proved plus probable basis.

(3)Includes shale gas that is not material representing less than one percent of conventional natural gas on a total proved plus probable basis.

(4)Includes Cenovus’s 40 percent interest in HCML.

Cenovus Energy Inc. – 2022 Annual Information Form 19

Net Reserves (1)	Bitumen (2) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (3) (Bcf)	Total (MMBOE)
Canada
Proved
Developed Producing	758	15	42	1,140	1,005
Developed Non-Producing	100	18	1	40	126
Undeveloped	3,325	3	10	345	3,396
Total Proved	4,183	36	53	1,525	4,527
Probable	1,756	108	29	802	2,026
Total Proved Plus Probable	5,939	144	82	2,327	6,553
China
Proved
Developed Producing	—	—	11	314	64
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	11	314	64
Probable	—	—	2	60	12
Total Proved Plus Probable	—	—	13	374	76
Indonesia (4)
Proved
Developed Producing	—	—	3	128	24
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	3	128	24
Probable	—	—	1	37	7
Total Proved Plus Probable	—	—	4	165	31
Total Company
Proved
Developed Producing	758	15	56	1,582	1,093
Developed Non-Producing	100	18	1	40	126
Undeveloped	3,325	3	10	345	3,396
Total Proved	4,183	36	67	1,967	4,615
Probable	1,756	108	32	899	2,045
Total Proved Plus Probable	5,939	144	99	2,866	6,660

(1)Cenovus’s interest (operated or non-operated) after deduction of royalties and includes royalty interests.

(2)Includes heavy crude oil that is not material representing less than one percent of bitumen on a total proved plus probable basis.

(3)Includes shale gas that is not material representing less than one percent of conventional natural gas on a total proved plus probable basis.

(4)Includes Cenovus’s 40 percent interest in HCML.

Cenovus Energy Inc. – 2022 Annual Information Form 20

Summary of Net Present Value of Future Net Revenue as at December 31, 2022

	Discounted at % per year					Unit Value Discounted at 10% (1)
Before Income Taxes($ millions)	0%	5%	10%	15%	20%	$/BOE
Canada
Proved
Developed Producing	27,324	26,946	24,146	21,617	19,525	24.03
Developed Non-Producing	5,101	3,914	3,131	2,584	2,184	24.89
Undeveloped	166,663	65,901	32,134	18,205	11,401	9.46
Total Proved	199,088	96,761	59,411	42,406	33,110	13.12
Probable	138,089	33,564	13,941	8,245	5,733	6.88
Total Proved Plus Probable	337,177	130,325	73,352	50,651	38,843	11.19
China
Proved
Developed Producing	4,112	3,558	3,126	2,783	2,505	49.13
Developed Non-Producing	—	—	—	—	—	—
Undeveloped	—	—	—	—	—	—
Total Proved	4,112	3,558	3,126	2,783	2,505	49.13
Probable	784	619	503	419	357	41.05
Total Proved Plus Probable	4,896	4,177	3,629	3,202	2,862	47.82
Indonesia (2)
Proved
Developed Producing	572	493	431	382	343	17.96
Developed Non-Producing	—	—	—	—	—	—
Undeveloped	—	—	—	—	—	—
Total Proved	572	493	431	382	343	17.96
Probable	279	211	165	132	108	24.29
Total Proved Plus Probable	851	704	596	514	451	19.36
Total Company
Proved
Developed Producing	32,008	30,997	27,703	24,782	22,373	25.36
Developed Non-Producing	5,101	3,914	3,131	2,584	2,184	24.89
Undeveloped	166,663	65,901	32,134	18,205	11,401	9.46
Total Proved	203,772	100,812	62,968	45,571	35,958	13.65
Probable	139,152	34,394	14,609	8,796	6,198	7.14
Total Proved Plus Probable	342,924	135,206	77,577	54,367	42,156	11.65

(1)Unit values have been calculated using Cenovus’s interest (operated and non-operated) after deduction of royalties and includes royalty interests reserves.

(2)Includes Cenovus’s 40 percent interest in HCML.

Cenovus Energy Inc. – 2022 Annual Information Form 21

	Discounted at % per year
After Income Taxes (1) ($ millions)	0%	5%	10%	15%	20%
Canada
Proved
Developed Producing	21,339	21,807	19,676	17,647	15,946
Developed Non-Producing	3,975	3,019	2,399	1,970	1,659
Undeveloped	127,569	49,903	24,019	13,404	8,248
Total Proved	152,883	74,729	46,094	33,021	25,853
Probable	105,441	25,434	10,543	6,238	4,342
Total Proved Plus Probable	258,324	100,163	56,637	39,259	30,195
China
Proved
Developed Producing	3,077	2,669	2,348	2,092	1,884
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	3,077	2,669	2,348	2,092	1,884
Probable	559	432	344	281	234
Total Proved Plus Probable	3,636	3,101	2,692	2,373	2,118
Indonesia (2)
Proved
Developed Producing	389	337	297	264	238
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	389	337	297	264	238
Probable	176	145	121	104	91
Total Proved Plus Probable	565	482	418	368	329
Total Company
Developed Producing	24,805	24,813	22,321	20,003	18,068
Developed Non-Producing	3,975	3,019	2,399	1,970	1,659
Undeveloped	127,569	49,903	24,019	13,404	8,248
Total Proved	156,349	77,735	48,739	35,377	27,975
Probable	106,176	26,011	11,008	6,623	4,667
Total Proved Plus Probable	262,525	103,746	59,747	42,000	32,642

(1)Values are calculated by considering existing tax pools and tax circumstances for Cenovus in the consolidated evaluation of Cenovus’s oil and gas properties and taking into account current tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see Cenovus’s consolidated financial statements for the year ended December 31, 2022, and the annual 2022 MD&A.

(2)Includes Cenovus’s 40 percent interest in HCML.

Cenovus Energy Inc. – 2022 Annual Information Form 22

Total Undiscounted Future Net Revenue as at December 31, 2022

($ millions)	Revenue	Royalties	Operating Costs	Development Costs	Total Abandonment and Reclamation Costs (1)	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
Canada
Total Proved	493,169	125,207	110,637	47,009	11,228	199,088	46,205	152,883
Total Proved Plus Probable	813,247	212,677	171,460	78,833	13,100	337,177	78,853	258,324
China
Total Proved	5,325	285	777	43	108	4,112	1,035	3,077
Total Proved Plus Probable	6,401	343	1,010	44	108	4,896	1,260	3,636
Indonesia (2)
Total Proved	2,247	703	935	—	37	572	183	389
Total Proved Plus Probable	3,089	1,097	1,083	19	39	851	286	565
Total Company
Total Proved	500,741	126,195	112,349	47,052	11,373	203,772	47,423	156,349
Total Proved Plus Probable	822,737	214,117	173,553	78,896	13,247	342,924	80,399	262,525

(1)Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of future development activity.

(2)Includes Cenovus’s 40 percent interest in HCML.

Future Net Revenue by Product Type as at December 31, 2022

Reserves Category	Product Types	Future Net Revenue Before Income Taxes Discounted at 10% per Year ($ millions)	Unit Value Discounted at 10% per Year (1) ($/BOE)
Total Proved	Bitumen (2)	56,696	13.55
	Light and Medium Oil (3)	1,084	12.49
	Conventional Natural Gas (4) (5)	5,188	15.05
	Total	62,968	13.65
Total Proved Plus	Bitumen (2)	67,682	11.40
Probable	Light and Medium Oil (3)	2,951	13.81
	Conventional Natural Gas (4) (5)	6,944	13.71
	Total	77,577	11.65

(1)Unit values have been calculated using Cenovus’s interest (operated and non-operated) after deduction of royalties and includes royalty interest reserves.

(2)Includes heavy crude oil that is not material.

(3)Includes solution gas and other byproducts, which includes NGLs.

(4)Includes shale gas that is not material and other byproducts, which includes NGLs, but excludes solution gas.

(5)Includes Cenovus’s 40 percent interest in HCML.

Additional Notes to Reserves Data Tables

•All reserves and FNR were evaluated using forecast prices and costs.

•The estimates of FNR presented do not represent fair market value.

•FNR from reserves excludes cash flows related to Cenovus’s risk management activities.

•For disclosure purposes, Cenovus includes heavy crude oil with bitumen and shale gas with conventional natural gas, as the reserves of heavy crude oil and shale gas are not material.

•In accordance with NI 51-101, NPV and FNR amounts presented include all of Cenovus’s existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves.

•BOE estimates and tables may not sum due to rounding.

Cenovus Energy Inc. – 2022 Annual Information Form 23

Definitions

Gross means: (a) in relation to production and reserves, the interest (operated or non-operated) held by Cenovus before deduction of royalties and excludes royalty interests; (b) in relation to wells, the total number of wells in which Cenovus has an interest; and (c) in relation to properties, the total acreage of properties in which Cenovus has an interest.

Net means: (a) in relation to production and reserves, the interest (operated or non-operated) held by Cenovus after deduction of royalties and includes royalty interests; (b) in relation to wells, the number of wells obtained by aggregating Cenovus’s interest (operated or non-operated) in each of its wells; and (c) in relation to properties, the total acreage obtained by aggregating Cenovus’s interest (operated or non-operated) in each of its properties.

Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analysis of drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions, which are generally accepted as being reasonable, and are disclosed later in this AIF.

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

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

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

Each of the reserves categories may be divided into developed and undeveloped categories:

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared with the cost of drilling a well) to put the reserves on production. The developed category may be subdivided as follows:

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

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

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

Cenovus Energy Inc. – 2022 Annual Information Form 24

Pricing Assumptions

Except as noted below, the forecast of prices, inflation and exchange rate provided in the table below is computed using the average of forecasts by McDaniel, GLJ and Sproule Associates Limited and is used to estimate FNR associated with the reserves disclosed herein. This average forecast is dated January 1, 2023. The inflation forecast was applied uniformly to prices beyond the forecast interval, and to all future costs. Natural gas prices for China and Indonesia are derived from the natural gas sales agreements specific to each set of projects. For historical prices realized during 2022, see the Production History and Per-Unit Results section in this AIF.

	Crude Oil and NGLs (1)					Conventional Natural Gas
Year	WTI Cushing Oklahoma (US$/bbl)	Edmonton Par Price 40 API (C$/bbl)	Western Canadian Select (C$/bbl)	Edmonton C5+ (C$/bbl)	Brent (US$/bbl)	AECO (C$/MMBtu)	China(2) (US$/Mcf)	Indonesia (2) (US$/Mcf)	Inflation Rate (%/year)	Exchange Rate (US$/C$)
2023	80.33	103.77	76.54	106.22	84.67	4.23	9.53	7.18	0.0	0.7450
2024	78.50	97.74	77.75	101.35	82.69	4.40	9.67	7.32	2.3	0.7650
2025	76.95	95.27	77.54	98.94	81.03	4.21	9.67	7.43	2.0	0.7683
2026	77.61	95.58	80.07	100.19	81.39	4.27	9.62	7.51	2.0	0.7717
2027	79.16	97.07	81.89	101.74	82.65	4.34	9.83	7.64	2.0	0.7750
2028	80.75	99.01	84.02	103.78	84.29	4.43	9.87	7.79	2.0	0.7750
2029	82.36	100.99	85.73	105.85	85.98	4.51	9.91	7.89	2.0	0.7750
2030	84.01	103.01	87.44	107.97	87.70	4.60	9.99	8.04	2.0	0.7750
2031	85.69	105.07	89.20	110.13	89.46	4.69	10.98	8.22	2.0	0.7750
2032	87.40	106.69	91.11	112.33	91.25	4.79	11.16	8.39	2.0	0.7750
2033	89.15	108.83	92.93	114.58	93.07	4.89	11.19	—	2.0	0.7750
2034+	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	—	—	2.0	0.7750

(1)Crude oil includes bitumen, heavy crude oil and light and medium oil.

(2)China and Indonesia natural gas prices are derived from the natural gas sales agreements specific to each set of projects.

Future Development Costs

The following table outlines undiscounted future development costs deducted in the estimation of FNR, by reserves category:

($ millions)	2023	2024	2025	2026	2027	Remainder	Total
Canada
Total Proved	1,846	1,961	1,578	1,458	1,048	39,118	47,009
Total Proved Plus Probable	2,350	2,346	2,171	1,941	1,323	68,702	78,833
China
Total Proved	5	5	5	5	5	18	43
Total Proved Plus Probable	6	5	5	5	5	18	44
Indonesia (1)
Total Proved	—	—	—	—	—	—	—
Total Proved Plus Probable	19	—	—	—	—	—	19
Total Company
Total Proved	1,851	1,966	1,583	1,463	1,053	39,136	47,052
Total Proved Plus Probable	2,375	2,351	2,176	1,946	1,328	68,720	78,896

(1)Includes Cenovus’s 40 percent interest in HCML.

Cenovus believes that existing cash and cash equivalents balances, internally generated cash flows, existing credit facilities, management of its asset portfolio and access to capital markets will be sufficient to fund the Company’s future development costs. However, there can be no guarantee that the necessary funds will be available or that Cenovus will allocate funding to develop all of its reserves. Failure to develop those reserves would have a negative impact on the Company’s FNR.

The interest or other costs of external funding are not included in the reserves and FNR estimates and would reduce FNR depending upon the funding sources utilized. Cenovus does not believe that interest or other funding costs would make development of any property uneconomic.

Cenovus Energy Inc. – 2022 Annual Information Form 25

Reserves Reconciliation as at December 31, 2022

Gross Reserves, Total Proved	Bitumen (1) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (2) (Bcf)	Total (MMBOE)
Canada
As at December 31, 2021	5,573	45	69	1,615	5,956
Extensions and Improved Recovery	25	2	4	209	67
Discoveries	—	—	—	—	—
Technical Revisions	33	(1)	2	46	42
Economic Factors	3	4	2	57	18
Acquisitions	294	—	—	2	294
Dispositions	(122)	(1)	(3)	(32)	(132)
Production (3)	(214)	(7)	(8)	(217)	(265)
As at December 31, 2022	5,592	42	66	1,680	5,980
China
As at December 31, 2021	—	—	17	403	84
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	(1)	12	1
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(4)	(84)	(18)
As at December 31, 2022	—	—	12	331	67
Indonesia (4)
As at December 31, 2021	—	—	3	201	37
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	2	(1)	2
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(1)	(17)	(4)
As at December 31, 2022	—	—	4	183	35
Total Company
As at December 31, 2021	5,573	45	89	2,219	6,077
Extensions and Improved Recovery	25	2	4	209	67
Discoveries	—	—	—	—	—
Technical Revisions	33	(1)	3	57	45
Economic Factors	3	4	2	57	18
Acquisitions	294	—	—	2	294
Dispositions	(122)	(1)	(3)	(32)	(132)
Production (3)	(214)	(7)	(13)	(318)	(287)
As at December 31, 2022	5,592	42	82	2,194	6,082

Cenovus Energy Inc. – 2022 Annual Information Form 26

Gross Reserves, Probable	Bitumen (1) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (2) (Bcf)	Total (MMBOE)
Canada
As at December 31, 2021	1,850	152	34	814	2,172
Extensions and Improved Recovery	402	9	2	122	432
Discoveries	—	—	—	—	—
Technical Revisions	14	(5)	(1)	(49)	—
Economic Factors	1	(3)	1	17	1
Acquisitions	204	—	—	1	205
Dispositions	(23)	(24)	(1)	(8)	(48)
Production (3)	—	—	—	—	—
As at December 31, 2022	2,448	129	35	897	2,762
China
As at December 31, 2021	—	—	3	74	16
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	(1)	(9)	(3)
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	—	—
As at December 31, 2022	—	—	2	65	13
Indonesia (4)
As at December 31, 2021	—	—	2	71	13
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	—	(4)	(1)
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	—	—
As at December 31, 2022	—	—	2	67	12
Total Company
As at December 31, 2021	1,850	152	39	959	2,201
Extensions and Improved Recovery	402	9	2	122	432
Discoveries	—	—	—	—	—
Technical Revisions	14	(5)	(2)	(62)	(4)
Economic Factors	1	(3)	1	17	1
Acquisitions	204	—	—	1	205
Dispositions	(23)	(24)	(1)	(8)	(48)
Production (3)	—	—	—	—	—
As at December 31, 2022	2,448	129	39	1,029	2,787

Cenovus Energy Inc. – 2022 Annual Information Form 27

Gross Reserves, Total Proved Plus Probable	Bitumen (1) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (2) (Bcf)	Total (MMBOE)
Canada
As at December 31, 2021	7,423	197	103	2,429	8,128
Extensions and Improved Recovery	427	11	6	331	499
Discoveries	—	—	—	—	—
Technical Revisions	47	(6)	1	(3)	42
Economic Factors	4	1	3	74	19
Acquisitions	498	—	—	3	499
Dispositions	(145)	(25)	(4)	(40)	(180)
Production (3)	(214)	(7)	(8)	(217)	(265)
As at December 31, 2022	8,040	171	101	2,577	8,742
China
As at December 31, 2021	—	—	20	477	100
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	(2)	3	(2)
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(4)	(84)	(18)
As at December 31, 2022	—	—	14	396	80
Indonesia (4)
As at December 31, 2021	—	—	5	272	50
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	2	(5)	1
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(1)	(17)	(4)
As at December 31, 2022	—	—	6	250	47
Total Company
As at December 31, 2021	7,423	197	128	3,178	8,278
Extensions and Improved Recovery	427	11	6	331	499
Discoveries	—	—	—	—	—
Technical Revisions	47	(6)	1	(5)	41
Economic Factors	4	1	3	74	19
Acquisitions	498	—	—	3	499
Dispositions	(145)	(25)	(4)	(40)	(180)
Production (3)	(214)	(7)	(13)	(318)	(287)
As at December 31, 2022	8,040	171	121	3,223	8,869

(1)Includes heavy crude oil that is not material.

(2)Includes shale gas that is not material.

(3)Production used for the reserves reconciliation differs from publicly reported production. In accordance with NI 51-101, gross production used for the reserves reconciliation above includes Cenovus’s share of gas volumes provided to FCCL for steam generation, but does not include royalty interest production.

(4)Includes Cenovus’s 40 percent interest in HCML.

Cenovus Energy Inc. – 2022 Annual Information Form 28

Developments in 2022 compared with 2021 include:

•Bitumen gross total proved and gross total proved plus probable reserves increased by 19 million barrels and 617 million barrels, respectively. The increases were due to additions from the regulatory approval at Foster Creek, the Sunrise Acquisition and improved recovery performance at Sunrise and Lloydminster thermal, partially offset by the Tucker asset sale and current year production.

•Light and medium oil gross total proved and gross total proved plus probable reserves decreased by three million barrels and 26 million barrels, respectively. The decreases were due to the disposition of 12.5 percent of the Company’s working interest in the White Rose field and satellite extensions, the Wembley asset sale and current year production, partially offset by additions from updates to the Atlantic region and Conventional segment development plans.

•NGLs gross total proved and gross total proved plus probable reserves decreased by seven million barrels each, due to dispositions in the Conventional segment and current year production, partially offset by additions from updates to the development plan and economic factors related to increased product pricing for the Conventional segment.

•Conventional natural gas gross total proved reserves decreased by 25 billion cubic feet due to the Wembley asset sale and current year production, partially offset by updates to the development plans, improved recovery performance, and economic factors due to improved product pricing for the Conventional segment. Conventional natural gas gross total proved plus probable reserves increased by 45 billion cubic feet due to updates to the development plan and economic factors due to improved product pricing for the Conventional segment, partially offset by the Wembley asset sale and current year production.

Undeveloped Reserves

Proved and probable undeveloped reserves have been estimated by the IQREs in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”). Undeveloped reserves are scheduled to be produced within the next 50 years.

The undeveloped tables presented here reflect Cenovus’s gross reserves and the product type groups reported above.

Proved Undeveloped (Gross Reserves)

	Bitumen (1) (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas (2) (Bcf)		Total (MMBOE)
	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total
2020	99	3,848	—	—	1	9	16	157	103	3,884
2021	694	4,490	23	23	5	9	278	356	768	4,582
2022	313	4,442	2	4	3	13	158	382	344	4,523

(1)Includes heavy crude oil that is not material.

(2)Includes shale gas that is not material.

Probable Undeveloped (Gross Reserves)

	Bitumen (1) (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas (2) (3) (Bcf)		Total (MMBOE)
	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total
2020	—	1,407	1	3	1	18	13	317	3	1,481
2021	289	1,692	139	140	6	16	267	440	478	1,922
2022	633	2,281	1	116	4	19	186	513	669	2,502

(1)Includes heavy crude oil that is not material.

(2)Includes shale gas that is not material.

(3)Includes Cenovus’s 40 percent interest in HCML.

Cenovus Energy Inc. – 2022 Annual Information Form 29

Development of Proved and Probable Undeveloped Reserves

Bitumen

As at December 31, 2022, Cenovus had gross proved undeveloped bitumen reserves of 4,442 million barrels, or approximately 79 percent of the Company’s total gross proved bitumen reserves. Of Cenovus’s 2,448 million barrels of gross probable bitumen reserves, 2,281 million barrels, or approximately 93 percent, are undeveloped. Based on the evaluation of these reserves, Cenovus anticipates that the reserves will be recovered using SAGD, except for the heavy crude oil, which is not material.

Typical SAGD project development involves the initial installation of a steam generation facility, at a cost much greater than drilling a production/injection well pair, and then progressively drilling sufficient SAGD well pairs to fully utilize the available steam.

Bitumen reserves can be classified as proved when there is sufficient stratigraphic drilling to demonstrate, with a high degree of certainty, the presence of bitumen in commercially recoverable volumes. McDaniel’s standard for sufficient drilling in a fluvial SAGD formation is a minimum of eight stratigraphic wells per section with 3D seismic or 16 stratigraphic wells per section with no seismic. Additionally, operator funding approvals must be in place, a reasonable development timetable must be established and all requisite legal and regulatory approvals must have been obtained. Proved developed bitumen reserves are differentiated from proved undeveloped bitumen reserves by the presence of drilled production/injection well pairs at the reserves estimation effective date. Because a steam plant has a long life relative to well pairs, in the early stages of a SAGD project, only a small portion of proved reserves will be developed as the number of well pairs drilled will be limited by the available steam capacity.

Recognition of probable reserves requires sufficient drilling of stratigraphic wells to establish reservoir suitability for SAGD. McDaniel’s standard for probable reserves is a minimum of four stratigraphic wells per section. Reserves will be classified by McDaniel as probable if the number of stratigraphic wells drilled falls between their proved reserves and probable reserves requirements. In Alberta, if the reserves are located outside of an approved development plan area, but within an approved project area, they will be classified as probable reserves as long as they exceed the minimum stratigraphic well requirement. If reserves lie outside an approved development area, approval to include those reserves in the development area must be obtained before development drilling of SAGD well pairs can commence.

Development of the Christina Lake, Foster Creek, Lloydminster thermal and Sunrise proved and probable undeveloped reserves will take place in an orderly manner as additional well pairs are drilled to utilize the available steam when existing well pairs reach the end of their steam injection phase. Development and capital spending on the proved and probable undeveloped reserves at Narrows Lake continues with the tieback into the Christina Lake plant. First steam is expected in 2025. The forecasted production of Cenovus’s proved and proved plus probable SAGD bitumen reserves, extends approximately 45 years and 50 years, respectively. Production of the current proved developed portion is estimated to take approximately 23 years.

Light and Medium Oil, NGLs and Conventional Natural Gas

Cenovus’s Conventional segment gross proved undeveloped and gross proved plus probable undeveloped reserves of light and medium oil, NGLs and conventional natural gas are approximately one percent and two percent, respectively, of the Company’s gross total proved and gross total proved plus probable reserves. Cenovus plans to develop the Conventional segment proved and proved plus probable undeveloped reserves over the next five years and 10 years, respectively. Decisions on the priority and timing of developing the various proved and probable undeveloped reserves, including decisions to defer development of proved and probable undeveloped reserves beyond two years, are based on various factors including strategic considerations, changing economic conditions, changes to government regulations including the setting of production limits, technical performance, development plan optimization, facility capacity, pipeline constraints, and the size of the development program. The development opportunities have been pursued at a pace dependent on capital availability and its allocation in accordance with Cenovus’s business plans.

Cenovus’s Offshore segment gross proved plus probable undeveloped reserves of light and medium oil, NGLs and conventional natural gas are approximately one percent of the Company’s gross total proved plus probable reserves. The probable undeveloped reserves attributed to the West White Rose project are currently scheduled to be on stream by 2026.

Significant Factors or Uncertainties Affecting Reserves Data

The evaluation of reserves is a continuous process that can be significantly impacted by a variety of internal and external influences. Revisions are often required resulting from changes in pricing, economic conditions, regulatory changes, and historical performance. While these factors can be considered and potentially anticipated, certain judgments and assumptions are always required. As new information becomes available, these areas are reviewed and revised accordingly. For a discussion of the risk factors and uncertainties affecting Cenovus’s reserves data, see the section entitled Risk Management and Risk Factors in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and is available on SEDAR at sedar.com and EDGAR at sec.gov.

Cenovus Energy Inc. – 2022 Annual Information Form 30

Other Oil and Gas Information

Oil and Gas Properties and Wells

The following tables summarizes producing and non-producing wells in which Cenovus has a working interest, as at December 31, 2022:

Producing Wells

	Crude Oil (1)		Conventional Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Canada
Oil Sands (2)	2,191	2,129	358	333	2,549	2,462
Conventional (3)	723	534	4,150	3,156	4,873	3,690
Offshore – Atlantic (4)	37	17	—	—	37	17
	2,951	2,680	4,508	3,489	7,459	6,169
International
Offshore – China	—	—	17	10	17	10
Offshore – Indonesia	—	—	9	4	9	4
	—	—	26	14	26	14
Total	2,951	2,680	4,534	3,503	7,485	6,183

(1)Crude oil includes bitumen, heavy crude oil and light and medium oil.

(2)Includes 1,265 gross producing wells (1,247 net producing wells) located in Alberta and 926 gross producing wells (882 net producing wells) located in Saskatchewan.

(3)Includes 721 gross producing wells (534 net producing wells) located in Alberta and 2 gross producing wells (2 net producing wells) located in British Columbia.

(4)All producing Offshore – Atlantic wells are located in Newfoundland and Labrador.

Non-Producing Wells (1)

	Crude Oil (2)		Conventional Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Canada
Oil Sands (3)	7,162	6,763	729	693	7,891	7,456
Conventional (4)	565	430	1,367	1,069	1,932	1,499
Offshore – Atlantic (5)	5	3	—	—	5	3
	7,732	7,196	2,096	1,762	9,828	8,958
International
Offshore – China	—	—	—	—	—	—
Offshore – Indonesia (6)	—	—	4	2	4	2
	—	—	4	2	4	2
Total	7,732	7,196	2,100	1,764	9,832	8,960

(1)Non-producing wells include wells that are capable of producing, but which are currently not producing. Non-producing wells do not include other types of wells such as stratigraphic test wells, service wells or wells that have been abandoned.

(2)Crude oil includes bitumen, heavy crude oil and light and medium oil.

(3)Includes 1,863 gross non-producing wells (1,758 net non-producing wells) located in Alberta and 5,299 gross non-producing wells (5,005 net non-producing wells) located in Saskatchewan.

(4)Includes 559 gross non-producing wells (424 net non-producing wells) located in Alberta; 1 gross non-producing wells (1 net non-producing wells) located in British Columbia; 5 gross non-producing wells (5 net non-producing wells) located in Saskatchewan.

(5)All non-producing Offshore – Atlantic wells are located in Newfoundland and Labrador.

(6)Indonesia wells are located in Madura Strait MDA and MAC fields.

Cenovus Energy Inc. – 2022 Annual Information Form 31

Exploration and Development Activity

The following tables summarize Cenovus’s gross and net interest in wells drilled in 2022:

					Offshore
	Oil Sands (1) (2)		Conventional (1)(2)		Atlantic (1) (2)		China (1)		Indonesia (1)		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Crude Oil (3)	328	309	12	12	—	—	—	—	—	—	340	321
Natural Gas	—	—	20	19	—	—	—	—	9	4	29	23
Dry and Abandoned	—	—	—	—	—	—	—	—	—	—	—	—
Total	328	309	32	31	—	—	—	—	9	4	369	344

(1)No exploration wells were drilled in 2022.

(2)Oil Sands, Conventional and Atlantic consist only of wells located in Canada.

(3)Crude oil includes bitumen, heavy crude oil and light and medium oil.

During the year ended December 31, 2022, the Company drilled 70 gross stratigraphic test wells (68 net wells) and 142 gross observation wells (127 net wells) in the Oil Sands segment. No stratigraphic test wells were drilled in the Conventional and Offshore segments.

During the year ended December 31, 2022, no service wells were drilled within Oil Sands, Conventional or Offshore segments.

SAGD well pairs are counted as a single oil producing well in the table above. During the year ended December 31, 2022, 116 gross SAGD well pairs were drilled (114 net well pairs).

For all types of wells except stratigraphic test and observation wells, the calculation of the number of wells is based on the number of surface locations. For stratigraphic test and observation wells, the calculation is based on the number of bottomhole locations.

Development activities were focused on sustaining bitumen production at Foster Creek, Christina Lake and Lloydminster thermal, and the production and de-risking resource potential of the Conventional properties. The Company completed nine (gross) development wells in the Madura Strait area in 2022.

Properties With No Attributed Reserves

The following table summarizes Cenovus’s unproved acreage as at December 31, 2022:

(thousands of acres)	Gross	Net
Canada	10,420	7,986
China and Taiwan	1,963	1,479
Indonesia	614	246
Total	12,997	9,711

For lands in which Cenovus holds multiple leases under the same surface area, both gross areas and net areas have been counted for each lease.

Cenovus has rights to explore, develop, and exploit approximately 392,114 unproved net acres in Canada that could potentially expire by December 31, 2023, which relate entirely to Crown and freehold properties. Cenovus relinquished the PSC for block 23/07 in 2022. There are no other expiries for China or Indonesia.

The Company and CPC Corporation, through a joint agreement, have rights to an exploration block covering approximately 7,700 square kilometres located southwest of the Taiwan Area offshore. The three-dimensional seismic period expires on December 17, 2024. See Description of the Business Offshore section in this AIF for further details.

The Company has a liability of approximately $37 million related to exploration licenses in the Atlantic region. The Company has commitments totaling approximately $34 million related to exploration to be completed in China on timelines to be agreed with CNOOC.

Properties with no attributed reserves include Crown lands where bitumen contingent and prospective resources have been identified and Crown lands where exploration activities to date have not identified potential reserves in commercial quantities. The Company regularly reviews the economic viability of these unproved properties on the basis of product pricing, capital availability and level of related infrastructure development. From this process, some properties are selected for future development activity while others are retained as inactive, sold, swapped or relinquished back to the mineral rights owner.

Cenovus Energy Inc. – 2022 Annual Information Form 32

Additional Information Concerning Abandonment and Reclamation Costs

The estimated total future abandonment and reclamation costs for existing wells, facilities, and infrastructure is based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities having regard to Cenovus’s working interest and the estimated timing of the costs to be incurred in future periods. Cenovus has developed a process to calculate these estimates, which considers applicable regulations, actual and anticipated costs, type and size of the well or facility and the geographic location.

Cenovus has estimated undiscounted and uninflated future abandonment and reclamation costs for its existing upstream assets of approximately $7.6 billion (approximately $3.1 billion, discounted at 10 percent) at December 31, 2022, of which the Company expects to pay $0.8 billion in the next three financial years.

The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2022, $209 million (December 31, 2021 – $186 million), was deposited in restricted accounts in the consolidated financial statements.

Of the undiscounted future abandonment and reclamation costs to be incurred over the life of Cenovus’s total proved reserves, approximately $11.4 billion has been deducted in estimating the FNR, which represents the Company’s total existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves.

Tax Outlook

Consistent with 2023 guidance dated December 5, 2022, and available on the Company’s website at cenovus.com, the Company expects to pay cash taxes of $1.5 billion to $1.8 billion in 2023. This estimate could vary significantly if underlying assumptions change with respect to commodity prices, capital spending levels and acquisition and disposition transactions.

Costs Incurred

($ millions)	Canada	China	Indonesia (1)	2022
Acquisitions
Unproved	—	—	—	—
Proved	1,621	—	—	1,621
Total Acquisitions	1,621	—	—	1,621
Exploration Costs	34	3	—	37
Development Costs	2,404	4	74	2,482
Total Costs Incurred	4,059	7	74	4,140

($ millions)	Canada	China	Indonesia (1)	2021
Acquisitions
Unproved	—	45	—	45
Proved	5,640	3,000	—	8,640
Total Acquisitions	5,640	3,045	—	8,685
Exploration Costs	39	16	—	55
Development Costs	1,356	5	8	1,369
Total Costs Incurred	7,035	3,066	8	10,109

(1)Includes Cenovus’s 40 percent interest in HCML.

Forward Contracts

Cenovus may use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates. These include WTI contracts for exposure management unrelated to crude oil sales price risk management; and contracts for management of price exposures associated with crude oil, crude oil differentials, condensate, natural gas liquids, refined products, refining margins, natural gas, electricity and renewable power contracts. A description of such instruments is provided in the notes to the Company’s consolidated financial statements for the year ended December 31, 2022.

Cenovus Energy Inc. – 2022 Annual Information Form 33

Production Estimates

The following table summarizes the 2023 estimated gross production of Cenovus’s gross reserves for all properties held on December 31, 2022, using forecast prices and costs, which will be produced in Canada, China and Indonesia. These estimates assume certain activities take place, such as the development of undeveloped reserves, and that there are no divestitures.

	Total Proved	Total Proved Plus Probable
Canada
Bitumen (Mbbls/d) (1) (2)	588.6	621.1
Light and Medium Oil (Mbbls/d)	23.8	25.2
NGLs (Mbbls/d)	22.8	24.5
Conventional Natural Gas (MMcf/d) (3)	553.9	601.2
Total (MBOE/d)	727.5	771.0
China
NGLs(Mbbls/d)	6.2	6.8
Conventional Natural Gas (MMcf/d)	150.4	164.7
Total (MBOE/d)	31.3	34.3
Indonesia(4)
NGLs(Mbbls/d)	2.2	2.5
Conventional Natural Gas (MMcf/d)	67.3	81.9
Total (MBOE/d)	13.4	16.2
Total Company
Bitumen (Mbbls/d) (1) (2)	588.6	621.1
Light and Medium Oil (Mbbls/d)	23.8	25.2
NGLs (Mbbls/d)	31.2	33.9
Conventional Natural Gas (MMcf/d) (3)	771.6	847.8
Total (MBOE/d)	772.2	821.5

(1)Includes heavy crude oil that is not material.

(2)Includes Foster Creek production of 175.3 thousand barrels per day for total proved and 177.0 thousand barrels per day for total proved plus probable, and Christina Lake production of 247.3 thousand barrels per day for total proved and 258.6 thousand barrels per day for total proved plus probable.

(3)Includes shale gas that is not material.

(4)Includes Cenovus’s 40 percent interest in HCML.

Cenovus Energy Inc. – 2022 Annual Information Form 34

Production History and Per-Unit Results

	2022	Q4	Q3	Q2	Q1
Canada
Bitumen (Mbbls/d)	570.3	593.5	568.2	540.3	578.8
Heavy Crude Oil (1)(Mbbls/d)	16.3	15.8	16.8	16.4	16.2
Light and Medium Oil (1)(Mbbls/d)	19.1	17.1	16.0	20.8	21.9
NGLs (Mbbls/d)	23.8	26.1	19.9	24.7	24.5
Conventional Natural Gas (2)(MMcf/d)	588.4	567.2	608.7	613.2	567.8
Total (MBOE/d)	727.5	747.1	722.4	704.6	735.9
China
NGLs (Mbbls/d)	9.8	9.9	9.5	9.4	10.6
Conventional Natural Gas (MMcf/d)	230.1	222.8	215.5	224.9	257.7
Total (MBOE/d)	48.2	47.0	45.4	46.9	53.6
Indonesia (3)
NGLs (Mbbls/d)	2.6	2.5	2.7	2.6	2.5
Conventional Natural Gas (MMcf/d)	47.6	62.0	44.5	44.1	39.8
Total (MBOE/d)	10.5	12.8	10.1	10.0	9.1
Total Company
Bitumen (Mbbls/d)	570.3	593.5	568.2	540.3	578.8
Heavy Crude Oil (1) (Mbbls/d)	16.3	15.8	16.8	16.4	16.2
Light and Medium Oil (1) (Mbbls/d)	19.1	17.1	16.0	20.8	21.9
NGLs (Mbbls/d)	36.2	38.5	32.1	36.7	37.6
Conventional Natural Gas (2)(MMcf/d)	866.1	852.0	868.7	882.2	865.3
Total (MBOE/d)	786.2	806.9	777.9	761.5	798.6

(1)Medium crude oil production in previous periods in the Lloydminster conventional heavy oil area was reclassified to heavy crude oil production.

(2)Includes shale gas that is not material.

(3)Includes Cenovus’s 40 percent interest in HCML.

Netbacks

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance and is also presented on a per-unit basis. Our Netback calculation is aligned with the definition found in the COGE Handbook. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending and operating expenses, and netback per BOE is divided by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold and exclude risk management activities. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with crude oil to transport it to market.

This measure has been described and presented in this AIF in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations, and to comply with the requirements of NI 51-101. This measure should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. For further information on these measures, readers should refer to the section entitled Specified Financial Measures Advisory located in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and is available on SEDAR at sedar.com and EDGAR at sec.gov.

Cenovus Energy Inc. – 2022 Annual Information Form 35

Canada (1) (2)	2022	Q4	Q3	Q2	Q1
Bitumen($/bbl)
Sales Price	91.79	68.13	84.46	119.75	96.16
Royalties	21.36	14.61	21.69	29.59	20.03
Transportation and Blending	8.04	9.28	7.88	7.65	7.34
Operating Expenses	12.74	12.29	12.40	14.74	11.63
Netback	49.65	31.95	42.49	67.77	57.16
Heavy Crude Oil (3)($/bbl)
Sales Price	94.84	69.24	84.95	135.76	93.57
Royalties	8.81	8.16	7.52	9.55	10.28
Transportation and Blending	3.63	3.59	3.57	3.56	3.83
Operating Expenses	45.65	51.83	43.43	45.23	41.62
Netback	36.75	5.66	30.43	77.42	37.84
Light Crude Oil($/bbl)
Sales Price	131.95	112.15	145.99	142.55	124.32
Royalties	8.97	12.43	14.01	0.43	12.23
Transportation and Blending	3.81	4.61	4.34	3.08	3.71
Operating Expenses	30.03	43.11	30.53	24.39	27.24
Netback	89.14	52.00	97.11	114.65	81.14
Conventional Natural Gas (4)($/Mcf)
Sales Price	6.48	6.56	5.89	7.86	5.53
Royalties	0.50	0.50	0.46	0.57	0.50
Transportation and Blending	0.46	0.67	0.40	0.35	0.45
Operating Expenses	1.93	1.98	1.98	1.75	2.03
Netback	3.59	3.41	3.05	5.19	2.55
NGLs($/bbl)
Sales Price	63.22	66.45	55.80	73.47	55.39
Royalties	15.00	12.60	15.85	17.84	14.02
Transportation and Blending	4.25	3.96	2.37	5.97	4.38
Operating Expenses	10.88	11.60	11.94	10.02	10.10
Netback	33.09	38.29	25.64	39.64	26.89
Total Canada (5)($/BOE)
Sales Price	91.30	68.86	83.89	117.41	95.35
Royalties	20.51	14.72	20.66	27.27	19.54
Transportation and Blending	7.94	9.39	7.63	7.43	7.34
Operating Expenses	10.58	9.82	11.15	10.91	10.45
Netback	52.27	34.93	44.45	71.80	58.02

Cenovus Energy Inc. – 2022 Annual Information Form 36

China (1)	2022	Q4	Q3	Q2	Q1
Conventional Natural Gas($/Mcf)
Sales Price	12.69	13.16	12.58	12.43	12.61
Royalties	0.70	0.77	0.72	0.66	0.67
Transportation and Blending	—	—	—	—	—
Operating Expenses	0.94	0.89	1.13	0.98	0.78
Netback	11.05	11.50	10.73	10.79	11.16
NGLs($/bbl)
Sales Price	104.67	97.62	100.28	112.96	108.05
Royalties	5.93	5.49	5.68	6.42	6.15
Transportation and Blending	—	—	—	—	—
Operating Expenses	5.61	5.36	6.66	5.86	4.68
Netback	93.13	86.77	87.94	100.68	97.22
Total China($/BOE)
Sales Price	81.99	82.89	80.68	82.25	82.09
Royalties	4.57	4.80	4.63	4.44	4.43
Transportation and Blending	—	—	—	—	—
Operating Expenses	5.62	5.36	6.73	5.89	4.66
Netback	71.80	72.73	69.32	71.92	73.00

Indonesia (1)	2022	Q4	Q3	Q2	Q1
Conventional Natural Gas($/Mcf)
Sales Price	8.53	9.09	6.94	8.34	9.67
Royalties	2.20	1.99	1.18	2.40	3.46
Transportation and Blending	—	—	—	—	—
Operating Expenses	2.22	2.32	2.01	2.29	2.25
Netback	4.11	4.78	3.75	3.65	3.96
NGLs($/bbl)
Sales Price	130.62	115.56	137.20	148.31	119.91
Royalties	82.56	66.96	81.50	110.02	70.28
Transportation and Blending	—	—	—	—	—
Operating Expenses	13.24	13.76	12.08	13.66	13.54
Netback	34.82	34.84	43.62	24.63	36.09
Total Indonesia($/BOE)
Sales Price	70.66	66.50	66.97	76.06	74.82
Royalties	30.19	22.74	26.80	39.69	34.23
Transportation and Blending	—	—	—	—	—
Operating Expenses	13.32	13.88	12.05	13.70	13.51
Netback	27.15	29.88	28.12	22.67	27.08

Cenovus Energy Inc. – 2022 Annual Information Form 37

Total Company (1) (2)	2022	Q4	Q3	Q2	Q1
Bitumen($/bbl)
Sales Price	91.79	68.13	84.46	119.75	96.16
Royalties	21.36	14.61	21.69	29.59	20.03
Transportation and Blending	8.04	9.28	7.88	7.65	7.34
Operating Expenses	12.74	12.29	12.40	14.74	11.63
Netback	49.65	31.95	42.49	67.77	57.16
Heavy Crude Oil (3)($/bbl)
Sales Price	94.84	69.24	84.95	135.76	93.57
Royalties	8.81	8.16	7.52	9.55	10.28
Transportation and Blending	3.63	3.59	3.57	3.56	3.83
Operating Expenses	45.65	51.83	43.43	45.23	41.62
Netback	36.75	5.66	30.43	77.42	37.84
Light Crude Oil($/bbl)
Sales Price	131.95	112.15	145.99	142.55	124.32
Royalties	8.97	12.43	14.01	0.43	12.23
Transportation and Blending	3.81	4.61	4.34	3.08	3.71
Operating Expenses	30.03	43.11	30.53	24.39	27.24
Netback	89.14	52.00	97.11	114.65	81.14
Conventional Natural Gas (4)($/Mcf)
Sales Price	8.25	8.47	7.61	9.05	7.84
Royalties	0.65	0.68	0.56	0.68	0.69
Transportation and Blending	0.32	0.45	0.28	0.24	0.30
Operating Expenses	1.68	1.72	1.77	1.58	1.67
Netback	5.60	5.62	5.00	6.55	5.18
NGLs($/bbl)
Sales Price	79.28	77.69	75.73	88.92	74.52
Royalties	17.35	14.32	18.30	21.57	15.51
Transportation and Blending	2.79	2.68	1.47	4.02	2.85
Operating Expenses	9.62	10.13	10.39	9.23	8.80
Netback	49.52	50.56	45.57	54.10	47.36
Total (5)($/BOE)
Sales Price	90.34	69.77	83.43	114.40	94.12
Royalties	19.56	14.19	19.69	25.89	18.61
Transportation and Blending	7.28	8.57	7.01	6.81	6.71
Operating Expenses	10.29	9.59	10.87	10.61	10.06
Netback	53.21	37.42	45.86	71.09	58.74

(1)Netbacks exclude risk management activities.

(2)The netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until the product is sold.

(3)Medium crude oil production in previous periods in the Lloydminster conventional heavy oil area was reclassified to heavy oil production.

(4)Includes shale gas that is not material.

(5)Excludes natural gas volumes used for internal consumption by the Oil Sands segment.

Cenovus Energy Inc. – 2022 Annual Information Form 38

DIVIDENDS

The declaration of dividends on common shares (base and variable) and preferred shares is at the sole discretion of the Board and is considered quarterly. The Board has the ability to declare common share dividends in common shares, cash or other property. If a dividend is not paid in full on any preferred shares on any dividend payment date, then a common share dividend restriction shall apply. The preferred share dividends are cumulative.

On April 27, 2022, Cenovus announced a revised capital allocation framework to return incremental cash to shareholders through continued share repurchases and/or the use of a variable dividend mechanism. Shareholder returns are dependent on reaching certain net debt targets and the amount of excess free funds flow.

The Company’s Board declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023.

The Company’s Board declared first quarter dividends for Cenovus’s preferred shares, payable on March 31, 2023, in the amount of $9 million, to preferred shareholders of record as at March 15, 2023.

Cenovus declared and paid the following dividends on common shares over the last three years ended December 31:

($ per share)	2022	2021	2020
Base Dividends	0.350	0.088	0.063
Variable Dividends	0.114	—	—

Cenovus declared the following dividends on the First Preferred Shares over the last three years ended December 31:

($ per share)	2022	2021	2020(1)
Series 1 First Preferred Shares	0.644	0.633	—
Series 2 First Preferred Shares	0.781	0.462	—
Series 3 First Preferred Shares	1.172	1.172	—
Series 5 First Preferred Shares	1.148	1.148	—
Series 7 First Preferred Shares	0.984	0.984	—

(1)During the twelve months ended December 31, 2020, the Company did not have any preferred shares outstanding.

The preferred shares dividends declared on November 1, 2022, were paid on January 3, 2023.

For additional information, readers should also refer to the section entitled Risk Management and Risk Factors and in particular the section entitled Risk Management and Risk Factors - Dividend Payment and Purchase of Securities in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and is available on SEDAR at sedar.com and EDGAR at sec.gov.

DESCRIPTION OF CAPITAL STRUCTURE

Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Board prior to issuance and subject to the Company’s articles. Cenovus has series 1, 2, 3, 4, 5, 6, 7 and 8 First Preferred shares.

As at December 31, 2022, the Company had the following common shares, Cenovus Warrants and first preferred shares outstanding:

	Units Outstanding(thousands)
Common Shares	1,909,190
Cenovus Warrants	55,720
Series 1 First Preferred Shares	10,740
Series 2 First Preferred Shares	1,260
Series 3 First Preferred Shares	10,000
Series 5 First Preferred Shares	8,000
Series 7 First Preferred Shares	6,000

Cenovus Energy Inc. – 2022 Annual Information Form 39

Common Shares

The holders of common shares are entitled to: (i) receive dividends if, as and when declared by Cenovus’s Board; (ii) receive notice of, to attend, and to vote on the basis of one vote per common share held, at all meetings of shareholders; and (iii) participate in any distribution of the Company’s assets in the event of liquidation, dissolution or winding up or other distribution of its assets among its shareholders for the purpose of winding up its affairs.

Normal Course Issuer Bid

On November 4, 2021, the TSX accepted the Company’s implementation of an NCIB to purchase up to 146.5 million common shares between November 9, 2021, and November 8, 2022. On November 7, 2022, the Company received approval from the TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period from November 9, 2022, to November 8, 2023.

For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares (December31, 2021 – 17 million) through the NCIBs. The shares were purchased at a volume weighted average price of $22.49 per common share (December 31, 2021 – $15.56) for a total of $2.5 billion (December 31, 2021 – $265 million). Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value.

From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB.

Preferred Shares

Cenovus may issue preferred shares in one or more series. Cenovus’s Board may determine the designation, rights, privileges, restrictions and conditions attached to each series of preferred shares before the issue of such series. Holders of preferred shares are not entitled to vote at any meeting of shareholders but may be entitled to vote if the Company fails to pay dividends on that series of preferred shares. The first preferred shares are entitled to priority over the second preferred shares and the common shares with respect to the payment of dividends and the distribution of assets in the event of any liquidation, dissolution or winding up of Cenovus’s affairs. The aggregate number of preferred shares issued by the Company may not exceed 20 percent of the aggregate number of the then-outstanding common shares.

As at December 31, 2022	Dividend Reset Date	Dividend Rate		Shares Outstanding (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	%	10,740
Series 2 First Preferred Shares (1)	Quarterly	5.86	%	1,260
Series 3 First Preferred Shares	December 31, 2024	4.69	%	10,000
Series 5 First Preferred Shares	March 31, 2025	4.59	%	8,000
Series 7 First Preferred Shares	June 30, 2025	3.94	%	6,000

(1)The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June 30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 – 1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023.

Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such option to convert their shares into the other series.

Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1), 3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6) and 3.52 percent (series 8).

Cenovus Energy Inc. – 2022 Annual Information Form 40

Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Second Preferred Shares

There were no second preferred shares outstanding as at December 31, 2022.

Cenovus Warrants

The Cenovus warrants were created and issued pursuant to the terms of the warrant indenture dated January 1, 2021 (the “Warrant Indenture”) between Cenovus and Computershare Trust Company of Canada, as warrant agent.

Each whole Cenovus warrant is exercisable for one common share at any time up to 4:30 pm (MST) on January 1, 2026, with an exercise price of $6.54 per common share, subject to adjustment in accordance with the terms of the Warrant Indenture. Cenovus warrants do not have voting or any other rights of common shares. A copy of the Warrant Indenture is filed and available on SEDAR at sedar.com and EDGAR at sec.gov.

Shareholder Rights Plan

Cenovus has a shareholder rights plan (the “Shareholder Rights Plan”) which was adopted in 2009 and creates a right that attaches to each issued common share. Until the separation time, which typically occurs at the time of an unsolicited take-over bid, whereby a person acquires or attempts to acquire 20 percent or more of Cenovus’s common shares, the rights are not separable from the common Shares, are not exercisable and no separate rights certificates are issued. Each right entitles the holder, other than the 20 percent acquiror, from and after the separation time (unless delayed by Cenovus’s Board) and before certain expiration times, to acquire common Shares at 50 percent of the market price at the time of exercise. In connection with the Arrangement, the Company’s shareholders approved certain amendments to the Shareholder Rights Plan to ensure that an acquisition by any person of common Shares or of rights to acquire common Shares pursuant to (i) the Arrangement, (ii) the Cenovus Warrants, including the exercise thereof, or (iii) any exercise of pre-emptive rights, including pursuant to any follow-on offering, under any Arrangement Pre-Emptive Rights Agreement (as defined below in the Material Contracts section of this AIF) does not and will not result in the occurrence of a “Flip-In Event” or the “Separation Time” (as those terms are defined in the Shareholder Rights Plan). The Shareholder Rights Plan was amended and reconfirmed at the 2021 annual meeting of shareholders and must be reconfirmed by the Company’s shareholders every three years. Shareholders will be asked to reconfirm, and if applicable, approve certain amendments to the Shareholder Rights Plan at the 2024 annual meeting of shareholders. If the Shareholder Rights Plan is not reconfirmed by Cenovus shareholders every three years, the Shareholder Rights Plan will terminate. A copy of the Shareholder Rights Plan was filed on SEDAR on May 12, 2021, and available on SEDAR at sedar.com and EDGAR at sec.gov.

Dividend Reinvestment Plan

Cenovus has a dividend reinvestment plan which permits holders of common shares to automatically reinvest all or any portion of the cash dividends paid on their common shares in additional common shares. At the discretion of the Company, the additional common shares may be issued from treasury at the volume weighted average price of the common shares (denominated in the currency in which the common shares trade on the applicable stock exchange) traded on the TSX during the last five trading days preceding the relevant dividend payment date or purchased on the market.

Credit Ratings

The following information relating to Cenovus’s credit ratings is provided as it relates to the Company’s financing costs and liquidity. Specifically, credit ratings affect Cenovus’s ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current rating on Cenovus’s debt by the Company’s rating agencies or a negative change in its ratings outlook could adversely affect Cenovus’s cost of financing, its access to sources of liquidity and capital, and potentially obligate it to post incremental collateral in the form of cash, letters of credit or other financial instruments. See the section entitled Risk Management and Risk Factors in the Company’s annual 2022 MD&A, which section is incorporated by reference into this AIF and is available on SEDAR at sedar.com and EDGAR at sec.gov.

Cenovus Energy Inc. – 2022 Annual Information Form 41

The following table outlines the current ratings and outlooks of Cenovus’s debt and First Preferred Shares:

	S&P Global Ratings (“S&P”)	Moody’s Investors Service (“Moody’s”)	DBRS Limited (“DBRS”)	Fitch Ratings Inc. (“Fitch”)
Senior Unsecured Long-Term Notes	BBB-	Baa2	BBB (high)	BBB-
Outlook/Trend	Stable	Stable	Stable	Positive
Series 1 First Preferred Shares	P-3		Pfd-3 (high)
Series 2 First Preferred Shares	P-3		Pfd-3 (high)
Series 3 First Preferred Shares	P-3		Pfd-3 (high)
Series 5 First Preferred Shares	P-3		Pfd-3 (high)
Series 7 First Preferred Shares	P-3		Pfd-3 (high)

Credit ratings are intended to provide an independent measure of the credit quality of an issue of securities. The credit ratings assigned by the rating agencies are not recommendations to purchase, hold or sell the securities nor do the ratings comment on market price or suitability for a particular investor. A rating may not remain in effect for any given period of time and may be revised or withdrawn entirely by a rating agency at any time in the future if, in its judgment, circumstances so warrant.

S&P’s long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of BBB- by S&P is within the fourth highest of 10 categories and indicates that the obligation exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to weaken the obligor’s capacity to meet its financial commitments on the obligation. The addition of a “+” or “-” designation after a rating indicates the relative standing within the major rating categories. An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate term, which is generally up to two years for investment grade and generally up to one year for speculative grade. Rating outlooks fall into four categories – “Positive”, “Negative”, “Stable” and “Developing”. In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions. A “Stable” outlook indicates that a rating is not likely to change.

S&P’s preferred share ratings are a forward-looking opinion about the creditworthiness of an obligor with respect to a specific preferred share obligation issued in the Canadian market relative to preferred shares issued by other issuers in the Canadian market. There is a direct correspondence between the specific ratings assigned on the Canadian preferred share scale and the various rating levels on the global debt rating scale of S&P. According to S&P’s ratings system, a P-3 rating on the Canadian preferred share rating scale is equivalent to a BB rating on the long-term credit rating scale. A rating of BB by S&P is within the fifth highest of 10 categories and indicates that the obligation is less vulnerable to nonpayment than other speculative issues. However, it faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions that could lead to the obligor’s inadequate capacity to meet its financial commitments on the obligation.

Moody’s long-term credit ratings are on a rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa2 by Moody’s is within the fourth highest of nine categories and is assigned to debt securities which are considered to be medium-grade and subject to moderate credit risk and as such may possess certain speculative characteristics. The addition of a 1, 2 or 3 modifier after a rating indicates the relative standing within a particular rating category. The modifier 2 indicates that the issue ranks in the mid-range end of its generic rating category. A Moody’s rating outlook is an opinion regarding the likely rating direction over the medium term. Rating outlooks fall into four categories – “Positive”, “Negative”, “Stable”, and “Developing”. A Stable outlook indicates a low likelihood of a rating change over the medium term.

DBRS’s long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of BBB (high) by DBRS is within the fourth highest of 10 categories and is assigned to debt securities considered to be of adequate credit quality, with acceptable capacity for payment of financial obligations. Entities in the BBB (high) category may be vulnerable to future events. The assignment of a “(high)” or “(low)” modifier within each rating category indicates relative standing within such category. The assignment of a “(high)” modifier indicates the rating is in the high end of the category. Rating trends provide guidance in respect of DBRS’s opinion regarding the outlook for the rating in question, with rating trends falling into one of three categories “Positive”, “Stable” or “Negative”. The rating trend indicates the direction in which DBRS considers the rating is headed should present circumstances continue, or in some cases, unless challenges are addressed by the issuer.

DBRS’s preferred share ratings reflect an opinion on the risk that an issuer will not fulfill its full obligations, with respect to both dividend and principal commitments in respect of preferred shares issued in the Canadian securities market in accordance with the terms under which the relevant preferred shares have been issued. DBRS’s preferred share ratings range from Pdf-1 (highest) to D (lowest). According to DBRS’s ratings system, preferred shares rated Pfd-3 (high) are generally of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. Pfd-3 (high) ratings generally correspond with issuers with a BBB category or higher reference point.

Cenovus Energy Inc. – 2022 Annual Information Form 42

Fitch’s long-term credit ratings are on a rating scale that ranges from AAA to BBB (investment grade) and BB to D (speculative grade), which represents the range from highest to lowest quality of such securities rated. The terms "investment grade" and "speculative grade" are market conventions and do not imply any recommendation or endorsement of a specific security for investment purposes. A rating of BBB- is within the fourth highest of 11 categories and indicates that expectations of default risk are currently low. The capacity for payment of financial commitments is considered adequate, but adverse business or economic conditions are more likely to impair this capacity. The modifiers “+” or ”-” may be appended to a rating to denote relative status within major rating categories. A Fitch rating outlook indicates the direction a rating is likely to move over a one to two-year period, with rating outlooks falling into four categories: “Positive”, “Negative”, “Stable” or “Evolving”. Rating outlooks reflect financial or other trends that have not yet reached, or have not been sustained at, a level that would trigger a rating action, but which may do so if such trends continue. Positive or Negative outlooks do not imply that a rating change is inevitable and similarly, ratings with Stable outlooks can be raised or lowered without prior revision of the outlook. Where the fundamental trend has strong, conflicting elements of both positive and negative, the rating outlook may be described as Evolving. A Positive Rating Outlook indicates an upward trend on the rating scale.

Throughout the last two years, Cenovus has made payments to each of S&P, Moody’s, DBRS and Fitch related to the rating of the Company’s debt. Additionally, Cenovus has purchased products and services from S&P, Moody’s, DBRS and Fitch over the same time period.

MARKET FOR SECURITIES

All of the outstanding Cenovus common shares are listed and posted for trading on the TSX and the NYSE under the symbol CVE. The following table outlines the share price trading range and volume of shares traded by month in 2022:

	TSX				NYSE
	Price Range ($ per share)			Volume (thousands) (1)	Price Range (US$ per share)			Volume (thousands) (2)
	High	Low	Close		High	Low	Close
January	19.23	16.01	18.49	307,839	15.35	12.27	14.55	233,256
February	20.56	17.89	19.93	311,205	16.16	14.07	15.70	258,069
March	21.52	18.19	20.84	423,696	17.21	14.19	16.68	349,464
April	25.07	20.24	23.75	314,926	19.64	15.85	18.48	227,586
May	30.25	23.05	29.32	357,464	23.91	17.86	23.17	234,231
June	31.19	23.01	24.49	331,733	24.91	17.72	19.01	216,826
July	25.36	20.03	24.40	245,477	19.62	15.20	19.08	212,047
August	25.95	20.55	24.64	223,696	19.99	15.80	18.76	196,415
September	25.86	19.90	21.22	249,955	19.66	14.45	15.37	159,765
October	28.18	22.10	27.54	217,419	20.64	16.14	20.20	178,277
November	29.99	25.03	26.75	212,189	22.17	18.57	19.89	153,094
December	27.36	23.85	26.27	163,343	20.37	17.42	19.41	102,243

(1)As reported by all Canadian marketplaces. Source: Bloomberg.

(2)As reported by all U.S. marketplaces. Source: Bloomberg.

The Cenovus Warrants are listed and trade on the TSX under the symbol CVE.WT and on the NYSE under the symbol CVE.WS and the Series 1 First Preferred Shares, Series 2 First Preferred Shares, Series 3 First Preferred Shares, Series 5 First Preferred Shares and Series 7 First Preferred Shares are listed and trade on the TSX under the symbols CVE.PR.A, CVE.PR.B, CVE.PR.C, CVE.PR.E and CVE.PR.G, respectively.

Cenovus Energy Inc. – 2022 Annual Information Form 43

The share price trading range and volume of the Cenovus Warrants traded on the TSX and the NYSE in 2022 are provided below:

	TSX				NYSE
	Price Range ($ per share)			Volume (thousands)	Price Range (US$ per share)			Volume (thousands)
	High	Low	Close		High	Low	Close
January	12.77	9.99	12.00	871	10.11	7.82	9.36	454
February	14.01	11.55	13.40	794	11.00	9.20	10.47	228
March	15.00	11.80	14.50	868	12.02	9.37	11.55	195
April	18.46	13.80	17.05	1,042	14.42	10.90	13.53	182
May	23.63	16.49	22.82	1,246	18.52	12.91	18.00	164
June	24.58	16.53	17.91	2,473	19.55	12.84	13.80	293
July	18.59	13.51	17.91	1,528	14.18	10.40	14.07	95
August	19.36	14.05	18.18	1,317	14.88	10.98	14.07	95
September	19.29	13.43	14.60	929	14.43	9.88	10.55	98
October	21.99	15.59	20.94	1,247	15.60	11.31	15.60	87
November	23.43	18.45	20.18	1,343	17.13	13.70	15.29	80
December	20.74	17.22	19.71	377	15.28	12.75	14.58	38

The share price trading range and volume of the Series 1 First Preferred Shares traded on the TSX in 2022 are provided below:

	Price Range ($ per share)			Volume (thousands)
	High	Low	Close
January	20.63	18.36	18.99	177
February	19.36	16.02	16.99	85
March	17.55	15.35	17.13	99
April	17.15	14.60	15.15	133
May	16.70	14.07	16.64	79
June	17.12	15.18	15.21	171
July	15.26	13.88	14.96	78
August	15.52	14.26	14.85	84
September	15.30	14.12	14.15	81
October	14.65	13.30	13.70	97
November	14.99	13.74	14.99	105
December	15.48	13.44	13.99	150

The share price trading range and volume of the Series 2 First Preferred Shares traded on the TSX in 2022 are provided below:

	Price Range ($ per share)			Volume (thousands)
	High	Low	Close
January	17.95	16.00	17.25	8
February	17.58	16.71	16.71	18
March	17.20	16.56	16.70	11
April	16.70	15.79	15.79	3
May	15.52	15.00	15.30	9
June	16.50	15.23	15.51	5
July	15.51	15.00	15.00	6
August	16.47	14.99	16.47	5
September	16.36	15.60	15.60	11
October	16.00	15.25	15.96	11
November	15.96	15.40	15.68	5
December	16.00	13.82	15.00	13

Cenovus Energy Inc. – 2022 Annual Information Form 44

The share price trading range and volume of the Series 3 First Preferred Shares traded on the TSX in 2022 are provided below:

	Price Range ($ per share)			Volume (thousands)
	High	Low	Close
January	24.00	23.39	23.71	103
February	23.92	22.82	22.82	86
March	23.79	22.77	23.60	190
April	23.65	19.18	21.22	272
May	23.48	20.79	23.44	114
June	23.50	21.28	21.52	67
July	21.99	19.32	20.28	56
August	21.99	20.10	21.40	89
September	21.50	19.85	20.42	120
October	20.42	19.39	19.60	61
November	20.22	19.10	19.40	87
December	19.95	19.10	19.91	149

The share price trading range and volume of the Series 5 First Preferred Shares traded on the TSX in 2022 are provided below:

	Price Range($ per share)			Volume (thousands)
	High	Low	Close
January	24.80	24.02	24.74	79
February	24.97	23.65	23.77	169
March	24.88	23.47	24.49	129
April	24.50	20.81	21.45	58
May	23.65	20.80	23.65	119
June	23.85	21.91	22.20	124
July	22.55	20.18	21.13	66
August	22.46	21.20	22.01	52
September	22.10	20.61	21.25	66
October	21.49	20.51	20.71	78
November	21.20	20.05	20.99	99
December	22.42	20.27	20.27	158

The share price trading range and volume of the Series 7 First Preferred Shares traded on the TSX in 2022 are provided below:

	Price Range ($ per share)			Volume (thousands)
	High	Low	Close
January	23.50	22.80	23.34	62
February	23.40	22.54	22.60	42
March	22.97	22.06	22.97	182
April	22.97	19.00	20.40	255
May	22.56	19.65	22.56	55
June	22.59	20.60	21.01	239
July	21.31	18.87	20.01	27
August	21.14	19.32	20.44	67
September	21.10	19.52	20.38	74
October	20.65	19.00	19.35	231
November	20.03	19.03	19.41	84
December	20.24	19.11	20.00	118

Cenovus Energy Inc. – 2022 Annual Information Form 45

DIRECTORS AND EXECUTIVE OFFICERS

Directors

The following individuals are the directors of Cenovus:

Name and Residence	Director Since (1)	Principal Occupation During the Past Five Years
Keith M. Casey (2) (5) San Antonio, Texas United States	2020	Mr. Casey is the Chief Executive Officer of Pin Oak Group, LLC, a private midstream company, since February 2022. Mr. Casey served as Chief Executive Officer of Tatanka Midstream LLC, a private midstream company, from March 2020 to January 2022. Mr. Casey spent five years with Andeavor Corporation (“Andeavor”), formerly known as Tesoro Corporation, an integrated petroleum refining, logistics, and marketing company and served as Executive Vice-President Commercial and Value Chain, from August 2016 to October 2018, Executive Vice-President, Operations from May 2014 to August 2016, and Senior Vice-President, Strategy and Business Development from April 2013 to May 2014. Mr. Casey served as a director of Andeavor Logistics LP, formerly Tesoro Logistics LP, a publicly traded midstream service company, from April 2014 to April 2015 and has served as a director of a number of private midstream companies. Mr. Casey has worked in the refining industry since 1998 and prior to that, he held leadership and operational roles with BP Products North America Inc., Praxair Incorporated and Union Carbide Corp.
Canning K.N. Fok Hong Kong Special Administrative Region	2021	Mr. Fok is Executive Director and Group Co-Managing Director of CK Hutchison Holdings Limited, a publicly traded ports and related services, retail, infrastructure and telecommunications company; Chairman and a Director of: Hutchison Telecommunications Hong Kong Holdings Limited, a publicly traded telecommunications services operator; Hutchison Telecommunications (Australia) Limited, a publicly traded telecommunications service provider; Hutchison Port Holdings Management Pte. Limited as the trustee-manager of Hutchison Port Holdings Trust, manager of a publicly traded container port business trust; Power Assets Holdings Limited, a publicly traded global energy investor; TPG Telecom Limited, a publicly traded telecommunications service provider; HK Electric Investments Manager Limited as the trustee-manager of HK Electric Investments, manager of a publicly traded power industry focused trust; and HK Electric Investments Limited, a publicly traded power industry focused trust. Mr. Fok is Deputy Chairman and an Executive Director of CK Infrastructure Holdings Limited, a publicly traded global infrastructure investment and development company; and Deputy President Commissioner of PT Indosat Tbk, a publicly traded telecommunications service provider. Mr. Fok was Co-Chair of the Board of Husky, from August 2000 to December 31, 2020 and was a director of Husky until March 2021, prior to Husky’s amalgamation with the Corporation.
Jane E. Kinney (3) (5) Toronto, Ontario Canada	2019	Ms. Kinney is a director of Intact Financial Corporation, a publicly traded insurance company, since May 2019; and a director and Chair of Nautilus Indemnity Holdings Limited, a private insurance company, since February and July 2021, respectively. Ms. Kinney spent 25 years with Deloitte LLP Canada (“Deloitte”) and was admitted to the Deloitte Partnership in 1997. She was appointed Vice Chair, Leadership Team Member of Deloitte in June 2010 and served in this role until her retirement in June 2019. Ms. Kinney’s previous positions with Deloitte include Canadian Managing Partner, Quality & Risk from May 2010 to June 2015, Global Chief Risk Officer from June 2010 to May 2012, and Risk and Regulatory Practice Leader from June 1999 to May 2010. She has also served as a lecturer at the University of Manitoba, Dalhousie University and Saint Mary’s University.
Harold N. Kvisle (2) (4) Calgary, Alberta Canada	2018	Mr. Kvisle is a director, since May 2009, and Chairman of ARC Resources Ltd., a publicly traded oil and gas company; and a director, since June 2017, and Board Chair of Finning International Inc., a publicly traded heavy equipment company since January 2019, and a Director since June 2017. Mr. Kvisle served as a director of Cona Resources Ltd. (“Cona”), a publicly traded heavy oil company, from November 2011 to May 2018 when Cona was acquired by Waterous Energy Fund. Mr. Kvisle served as President and Chief Executive Officer of Talisman Energy Inc. (“Talisman”), a publicly traded oil and gas company, from September 2012 to May 2015 and as a director of Talisman from May 2010 to May 2015. From 2001 to 2010, Mr. Kvisle was President and Chief Executive Officer of TransCanada Corporation, now TC Energy Corporation (“TC Energy”), a publicly traded pipeline and power company. Prior to joining TC Energy in 1999, he was the President of Fletcher Challenge Energy Canada Inc. Mr. Kvisle has worked in the oil and gas industry since 1975 and in the utilities and power industries since 1999.

Cenovus Energy Inc. – 2022 Annual Information Form 46

Name and Residence	Director Since (1)	Principal Occupation During the Past Five Years
Eva L. Kwok (2) (4) Vancouver, British Columbia Canada	2021	Mrs. Kwok is Chair, a director and Chief Executive Officer of Amara Holdings Inc., a private investment holding company. Mrs. Kwok is also a director of CK Life Sciences Int’l., (Holdings) Inc., a publicly traded nutraceutical, pharmaceutical and agriculture-related company; CK Infrastructure Holdings Limited, a publicly traded global infrastructure investment and development company; CK Asset Holdings Limited, a publicly traded global property investment, development, management and utility infrastructure company; and the Li Ka Shing (Canada) Foundation and was a director of Husky, from August 2000 until March 2021, prior to Husky’s amalgamation with Cenovus.
Melanie A. Little (2) (5) Alpharetta, Georgia United States	2023	Ms. Little is the President and Chief Executive Officer of Colonial Pipeline Company, a privately owned refined products terminaling and pipeline company, since January 2023; and a Director of the International Liquid Terminals Association and The Discovery Lab. Ms. Little served as Executive Vice-President and Chief Operating Officer of Magellan Midstream Partners, L.P. (“Magellan”), a public partnership that transports, stores and distributes petroleum products, from June 2022 to January 2023, and as Senior Vice-President, Operations and Environmental, Health, Safety and Security of Magellan, from July 2017 to May 2022. During Ms. Little’s 21-year career with Magellan she held a number of senior management positions, including Vice-President roles in Operations and Crude Oil Commercial from February 2011 to June 2017; Director of Transportation Services for Refined Products and Marine from June 2007 to January 2011; and environmental, health and safety management roles from January 2004 to May 2007. Ms. Little was Manager of Environmental Compliance at The Williams Companies Inc., a public energy provider and infrastructure company, from June 2001 to December 2003 and held project management positions in the areas of environmental remediation on behalf of the U.S. Army and civil construction while on active duty in the U.S. Army. Ms. Little served as a director of Diversified Energy Company plc, a public oil and gas producer, from December 2019 to December 2022.
Keith A. MacPhail (4) (6) Calgary, Alberta Canada	2018	Mr. MacPhail has served as the Chair of Cenovus’s Board since April 2020 and as a Director since 2018. He is a director of NuVista Energy Ltd., a publicly traded oil and gas company, since July 2003, and served as Chairman from July 2003 to May 2020. He also served as a director of Bonavista Energy Corporation, formerly Bonavista Petroleum Ltd. (“Bonavista”), a publicly traded oil and gas company, from November 1997 to August 2020; Chairman from March 2012 to August 2020; Executive Chairman from 2012 to 2018; Chairman and Chief Executive Officer from 2008 to 2012; and as President and Chief Executive Officer from 1997 to 2008. Mr. MacPhail served as a director of Canadian Natural Resources Limited (“CNRL”) from 1993 to 2015. Prior to joining Bonavista in 1997, Mr. MacPhail held progressively more responsible positions with CNRL, with his final position being Executive Vice President and Chief Operating Officer. Previously, he held the position of Production Manager with Poco Petroleums Ltd.
Richard J. Marcogliese (3) (5) Alamo, California United States	2016	Mr. Marcogliese is the Principal of iRefine, LLC, a privately owned petroleum refining consulting company, since June 2011; and a director of Delek US Holdings, Inc., a publicly traded downstream energy company, since January 2020. Mr. Marcogliese served as Executive Advisor of Pilko & Associates L.P., a private chemical and energy advisory company, from June 2011 to December 2019; Operations Advisor to NTR Partners III LLC, a private investment company from October 2013 to December 2017; and from September 2012 to January 2016 as Operations Advisor to the Chief Executive Officer of Philadelphia Energy Solutions, a partnership between The Carlyle Group and a subsidiary of Energy Transfer Partners, L.P. that operated an oil refining complex on the U.S. Eastern seaboard.
Claude Mongeau (3) (5) Montreal, Quebec Canada	2016	Mr. Mongeau is a director of The Toronto-Dominion Bank, an international financial institution, since March 2015; and a director of Norfolk Southern Corporation, a publicly traded North American rail transportation provider, since September 2019. Mr. Mongeau served as a director of TELUS Corporation, a publicly traded telecommunications company, from May 2017 to August 2019. He also served as a director of Canadian National Railway Company (“CN”), a publicly traded railroad and transportation company, from October 2009 to July 2016 and as President and Chief Executive Officer from January 2010 to June 2016. During his tenure with CN, he also served as Executive Vice-President and Chief Financial Officer from October 2000 until December 2009 and held various increasingly senior positions from the time he joined in 1994. Mr. Mongeau also served as a director of SNC Lavalin Group Inc. from August 2003 to May 2015.

Cenovus Energy Inc. – 2022 Annual Information Form 47

Name and Residence	Director Since (1)	Office Held and Principal Occupation During the Past Five Years
Alexander J. Pourbaix (7) Calgary, Alberta Canada	2017	Mr. Pourbaix has served as President & Chief Executive Officer of Cenovus since November 6, 2017 and is a director of Canadian Utilities Limited, a publicly traded diversified global energy infrastructure corporation, since November 2019. Mr. Pourbaix served as a director of Trican Well Service Ltd., a publicly traded oilfield services provider, from May 2012 to December 2019. Mr. Pourbaix served as Chief Operating Officer of TC Energy from October 2015 to April 2017. During his tenure with TC Energy, he also served as Executive Vice‐President and President, Development from March 2014 to September 2015 and President, Energy & Oil Pipelines from July 2010 to February 2014, and held various increasingly senior positions from the time he joined TC Energy in 1994.
Wayne E. Shaw (3) (5) Toronto, Ontario Canada	2021	Mr. Shaw is the President of G.E. Shaw Investments Limited, a private investment holding company, since 2012. Prior to his retirement in April 2013, he was a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors, Toronto, Ontario. Mr. Shaw is also a director of the Li Ka Shing (Canada) Foundation and was a director of Husky, from August 2000 until March 2021, prior to Husky’s amalgamation with Cenovus.
Frank J. Sixt (4) Hong Kong Special Administrative Region	2021	Mr. Sixt is an Executive Director, Group Finance Director and Deputy Managing Director of CK Hutchison Holdings Limited, a publicly traded ports and related services, retail, infrastructure and telecommunications company. Mr. Sixt is also the Non-Executive Chairman of TOM Group Limited, a publicly traded technology and media company; an Executive Director of CK Infrastructure Holdings Limited, a publicly traded global infrastructure investment and development company; a Non-Executive Director of TPG Telecom Limited and a Director of Hutchison Telecommunications (Australia) Limited (“HTAL”), both publicly traded telecommunications service provider companies; and an Alternate Director to a Director of HTAL, of HK Electric Investments Manager Limited as the trustee-manager of HK Electric Investments, manager of a publicly traded power industry focused trust; and of HK Electric Investments Limited, a publicly traded power industry focused trust. Mr. Sixt is also a Commissioner of PT Indosat Tbk, a publicly traded telecommunications service provider. Mr. Sixt is a Director of the Li Ka Shing (Canada) Foundation, the Li Ka Shing Foundation Limited and he was a director of Husky, from August 2000 until March 2021, prior to Husky’s amalgamation with Cenovus.
Rhonda I. Zygocki (2) (4) Friday Harbor, Washington United States	2016	Ms. Zygocki served as Executive Vice President, Policy and Planning of Chevron Corporation (“Chevron”), a publicly traded integrated energy company, from March 2011 until her retirement in February 2015 and prior thereto, during her 34 years with Chevron, she held a number of senior management and executive leadership positions in international operations, public affairs, strategic planning, policy, government affairs and health, environment and safety.

(1)Directors were elected or appointed to Cenovus’s Board as follows:

•Ms. Zygocki and Mr. Marcogliese were first elected as directors of Cenovus at the annual meeting of shareholders held on April 27, 2016.

•Mr. Mongeau was appointed as a director of Cenovus as of December 1, 2016.

•Mr. Pourbaix was appointed as President and Chief Executive Officer and a director of Cenovus as of November 6, 2017.

•Messrs. Kvisle and MacPhail were first elected as directors of Cenovus at the annual meeting of shareholders held on April 25, 2018.

•Ms. Kinney was first elected as a director of Cenovus at the annual meeting of shareholders held on April 24, 2019.

•Mr. Casey was first elected as a director of Cenovus as of April 29, 2020.

•Mrs. Kwok, and Messrs. Fok, Shaw and Sixt were appointed as directors of Cenovus as of January 1, 2021.

•Ms. Little was appointed as of January 1, 2023.

The term of each director is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed.

(2)Member of the Human Resources and Compensation Committee. Ms. Little was appointed January 1, 2023 to the Human Resources and Compensation Committee.

(3)Member of the Audit Committee.

(4)Member of the Governance Committee.

(5)Member of the Safety, Sustainability and Reserves Committee. Ms. Little was appointed January 1, 2023 to the Safety, Sustainability and Reserves Committee.

(6)Ex officio, by standing invitation, non-voting member of the Audit Committee, the Human Resources and Compensation Committee and the Safety, Sustainability and Reserves Committee. As an ex officio non-voting member, Mr. MacPhail attends as his schedule permits and may vote when necessary to achieve a quorum.

(7)As an officer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board.

Cenovus Energy Inc. – 2022 Annual Information Form 48

Executive Officers

The following individuals are the executive officers of Cenovus:

Name and Residence	Office Held and Principal Occupation During the Past Five Years
Alexander J. Pourbaix Calgary, Alberta Canada	President & Chief Executive Officer Mr. Pourbaix’s biographical information is included under “Directors”.
Jeffrey R. Hart Calgary, Alberta Canada	Executive Vice-President & Chief Financial Officer Mr. Hart was appointed Executive Vice-President & Chief Financial Officer of Cenovus effective January 1, 2021. From November 2018 to January 1, 2021, Mr. Hart was Chief Financial Officer of Husky; from April 2018 to November 2018, Mr. Hart was Acting Chief Financial Officer of Husky; and from October 2015 to April 2018, Mr. Hart was Vice President, Controller of Husky Oil Operations Limited.
Jonathan M. McKenzie Calgary, Alberta Canada	Executive Vice-President & Chief Operating Officer Mr. McKenzie was appointed Executive Vice-President & Chief Operating Officer of Cenovus effective January 1, 2021. From May 2018 to January 1, 2021, Mr. McKenzie was Executive Vice-President and Chief Financial Officer of Cenovus. From April 2015 to April 2018, Mr. McKenzie was Chief Financial Officer of Husky. From April 2011 to April 2015, Mr. McKenzie was Chief Financial Officer and Chief Commercial Officer of Irving Oil Ltd.; and from March 2009 to May 2011, Mr. McKenzie was Vice-President and Controller of Suncor Energy Inc.
Keith A. Chiasson Calgary, Alberta Canada	Executive Vice-President, Downstream Mr. Chiasson was appointed Executive Vice-President, Downstream of Cenovus effective March 1, 2019. From December 2017 to February 2019, Mr. Chiasson was Senior Vice-President, Downstream of Cenovus; from May 2017 to December 2017, Mr. Chiasson was Vice-President, Oil Sands Production Operations of Cenovus; and from July 2016 to May 2017, Mr. Chiasson was Vice-President, Operations of Cenovus. From April 2016 to July 2016, Mr. Chiasson was Kearl Operations Manager at Imperial Oil Resources; from September 2013 to April 2016, Mr. Chiasson was U.S. Operations Manager for ExxonMobil; and from January 2012 to September 2013, Mr. Chiasson was Planning and Business Analysis Manager for ExxonMobil Production Company.
P. Andrew Dahlin Calgary, Alberta Canada	Executive Vice-President, Corporate & Operations Services Mr. Dahlin was appointed Executive Vice-President, Corporate & Operations Services of Cenovus effective March 1, 2022. From January 1, 2021 to February 28, 2022, Mr. Dahlin was Executive Vice-President, Safety & Operations Technical Services. From November 2020 to January 1, 2021, Mr. Dahlin was Executive Vice-President, Downstream of Husky; from May 2020 to November 2020, Mr. Dahlin was Executive Vice President, Onshore Upstream of Husky; from May 2018 to May 2020, Mr. Dahlin was Senior Vice President, Heavy Oil & Oil Sands of Husky Oil Operations Limited; from June 2017 to May 2018, Mr. Dahlin was Senior Vice President, Heavy Oil of Husky Oil Operations Limited; and from April 2012 to May 2017, Mr. Dahlin was Vice President, Upstream of Husky Oil Operations Limited.
Norrie C. Ramsay Calgary, Alberta Canada	Executive Vice-President, Upstream – Thermal, Major Projects & Offshore Dr. Ramsay was appointed Executive Vice-President, Upstream – Thermal, Major Projects & Offshore of Cenovus effective January 1, 2021. From January 2020 to January 1, 2021, Dr. Ramsay was Executive Vice-President, Upstream of Cenovus; from December 2019 to January 2020, Dr. Ramsay was Executive Vice-President of Cenovus. From June 2019 to November 2019, Dr. Ramsay was Senior Vice-President, Projects at TC Energy; from August 2014 to May 2019, Dr. Ramsay was Senior Vice-President, Technical Centre & Projects at TC Energy; and from May 2010 to July 2014, Dr. Ramsay was Global Vice-President, Projects & Engineering at Talisman Energy Inc.
Karamjit S. Sandhar Calgary, Alberta Canada	Executive Vice-President, Strategy & Corporate Development Mr. Sandhar was appointed Executive Vice-President, Strategy & Corporate Development of Cenovus effective January 1, 2021. From January 2020 to January 1, 2021, Mr. Sandhar was Senior Vice-President, Conventional of Cenovus, and Senior Vice-President, Deep Basin of Cenovus prior to the Deep Basin segment being renamed the Conventional segment in the first quarter of 2020. From December 2017 to December 2019, Mr. Sandhar was Senior Vice-President, Strategy & Corporate Development of Cenovus; from July 2016 until December 2017, Mr. Sandhar was Vice-President, Investor Relations & Corporate Development of Cenovus; and from May 2016 to July 2016, Mr. Sandhar was Vice-President, Investor Relations of Cenovus.

Cenovus Energy Inc. – 2022 Annual Information Form 49

Name and Residence	Office Held and Principal Occupation During the Past Five Years
J. Drew Zieglgansberger Calgary, Alberta Canada	Executive Vice-President, Natural Gas & Technical Services Mr. Zieglgansberger was appointed Executive Vice-President, Natural Gas & Technical Services of Cenovus effective March 1, 2022. From January 1, 2021 to February 28, 2022, Mr. Zieglgansberger was Executive Vice-President, Upstream – Conventional & Integration of Cenovus; from January 2020 to January 1, 2021, Mr. Zieglgansberger was Executive Vice-President, Strategy & Corporate Development of Cenovus; from January 2018 to December 2019, Mr. Zieglgansberger was Executive Vice-President, Upstream of Cenovus; from April 2017 to January 2018, Mr. Zieglgansberger was Executive Vice-President, Deep Basin of Cenovus; from September 2015 to April 2017, Mr. Zieglgansberger was Executive Vice-President, Oil Sands Manufacturing of Cenovus; from June 2015 to August 2015, Mr. Zieglgansberger was Executive Vice- President, Operations Shared Services of Cenovus; from June 2012 to May 2015, Mr. Zieglgansberger was Senior Vice-President, Operations Shared Services of Cenovus; from January 2012 to May 2012, Mr. Zieglgansberger was Senior Vice-President, Regulatory, Local Community & Military of Cenovus; and from December 2010 to January 2012, Mr. Zieglgansberger was Senior Vice-President, Christina Lake of Cenovus.
Rhona M. DelFrari Calgary, Alberta Canada	Chief Sustainability Officer & Senior Vice-President, Stakeholder Engagement Ms. DelFrari was appointed Chief Sustainability Officer & Senior Vice-President, Stakeholder Engagement of Cenovus effective January 1, 2021. From October 2019 to December 2020, Ms. DelFrari was Vice-President, Sustainability & Engagement of Cenovus. From May 2018 to October 2019, Ms. DelFrari was Vice-President, Communications & External Engagement of Cenovus. From October 2017 to May 2018, Ms. DelFrari was Vice-President, Communications & Community Engagement of Cenovus. From June 2017 to October 2017, Ms. DelFrari was Vice-President, Communications & Reputation Management of Cenovus. From January 2008 to June 2017, Ms. DelFrari held various positions within Cenovus’s communications and strategy portfolios.
Gary F. Molnar Calgary, Alberta Canada	Senior Vice-President, Legal, General Counsel & Corporate Secretary Mr. Molnar was appointed Senior Vice-President Legal, General Counsel & Corporate Secretary of Cenovus effective January 1, 2021. From December 2015 to January 1, 2021, Mr. Molnar was Vice-President, Legal, Assistant General Counsel & Corporate Secretary of Cenovus; from March 2011 to December 2015, Mr. Molnar was Vice-President, Legal & Assistant Corporate Secretary of Cenovus; and from November 2009 to March 2011, Mr. Molnar was Vice-President & Assistant Corporate Secretary of Cenovus.
Susan M. Anderson Calgary, Alberta Canada	Senior Vice-President, People Services Ms. Anderson was appointed Senior Vice-President, People Services of Cenovus effective March 1, 2022. From January 2021 to February 2022, Ms. Anderson was Vice-President, Supply Chain Management of Cenovus. From November 2017 to January 2021, Ms. Anderson was Vice-President and Chief Procurement Officer of Husky; and from December 2013 to November 2017, Ms. Anderson was Vice-President, Legal of Husky.

As of December 31, 2022, all of Cenovus’s directors and executive officers, as a group, beneficially owned or exercised control or direction over, directly or indirectly, 3,776,348 common shares or approximately 0.20 percent of the number of common shares that were outstanding as of such date.

Investors should be aware that some of Cenovus’s directors and officers are directors and officers of other private and public companies. Some of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise. Any such conflicts shall be resolved in accordance with the Code and procedures and requirements of the relevant provisions of the CBCA, including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of Cenovus.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

To the Company’s knowledge, none of its current directors or executive officers are, as at the date of this AIF, or have been, within 10 years prior to the date of this AIF, a director, chief executive officer or chief financial officer of any company that:

(a)was subject to a cease trade order, an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days (each, an “Order”) that was issued while that director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or

(b)was subject to an Order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

To the Company’s knowledge, none of its directors or executive officers:

(a)is, as at the date of this AIF, or has been within 10 years prior to the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or

Cenovus Energy Inc. – 2022 Annual Information Form 50

(b)has, within 10 years prior to the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director or executive officer.

To the Company’s knowledge, none of its directors or executive officers has been subject to:

(a)any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or

(b)any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

AUDIT COMMITTEE

The Audit Committee mandate is included as Appendix C to this AIF.

Composition of The Audit Committee

The Audit Committee consists of four members, each of whom is independent and financially literate in accordance with National Instrument 52-110 “Audit Committees”. The Board determined that each of the following members of Cenovus’s Audit Committee qualifies as an “audit committee financial expert”, as that term is defined under U.S. securities legislation: Claude Mongeau and Jane E. Kinney. The education and experience of each of the members of the Audit Committee relevant to the performance of the responsibilities as an Audit Committee member is outlined below.

Claude Mongeau (Audit Committee Chair)

Mr. Mongeau holds a Master’s in Business Administration degree from McGill University and has received honorary doctorate degrees from St. Mary’s and Windsor University. He is a director of The Toronto-Dominion Bank, an international financial institution, since March 2015, and Norfolk Southern Corporation, a publicly traded rail transportation provider, since September 2019. Mr. Mongeau served as a director of TELUS Corporation, a publicly traded telecommunications company, from May 2017 to August 2019. He served as a director of Canadian National Railway Company (“CN”), a publicly traded railroad and transportation company, from October 2009 to July 2016 and as President and Chief Executive Officer from January 2010 to June 2016. During his tenure with CN, he served as Executive Vice-President and Chief Financial Officer from October 2000 until December 2009 and from the time he joined CN in 1994 he held the titles of Senior Vice-President and Chief Financial Officer, Vice-President, Strategic and Financial Planning and Assistant Vice-President, Corporate Development.

Jane E. Kinney

Ms. Kinney is a chartered professional accountant, a Fellow of the Chartered Professional Accountants of Ontario (FCPA) and holds a Mathematics degree from the University of Waterloo. She is a seasoned business leader with over 30 years of experience in providing advisory services to global financial institutions and has extensive experience in enterprise risk management, regulatory compliance, cyber and IT risk management, digital transformation and stakeholder relations.

Ms. Kinney is a director and Chair of the Audit Committee of Intact Financial Corporation, a publicly traded insurance company, since May 2019. She spent 25 years with Deloitte and was admitted to the Deloitte Partnership in 1997. Ms. Kinney was appointed Vice Chair, Leadership Team Member of Deloitte in June 2010 and served in this role until her retirement in June 2019. Ms. Kinney’s previous positions with Deloitte include Canadian Managing Partner, Quality & Risk from May 2010 to June 2015, Global Chief Risk Officer from June 2010 to May 2012, and Risk and Regulatory Practice Leader from June 1999 to May 2010.

Richard J. Marcogliese

Mr. Marcogliese holds a Bachelor of Engineering degree in Chemical Engineering from the New York University School of Engineering and Science. He is the Principal of iRefine, LLC, a privately owned petroleum refining consulting company, since June 2011; and a director of Delek US Holdings, Inc., a publicly traded downstream energy company, since January 2020. Mr. Marcogliese served as Executive Advisor of Pilko & Associates L.P., a private chemical and energy advisory company, from June 2011 to December 2019; Operations Advisor to NTR Partners III LLC, a private investment company from October 2013 to December 2017; and from September 2012 to January 2016 as Operations Advisor to the Chief Executive Officer of Philadelphia Energy Solutions, a partnership between The Carlyle Group and a subsidiary of Energy Transfer Partners, L.P. that operated an oil refining complex on the U.S. Eastern seaboard.

Cenovus Energy Inc. – 2022 Annual Information Form 51

Wayne E. Shaw

Mr. Shaw holds a Bachelor of Arts degree and a Bachelor of Laws degree from the University of Alberta. He is a member of the Law Society of Ontario. He is the President of G.E. Shaw Investments Limited, a private investment holding company, since 2012. Prior to his retirement in 2013, Mr. Shaw was a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors, Toronto, Ontario.

The above list does not include Keith A. MacPhail who is, by standing invitation as Chair of the Board, an ex officio member of Cenovus’s Audit Committee.

Pre-Approval Policies and Procedures

Cenovus has adopted policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by PricewaterhouseCoopers LLP. The Audit Committee has established a budget for the provision of a specified list of audit and permitted non-audit services that the Audit Committee believes to be typical, recurring or otherwise likely to be provided by PricewaterhouseCoopers LLP, the Company’s auditor. Subject to the Audit Committee’s discretion, the budget generally covers the period between the adoption of the budget and the next meeting of the Audit Committee. The list of permitted services is sufficiently detailed to ensure that: (i) the Audit Committee knows precisely what services it is being asked to pre-approve; and (ii) it is not necessary for any member of management to make a judgment as to whether a proposed service fits within the pre-approved services.

Subject to the following paragraph, the Audit Committee has delegated authority to the Audit Committee to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP which are not otherwise pre-approved by the Audit Committee, including the fees and terms of the proposed services (“Delegated Authority”). Any required determination about the Chair’s unavailability will be required to be made by the good faith judgment of the applicable other member(s) of the Audit Committee after considering all facts and circumstances deemed by such member(s) to be relevant. All pre-approvals granted pursuant to Delegated Authority must be presented by the member(s) who granted the pre-approvals to the full Audit Committee at its next meeting.

The fees payable in connection with any particular service to be provided by PricewaterhouseCoopers LLP that have been pre-approved pursuant to Delegated Authority: (i) may not exceed $200,000, in the case of pre-approvals granted by the Chair of the Audit Committee; and (ii) may not exceed $50,000, in the case of pre-approvals granted by any other member of the Audit Committee.

All proposed services or the fees payable in connection with such services that have not already been pre-approved must be pre-approved by either the Audit Committee or pursuant to Delegated Authority. Prohibited services may not be pre-approved by the Audit Committee or pursuant to Delegated Authority.

External Auditor Service Fees

The following table provides information about the fees billed to Cenovus for professional services rendered by PricewaterhouseCoopers LLP in the years ended December 31, 2022 and 2021:

($ thousands)	2022	2021
Audit Fees (1)	4,153	2,974
Audit-Related Fees (2)	237	212
Tax Fees (3)	227	946
All Other Fees (4)	67	26
Total	4,684	4,158

(1)Audit fees consist of the aggregate fees billed for the audit of the Company’s consolidated financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.

(2)Audit-related fees consist of the aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported as audit fees. The services provided in this category included audit-related services in relation to Cenovus’s prospectuses and participation fees levied by the Canadian Public Accountability Board. Fees related to the acquisition or divestiture of assets are also included in audit-related fees.

(3)Tax fees consist of the aggregate fees billed for tax compliance, tax advice and expatriate tax services.

(4)All other fees relate to fees billed for the review of Extractive Sector Transparency Measures Act filings and services around filings.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

During the year ended December 31, 2022, there were no legal proceedings to which Cenovus is or was a party, or that any of its property is or was the subject of, which involves a claim for damages in an amount, exclusive of interest and costs, that exceeds 10 percent of Cenovus’s current assets and it is not aware of any such legal proceedings that are contemplated.

During the year ended December 31, 2022, there were no penalties or sanctions imposed against Cenovus by a court relating to securities legislation or by a securities regulatory authority, nor have there been any other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decision, and it has not entered into any settlement agreements before a court relating to securities legislation or with a securities regulatory authority.

Cenovus Energy Inc. – 2022 Annual Information Form 52

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the Company’s directors or executive officers or any person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10 percent of any class or series of Cenovus’s outstanding voting securities, or any associate or affiliate of any of the foregoing persons or companies, in each case, as at the date of this AIF, has or has had any material interest, direct or indirect, in any past transaction within the three most recently completed financial years or any proposed transaction that has materially affected or is reasonably expected to materially affect Cenovus.

TRANSFER AGENTS AND REGISTRARS

In Canada:	In the United States:
Computershare Investor Services, Inc. 8th Floor, 100 University Avenue Toronto, ON M5J 2Y1 Canada	Computershare Trust Company NA 250 Royall St. Canton, MA 02021 U.S.
Tel: 1-866-332-8898 Website: www.investorcentre.com/cenovus

MATERIAL CONTRACTS

Other than as set forth below, during the year ended December 31, 2022, Cenovus has not entered into any contracts, nor are there any contracts still in effect, that are material to Cenovus, other than contracts entered into in the ordinary course of business.

Arrangement Standstill Agreements

On October 24, 2020, each of Hutchison Whampoa Europe Investments S.à r.l. (“Hutchison”) and L.F. Investments S.à r.l. (“L.F. Investments”) entered into a separate standstill agreement with Cenovus (each, an “Arrangement Standstill Agreement”), with effect as of January 1, 2021. Each Arrangement Standstill Agreement sets forth certain restrictions and obligations in connection with such shareholder’s shareholdings in Cenovus following completion of the transactions contemplated by the Arrangement, including but not limited to the following:

(a)subject to certain exceptions, without the prior written consent of Cenovus, such shareholder agreed that it will not acquire, agree to acquire or make any proposal or offer to acquire voting or equity securities of Cenovus or any of its subsidiaries (other than Cenovus Warrants), securities convertible into, or exercisable or exchangeable for, voting or equity securities of Cenovus or any of its subsidiaries (other than Cenovus Warrants) or any assets of Cenovus or any of its subsidiaries;

(b)for a period of 18 months following January 1, 2021, such shareholder agreed not to transfer or cause the transfer of any common shares, except as otherwise permitted by the Arrangement Standstill Agreement;

(c)without the prior written consent of Cenovus, such shareholder will not transfer or cause the transfer of, either alone or in the aggregate with its affiliates, the other shareholder or the other shareholder’s affiliates, any common shares or Cenovus Warrants to any person, if such transfer would, to the knowledge of the shareholder, result in such person, together with any persons acting jointly or in concert with such person, beneficially owning, or controlling or directing, 20 percent or more of the then-outstanding common shares, except (i) transfers effected through an underwritten public offering (including an underwritten public offering undertaken pursuant to the applicable Arrangement Registration Rights Agreement (defined below); (ii) transfers effected as a result of the consummation of an arrangement, amalgamation, merger or other similar business combination transaction involving Cenovus which has been approved by a resolution of holders of the common shares, or made to an offeror in relation to a take-over bid as set out in the Arrangement Standstill Agreement; or (iii) transfers to an affiliate as permitted by the Arrangement Standstill Agreement (together with subparagraph (b), the “Transfer Restrictions”); and

(d)such shareholder is subject to voting restrictions with respect to certain Board matters relating to the election of Cenovus’s directors and in connection with any arrangement, amalgamation, merger or other similar business combination transaction involving Cenovus.

Cenovus Energy Inc. – 2022 Annual Information Form 53

The Arrangement Standstill Agreements terminate on the earlier of January 1, 2026, the date on which either of the Arrangement Standstill Agreement is terminated by the written agreement of the parties, provided that the Transfer Restrictions have been complied with under each Arrangement Standstill Agreement, the date on which Hutchison and L.F. Investments, together with their affiliates, cease to beneficially own, or control or direct, in aggregate, at least 10 percent of the then-outstanding common shares, or any Qualified Individual (as defined in the Arrangement Standstill Agreements) duly nominated in accordance with the Arrangement Standstill Agreements is not appointed to the Board in accordance with the Arrangement Standstill Agreements.

Copies of the Arrangement Standstill Agreements were filed on SEDAR on November 3, 2020, and available on SEDAR at sedar.com and EDGAR at sec.gov.

The following table summarizes the number of Cenovus securities subject to the Transfer Restrictions as at December 31, 2022:

Name of Holder	Designation of Securities	Number of Securities subject to Transfer Restrictions (1)	Percentage of Class
Hutchison Whampoa Europe Investments S.à r.l.	Common Shares	316,927,051	16.6
L.F. Investments S.à r.l.	Common Shares	231,194,699	12.1
Total		548,121,750	28.7

(1)     The date on which the Transfer Restrictions end is described above.

Arrangement Registration Rights Agreements

On January 1, 2021, Cenovus and each of Hutchison and L.F. Investments entered into a registration rights agreement (each, an “Arrangement Registration Rights Agreement”) which provides such shareholders with certain rights to facilitate the sale of their Registrable Securities (as defined in the Arrangement Registration Rights Agreements), including the right to require Cenovus to qualify the distribution of the Registrable Securities held by such shareholders and the right to piggy-back on an offering of common shares by Cenovus. These rights are available to such shareholders for a term that began on July 1, 2022, and will cease on the earlier of January 1, 2026, the date on which the Arrangement Registration Rights Agreement is terminated by agreement of the parties, the date the holder ceases to, directly or indirectly, beneficially own in aggregate more than 5 percent of the then-outstanding common shares, or the date on which the Arrangement Standstill Agreements are terminated.

Copies of the Arrangement Registration Rights Agreements were filed on SEDAR on January 4, 2021, and available on SEDAR at sedar.com and EDGAR at sec.gov.

Arrangement Pre-Emptive Rights Agreements

On January 1, 2021, Cenovus and each of Hutchison and L.F. Investments entered into a pre-emptive rights agreement (each, an “Arrangement Pre-Emptive Rights Agreement”) that provides such shareholders with certain rights to allow such shareholder to maintain its pro rata share of the then-outstanding common shares. These rights are available to such shareholders for a term that began on January 1, 2021, and will cease on the earlier of January 1, 2026, the date on which the Arrangement Pre-Emptive Rights Agreement is terminated by agreement of the parties, the date the shareholder ceases to, directly or indirectly, beneficially own in aggregate more than 5 percent of the then-outstanding common shares, or the date on which the Arrangement Standstill Agreements are terminated.

Copies of the Arrangement Pre-Emptive Rights Agreements were filed on SEDAR on January 4, 2021, and available on SEDAR at sedar.com and EDGAR at sec.gov.

Warrant Indenture

At closing of the Arrangement, the Cenovus Warrants were created and issued pursuant to the terms of the Warrant Indenture entered into with Computershare Trust Company of Canada, as warrant agent, which governs the Cenovus Warrants. The Warrant Indenture provides for customary adjustments to the number of common shares issuable upon exercise of the Cenovus Warrants and/or to the exercise price in effect for the Cenovus Warrants, and for adjustment in the class and/or number of securities issuable upon exercise of the Cenovus Warrants and/or to the exercise price for the Cenovus Warrants, upon the occurrence of certain events. Cenovus also covenants in the warrant Indenture that, so long as any Cenovus Warrant remains outstanding, Cenovus will give notice to holders of Cenovus Warrants of certain stated events, including events that would result in an adjustment to the exercise price for the Cenovus Warrants or the number of common shares issuable upon exercise of the Cenovus Warrants, at least 10 business days prior to the record date of such event.

A copy of the Warrant Indenture was filed on SEDAR on January 4, 2021, and available on SEDAR at sedar.com and EDGAR at sec.gov.

Cenovus Energy Inc. – 2022 Annual Information Form 55

INTERESTS OF EXPERTS

The Company’s independent auditors are PricewaterhouseCoopers LLP, who have issued an independent auditor’s report dated February 15, 2023 in respect of Cenovus’s consolidated financial statements that comprise the consolidated balance sheets as at December 31, 2022 and December 31, 2021 and the consolidated statements of earnings (loss), consolidated statements of comprehensive income (loss), consolidated statements of equity and consolidated statements of cash flows for the years ended December 31, 2022, 2021, and 2020 and Cenovus’s internal control over financial reporting as at December 31, 2022. PricewaterhouseCoopers LLP has advised that they are independent with respect to Cenovus within the meaning of the Code of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules of the SEC.

Information relating to reserves in this AIF has been calculated by McDaniel and GLJ as independent qualified reserves evaluators. The partners, employees or consultants of each of McDaniel and GLJ, in each case, as a group own beneficially, directly or indirectly, less than one percent of any class of the Company’s outstanding securities.

ADDITIONAL INFORMATION

Additional information relating to Cenovus is available on SEDAR at sedar.com, on EDGAR at sec.gov and on the Company’s website at cenovus.com. Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of Cenovus’s securities, and securities authorized for issuance under its equity-based compensation plans, is included in the Company’s management information circular for its most recent annual meeting of shareholders.

Additional financial information concerning Cenovus as at December 31, 2022, can be found in Cenovus’s consolidated financial statements and MD&A for the year ended December 31, 2022.

As a Canadian corporation listed on the NYSE, Cenovus is not required to comply with most of the NYSE’s corporate governance standards, and instead may comply with Canadian corporate governance practices. However, the Company is required to disclose the significant differences between its corporate governance practices and the requirements applicable to U.S. domestic companies listed on the NYSE. Except as summarized on the Company’s website at cenovus.com, the Company is in compliance with the NYSE corporate governance standards in all significant respects.

ACCOUNTING MATTERS

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars. All references to “dollars”, “C$” or to “$” are to Canadian dollars and all references to “US$” are to U.S. dollars. The information contained in this AIF is dated as at December 31, 2022 unless otherwise indicated. Numbers presented are rounded to the nearest whole number and tables may not add due to rounding.

Unless otherwise indicated, all financial information included in this AIF has been prepared in accordance with International Financial Reporting Standards, which are also generally accepted accounting principles for publicly accountable enterprises in Canada.

ABBREVIATIONS AND CONVERSIONS

Crude Oil and NGLs		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
Mbbls/d	thousand barrels per day	MMcf	million cubic feet
MMbbls	million barrels	MMcf/d	million cubic feet per day
BOE	barrel of oil equivalent	Bcf	billion cubic feet
MBOE/d	thousand barrels of oil equivalent per day	MMBtu	million British thermal units
MMBOE	million barrels of oil equivalent	AECO	Alberta Energy Company
WTI	West Texas Intermediate
WCS	Western Canadian Select
OPEC	Organization of Petroleum Exporting Countries

In this AIF, natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

Cenovus Energy Inc. – 2022 Annual Information Form 56

FORWARD-LOOKING INFORMATION

This AIF contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. This forward-looking information is identified by words such as “anticipate”, “believe”, “capacity”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “opportunities”, “option”, “plan”, “potential”, “project”, “progress”, “schedule”, “seek”, “strive”, “target”, “view”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: the closing of transactions; the amount and form of shareholder returns; the 2023 NCIB and share purchases thereunder; the impacts of the FNMPC; the timing of the start of production for assets currently under development; the extension of the production life of the Terra Nova field and the production therefrom; the timing of the return to production and operation of assets and facilities currently not producing or operating; expected levels of production, including from the West White Rose project; corporate sustainability and ESG targets; development of the Narrows Lake resource and timing to achieve first steam from the field; the Company’s ability and methods to fund future development costs; realizing the best margins and netbacks for the Company’s products and maximizing value; optimizing product mix, delivery points, transportation commitments and customer diversification; the focus of the Company's development programs; unlocking resource potential; drilling exploration wells and purchasing working interests; investment decisions; resuming production of suspended projects; capturing global prices for crude oil production; capturing value; restarting the Superior Refinery and ramping up throughput; the focus of, and timelines for, the development and completion of projects; forecast operating and financial results, including forecast production, sales prices, costs and cash flows; forecast capital expenditures; techniques expected to be used to recover reserves; abandonment and reclamation costs; expected payment of taxes, royalties and other payments; potential impacts of various identified risk factors, including those related to commodity prices and climate change; reserves and related information, future net revenue and future development costs; expected capacities, including for projects, processing, transportation and refining; anticipated timelines for future regulatory, partner or internal approvals; impact of regulatory measures; forecast commodity prices and trends and expected impacts to the Company; and future use and development of technology. Readers are cautioned not to place undue reliance on forward-looking information as the Corporation’s actual results may differ materially from those expressed or implied.

Statements relating to “reserves” are deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast oil and natural gas, natural gas liquids, condensate and refined products prices; light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits and cost synergies of acquisitions; the Company’s ability to successfully integrate the legacy businesses with its own and any costs associated therewith; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and throughput volumes; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change), Indigenous relations, interest rates, inflation, foreign exchange rates, competitive conditions and the supply and demand for crude oil and natural gas, NGLs, condensate and refined products; the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of fire, weather conditions, natural disaster, accidents, third-party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increases to the Company’s share price and market capitalization over the long term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue and fund future investments, sustainability and development plans and shareholder returns, including any increase thereto; realization of expected capacity to store within the Company’s oil sands reservoirs barrels not yet produced, including that the Company will be able to time production and sales of our inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and future crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to global supply factors and heavy crude processing capacity; the ability of the Company’s refining capacity, dynamic storage, existing pipeline commitments, crude-by-rail loading capacity and financial hedge transactions to partially mitigate a portion of the Company’s WCS crude oil volumes against wider differentials; the Company’s ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company’s ability to generate sufficient cash

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flow to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability to complete acquisitions and dispositions, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; alignment of realized WCS and WCS prices used to calculate the variable payment to BP; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2023 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities. 2023 guidance, as updated December 5, 2022, and available on cenovus.com, assumes: Brent prices of US$83.00 per barrel, WTI prices of US$77.00 per barrel; WCS of US$54.50 per barrel; Differential WTI-WCS of US$22.50 per barrel; AECO natural gas prices of $4.85 per thousand cubic feet; Chicago 3-2-1 crack spread of US$26.50 per barrel; and an exchange rate of $0.75 US$/C$.

The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the effect of the COVID-19 pandemic, including any variants thereof, on the Company’s business, including any related restrictions, containment, and treatment measures taken by varying levels of government in the jurisdictions in which the Company operates; the success of the Company’s COVID-19 workplace policies and the return of people to the Company’s workplace; the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; the Company’s ability to successfully integrate acquired businesses with its own in a timely and cost effective manner; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and dispositions; the Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; developing and implementing strategies to meet climate and GHG emissions targets and ambitions; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; foreign exchange risk; the Company’s continued liquidity being sufficient to sustain operations through a prolonged market downturn; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to recalculate the variable payment to bp; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events resulting in operational interruptions, including at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics or pandemics, and catastrophic events, including, but not limited to, war, adverse sea conditions, extreme weather events, natural disasters, acts of activism, vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or

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crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s business, including potential cyberattacks; geopolitical and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and the Company’s ability to attract and retain, critical and diverse talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets, commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors in its most recently filed annual Management’s Discussion and Analysis, and to the risk factors described in other documents the Company files from time to time with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Company’s website at cenovus.com.

Information on or connected to the Company’s website at cenovus.com does not form part of this AIF unless expressly incorporated by reference herein.

Cenovus Energy Inc. – 2022 Annual Information Form 59

APPENDIX A

Report on Reserves Data By Independent Qualified Reserves Evaluators

To the Board of Directors of Cenovus Energy Inc. (the “Corporation”):

1.We have evaluated the Corporation’s reserves data as at December 31, 2022. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2022, estimated using forecast prices and costs.

2.The reserves data are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

3.We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”) maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

4.Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

5.The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated for the year ended December 31, 2022, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation’s Board of Directors:

Independent Qualified Reserves Evaluator	Effective Date of Evaluation Report	Location of Reserves	Evaluated Net Present Value of Future Net Revenue (Before Income Taxes, 10% Discount Rate) ($ millions)
McDaniel & Associates Consultants Ltd.	December 31, 2022	Canada	69,326
McDaniel & Associates Consultants Ltd.	December 31, 2022	China	3,629
McDaniel & Associates Consultants Ltd.	December 31, 2022	Indonesia	596
GLJ Ltd.	December 31, 2022	Canada	4,026
			77,577

6.In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.

7.We have no responsibility to update our reports referred to in paragraph five for events and circumstances occurring after their respective effective dates.

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

Executed as to our report referred to above:

/s/ Brian R. Hamm	/s/ Jodi L. Anhorn
Brian R. Hamm, P. Eng. President & CEO McDaniel & Associates Consultants Ltd. Calgary, Alberta, Canada	Jodi L. Anhorn, M.Sc., P. Eng. President and Chief Executive Officer GLJ Ltd. Calgary, Alberta, Canada

February 14, 2023

Cenovus Energy Inc. – 2022 Annual Information Form 60

APPENDIX B

Report of Management and Directors on Reserves Data and Other Information

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

Independent qualified reserves evaluators have evaluated the Corporation’s reserves data. A report from the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.

The Safety, Sustainability and Reserves Committee of the Board of Directors of the Corporation has:

(a)reviewed the Corporation’s procedures for providing information to the independent qualified reserves evaluators;

(b)met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and

(c)reviewed the reserves data with management and each of the independent qualified reserves evaluators.

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

(a)the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b)the filing of the report of the independent qualified reserves evaluators on the reserves data; and

(c)the content and filing of this report.

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

/s/ Alexander J. Pourbaix	/s/ Jeffrey R. Hart
Alexander J. Pourbaix President & Chief Executive Officer	Jeffrey R. Hart Executive Vice-President & Chief Financial Officer
/s/ Keith A. MacPhail	/s/ Richard J. Marcogliese
Keith A. MacPhail Director and Chair of the Board	Richard J. Marcogliese Director and Chair of the Safety, Sustainability and Reserves Committee

February 15, 2023

Cenovus Energy Inc. – 2022 Annual Information Form 61

APPENDIX C

Audit Committee Mandate

The Audit Committee (the “Committee”) is a committee of the Board of Directors(the “Board”) of Cenovus Energy Inc. (“Cenovus” or the “Corporation”) appointed to act in an advisory capacity to the Board and assist the Board in fulfilling its oversight responsibilities.

The Committee’s primary duties and responsibilities are to:

•Oversee and monitor the effectiveness and integrity of the Corporation’s accounting and financial reporting processes, financial statements and system of internal controls regarding accounting and financial reporting compliance.

•Oversee audits of the Corporation’s financial statements.

•Oversee and monitor the Corporation’s market risk management framework, including supporting guidelines and policies, related to the management of commodity price, currency (foreign exchange), and interest rate market risk.

•Oversee and monitor management’s identification of principal financial risks and monitor the process to manage such risks.

•Oversee and monitor the Corporation’s compliance with legal and regulatory requirements related to financial reporting and disclosures.

•Oversee and monitor the qualifications, independence and performance of the Corporation’s external auditors and internal auditing group.

•Provide an avenue of communication among the external auditors, management, the internal auditing group and the Board.

The Committee has the authority to conduct any review or investigation appropriate to fulfilling its responsibilities. The Committee shall have unrestricted access to personnel and information, and any resources necessary to carry out its responsibility. In this regard, the Committee may direct internal audit personnel to particular areas of examination.

Constitution, Composition and Definitions

1.Reporting

The Committee shall report to the Board.

2.Composition of Committee

The Committee shall consist of not less than three and not more than eight directors, all of whom shall qualify as independent directors pursuant to National Instrument 52-110 Audit Committees (as implemented by the Canadian Securities Administrators (“CSA”) and as amended from time to time) (“NI 52-110”).

All members of the Committee shall be financially literate, as defined in NI 52-110, and at least one member shall have accounting or related financial managerial expertise.

At least one member shall have experience in the oil and gas industry.

Committee members shall not simultaneously serve on the audit committees of more than two other public companies, unless the Board first determines that such simultaneous service shall not impair the ability of the relevant members to effectively serve on the Committee, and required public disclosure is made.

The non-executive Board Chair shall be a non-voting member of the Committee. See “Quorum” for further details.

3.Appointment of Committee Members

Committee members shall be appointed by the Board, effective after the election of directors at the annual meeting of shareholders, provided that any member may be removed or replaced, subject to any requirements under the heading “Composition of Committee” above, at any time by the Board and shall, in any event, cease to be a Committee member upon ceasing to be a Board member.

4.Vacancies

Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board.

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5.Chair

The Governance Committee shall recommend for approval to the Board an independent Director to act as Chair of the Committee (the “Chair”). The Board shall appoint the Chair.

If unavailable or unable to attend a meeting of the Committee, the Chair shall ask another member to chair the meeting, failing which a member of the Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting.

The Chair presiding at any meeting of the Committee shall not have a casting vote.

The items pertaining to the Chair in this section should be read in conjunction with the Committee Chair section of the Chair of the Board of Directors and Committee Chair General Guidelines.

6.Secretary

The Committee shall appoint a Secretary who need not be a member of the Committee. The Secretary shall keep minutes of the meetings of the Committee.

7.Committee Meetings

The Committee shall meet at least quarterly. The Chair may call additional meetings as required. In addition, a meeting may be called by the non-executive Board Chair, the President & Chief Executive Officer, or any member of the Committee or by the external auditors.

Committee meetings may, by agreement of the Chair, be held in person, by video conference, by means of telephone, by other electronic or communication facility or by a combination of any of the foregoing.

At every Committee meeting the Committee shall meet without the presence of management.

8.Notice of Meeting

Notice of the time and place of each meeting may be given orally, or in writing, or by facsimile, or by electronic means to each member of the Committee at least 24 hours prior to the time fixed for such meeting. Notice of each meeting shall also be given to the external auditors of the Corporation.

A member and the external auditors may, in any manner, waive notice of the Committee meeting. Attendance of a member at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.

9.Quorum

A majority of Committee members, present in accordance with section 7, shall constitute a quorum. In addition, if an ex officio, non-voting member’s presence is required to attain a quorum of the Committee, then the said member shall be allowed to cast a vote at the meeting.

10.Attendance at Meetings

The President & Chief Executive Officer, the Chief Financial Officer, the Comptroller and the head of internal audit are expected to be available to attend the Committee’s meetings or portions thereof.

The Committee may, by specific invitation, have other resource persons in attendance.

The Committee shall have the right to determine who shall, and who shall not, be present at any time during a meeting of the Committee.

Directors who are not members of the Committee may attend Committee meetings, on an ad hoc basis, upon prior consultation and approval by the Chair or by a majority of the members of the Committee.

11.Minutes

Minutes of Committee meetings shall be sent to all Committee members. The Committee shall report its activities to the full Board at the next regularly scheduled Board meeting or more frequently as determined appropriate by the Chair.

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Specific Responsibilities

In carrying out its oversight responsibilities and its mandate, the Committee is expected to:

12.Review Procedures

(a)Review the summary of the Committee’s composition and responsibilities in the Corporation’s annual report, annual information form or other public disclosure documentation.

(b)Review the summary of all approvals by the Committee of the provision of audit, audit-related, tax and other services by the external auditors for inclusion in the Corporation’s annual report and annual information form, or other publicly filed disclosure documentation.

13.Annual Financial Statements

(a)Discuss and review with management and the external auditors the Corporation’s and any subsidiary with public securities’ annual audited financial statements and related documents prior to their filing or distribution. Such review shall include:

(i)The annual financial statements and related notes including significant issues regarding accounting principles, practices and significant management estimates and judgments, including any significant changes in the Corporation’s selection or application of accounting principles, any major issues as to the adequacy of the Corporation’s internal controls and any special steps adopted in light of material control deficiencies.

(ii)Management’s Discussion and Analysis.

(iii)The use of off-balance sheet financing, including management’s risk assessment and adequacy of disclosure.

(iv)The external auditors’ audit examination of the financial statements and their report thereon.

(v)Any significant changes required in the external auditors’ audit plan.

(vi)Any serious difficulties or disputes with management encountered during the course of the audit, including any restrictions on the scope of the external auditors’ work or access to required information.

(vii)Other matters related to the conduct of the audit, which are to be communicated to the Committee under generally accepted auditing standards.

(b)Review and formally recommend approval to the Board of the Corporation’s:

(i)Year-end audited financial statements. Such review shall include discussions with management and the external auditors as to:

i.The accounting policies of the Corporation and any changes thereto.

ii.The effect of significant judgments, accruals and estimates.

iii.The manner of presentation of significant accounting items.

iv.The consistency of disclosure.

(ii)Management’s Discussion and Analysis.

(iii)Annual Information Form as to financial information.

(iv)All prospectuses and information circulars, as to financial information.

The review shall include a report from the external auditors about the quality of the most critical accounting principles upon which the Corporation’s financial status depends, and which involve the most complex, subjective or significant judgmental decisions or assessments.

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14.Quarterly Financial Statements

(a)Review with management and the external auditors and either approve (such approval to include the authorization for public release) or formally recommend for approval to the Board the Corporation’s:

(i)Quarterly unaudited financial statements and related documents, including Management’s Discussion and Analysis.

(ii)Any significant changes to the Corporation’s accounting principles.

(b)Review quarterly unaudited financial statements prior to their distribution of any subsidiary of the Corporation with public securities.

15.Other Financial Filings and Public Documents

Review and discuss with management financial information, including earnings press releases, the use of “pro forma” or non-GAAP financial information and earnings guidance, contained in any filings with the CSA or U.S. Securities and Exchange Commission (“SEC”) or press releases related thereto, and consider whether the information is consistent with the information contained in the financial statements of the Corporation or any subsidiary with public securities.

16.Internal Control Environment

(a)Receive from and review with management, the external auditors and the internal auditors an annual report on the Corporation’s control environment as it pertains to the Corporation’s financial reporting process and controls.

(b)Review and discuss significant financial risks or exposures and assess the steps management has taken to monitor, control, report and mitigate such risk to the Corporation.

(c)Review in consultation with the internal auditors and the external auditors, the degree of coordination in the audit plans of the internal auditors and the external auditors and enquire as to the extent the planned scope can be relied upon to detect weaknesses in internal controls, fraud or other illegal acts. The Committee shall assess the coordination of audit effort to assure completeness of coverage and the effective use of audit resources. Any significant recommendations made by the auditors for the strengthening of internal controls shall be reviewed and discussed with management.

(d)Review with the President & Chief Executive Officer, the Chief Financial Officer of the Corporation and the external auditors: (i) all significant deficiencies and material weaknesses in the design or operation of the Corporation’s internal controls and procedures for financial reporting which could adversely affect the Corporation’s ability to record, process, summarize and report financial information required to be disclosed by the Corporation in the reports that it files or submits under the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”) or applicable Canadian federal and provincial legislation and regulations within the required time periods, and (ii) any fraud, whether or not material, that involves management of the Corporation or other employees who have a significant role in the Corporation’s internal controls and procedures for financial reporting.

(e)Review significant findings prepared by the external auditors and the internal auditing department together with management’s responses.

17.Other Review Items

(a)Review the process for the certification of the interim and annual financial statements by the President & Chief Executive Officer and Chief Financial Officer, and the certifications made by the President & Chief Executive Officer and Chief Financial Officer.

(b)Review policies and procedures with respect to officers’ and directors’ expense accounts and perquisites, including their use of corporate assets, and consider the results of any review of these areas by the internal auditor or the external auditors.

(c)Review all related party transactions between the Corporation and any executive officers or directors, including affiliations of any executive officers or directors.

(d)Review with the General Counsel, the head of internal audit and the external auditors the results of their review of the Corporation’s monitoring of compliance with each of the Corporation’s published codes of business conduct and applicable legal requirements.

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(e)Review legal and regulatory matters, including correspondence with and reports received from regulators and government agencies, that may have a material impact on the interim or annual financial statements or other documents filed with regulators containing financial information and related corporate compliance policies and programs. Members from the Legal and Tax groups should be at the meeting to deliver their respective reports.

(f)Review policies and practices with respect to off-balance sheet transactions and trading and hedging activities, and consider the results of any review of these areas by the internal auditors or the external auditors.

(g)Ensure that the Corporation’s presentation of hydrocarbon reserves has been reviewed with the Safety, Sustainability and Reserves Committee of the Board.

(h)Review management’s processes in place to prevent and detect fraud.

(i)Review:

(i)procedures for the receipt, retention and treatment of complaints received by the Corporation, including confidential, anonymous submissions by employees of the Corporation, regarding accounting, internal accounting controls or auditing matters; and

(ii)a summary of any significant investigations regarding such matters.

(j)Meet on a periodic basis separately with management.

18.External Auditors

(a)Be directly responsible, in the Committee’s capacity as a committee of the Board and subject to the rights of shareholders and applicable law, for the appointment, compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an audit report, or performing other audit, review or attest services for the Corporation. The external auditors shall report directly to the Committee.

(b)Meet on a regular basis with the external auditors (without management present) and have the external auditors be available to attend Committee meetings or portions thereof at the request of the Chair or by a majority of the members of the Committee.

(c)Review and discuss a report from the external auditors at least quarterly regarding:

(i)All critical accounting policies and practices to be used;

(ii)All alternative treatments within accounting principles for policies and practices related to material items that have been discussed with management, including the ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditors; and

(iii)Other material written communications between the external auditors and management, such as any management letter or schedule of unadjusted differences.

(d)Obtain and review a report from the external auditors at least annually regarding:

(i)The external auditors’ internal quality-control procedures.

(ii)Any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with those issues.

(iii)To the extent contemplated in the following paragraph, all relationships between the external auditors and the Corporation.

(e)Review and discuss at least annually with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors’ independence, including, without limitation, (i) receiving and reviewing, as part of the report described in the preceding paragraph, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on the independence of the external auditors with respect to the Corporation and its affiliates, (ii) discussing with the external auditors any disclosed relationships or services that the external auditors believe may affect the objectivity and independence of the external auditors, and (iii) recommending that the Board take appropriate action in response to the external auditors’ report to satisfy itself of the external auditors’ independence.

Cenovus Energy Inc. – 2022 Annual Information Form 66

(f)Review and evaluate annually:

(i)The external auditors’ and the lead partner of the external auditors’ team’s performance, and make a recommendation to the Board regarding the reappointment of the external auditors at the annual meeting of the Corporation’s shareholders or regarding the discharge of such external auditors.

(ii)The terms of engagement of the external auditors together with their proposed fees.

(iii)External audit plans and results.

(iv)Any other related audit engagement matters.

(v)The engagement of the external auditors to perform non-audit services, together with the fees therefor, and the impact thereof, on the independence of the external auditors.

(vi)The Annual Report of the Canadian Public Accountability Board (“CPAB”) concerning audit quality in Canada and discuss implications for Cenovus.

(vii)Any reports issued by CPAB regarding the audit of Cenovus.

(g)Conduct periodically a comprehensive review of the external auditor, with the outcome intended to assist the Committee to identify potential areas for improvement for the audit firm, and to reach a final conclusion on whether the auditor should be reappointed or the audit put out for tender.

(h)Upon reviewing and discussing the information provided to the Committee in accordance with paragraphs 18.(c) through (f), evaluate the external auditors’ qualifications, performance and independence, including whether or not the external auditors’ quality controls are adequate and the provision of permitted non-audit services is compatible with maintaining auditor independence, taking into account the opinions of management and the head of internal audit. The Committee shall present to the Board its conclusions in this respect.

(i)Review the rotation of partners on the audit engagement team in accordance with applicable law. Consider whether, in order to assure continuing external auditor independence, it is appropriate to adopt a policy of rotating the external auditing firm on a regular basis.

(j)Set clear hiring policies for the Corporation’s hiring of employees or former employees of the external auditors.

(k)Consider with management and the external auditors the rationale for employing audit firms other than the principal external auditors.

(l)Consider and review with the external auditors, management and the head of internal audit:

(i)Significant findings during the year and management’s responses and follow-up thereto.

(ii)Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information, and management’s response.

(iii)Any significant disagreements between the external auditors or internal auditors and management.

(iv)Any changes required in the planned scope of their audit plan.

(v)The resources, budget, reporting relationships, responsibilities and planned activities of the internal auditors.

(vi)The internal audit department mandate.

(vii)Internal audit’s compliance with the Institute of Internal Auditors’ standards.

19.Internal Audit Group and Independence

(a)Meet on a periodic basis separately with the head of internal audit.

(b)Review and concur in the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit.

(c)Review with the head of internal audit the Internal Audit budget, resource plan, activities, organizational structure of the internal audit function and the qualifications of the internal auditors.

(d)Confirm and assure, annually, the independence of the internal audit group.

(e)Approve the Internal Audit Charter, and the annual Internal Audit Plan.

Cenovus Energy Inc. – 2022 Annual Information Form 67

(f)Review the performance and effectiveness of the Internal Audit function including conformance with The Institute of Internal Auditors’ International Standards for the Professional Practice of Internal Auditing and the Code of Ethics.

20.Approval of Audit and Non-Audit Services

(a)Review and, where appropriate, approve the provision of all permitted non-audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors (subject to the de minimus exception for non-audit services described in the Exchange Act or applicable CSA and SEC legislation and regulations, which services are approved by the Committee prior to the completion of the audit).

(b)Review and, where appropriate and permitted, approve the provision of all audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors.

(c)If the pre-approvals contemplated in paragraphs 20.(a) and (b) are not obtained, approve, where appropriate and permitted, the provision of all audit and non-audit services promptly after the Committee or a member of the Committee to whom authority is delegated becomes aware of the provision of those services.

(d)Delegate, if the Committee deems necessary or desirable, to subcommittees consisting of one or more members of the Committee, the authority to grant the pre-approvals and approvals described in paragraphs 20.(a) through (c). The decision of any such subcommittee to grant pre-approval shall be presented to the full Committee at the next scheduled Committee meeting.

(e)Establish policies and procedures for the pre-approvals described in paragraphs 20.(a) and (b) so long as such policies and procedures are detailed as to the particular service, the Committee is informed of each service and such policies and procedures do not include delegation to management of the Committee’s responsibilities under the Exchange Act or applicable CSA and SEC legislation and regulations.

21.Risk Oversight

The Committee is responsible for oversight of and reports to the Board about risks related to:

(a)The design and operating effectiveness of the Corporation’s market risk management control framework and the processes to manage such risks;

(b)Non-compliance with regulations and policies relating to matters within the Committee’s mandate;

(c)All financial filings and public documents, including the Corporation’s and any subsidiary with public securities’ annual audited financial statements and related documents, and all unaudited financial statements and related documents, and other filings and public documents as to financial information;

(d)The evaluation, appointment, compensation, retention and work of the external auditors;

(e)Together with management, the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit;

(f)The receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls, or auditing matters;

(g)Significant financial risks or exposures, including those related to environmental, social and governance (“ESG”) matters, such as climate change; and

(h)Such principal or emerging risks that have been assigned to the Committee, from time to time, by the Board, as recommended by the Governance Committee.

22.Environmental, Social and Governance (ESG) Oversight

The Committee is responsible for oversight of:

(a)The financial impacts from evolving ESG matters (including climate change) and in particular impacts on the Corporation’s access to capital from its lenders, debt investors, and equity investors, its access to insurance coverage, and to its credit ratings.

23.Miscellaneous

(a)The Committee, upon approval by a majority of the members of the Committee, may engage outside advisors if deemed advisable;

(b)The Committee, upon approval by a majority of the members of the Committee, may delegate its duties and responsibilities to subcommittees of the Committee;

Cenovus Energy Inc. – 2022 Annual Information Form 68

(c)Review with the President & Chief Executive Officer and subject to the concurrence of the Committee, recommend to the Board the appointment, replacement, reassignment, or dismissal of the Chief Financial Officer;

(d)Conduct or authorize investigations into any matters within the Committee’s scope of responsibilities. The Committee shall be empowered to retain, obtain advice or otherwise receive assistance from independent counsel, accountants, or others to assist it in the conduct of any investigation as it deems necessary and the carrying out of its duties;

(e)Determine the appropriate funding for payment by the Corporation (i) of compensation to the external auditors for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation, (ii) of compensation to any advisors employed by the Committee, and (iii) of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties;

(f)Review and reassess the adequacy of this mandate annually and recommend any proposed changes to the Governance Committee for consideration;

(g)Consider for implementation any recommendations of the Governance Committee of the Board with respect to the Committee’s effectiveness, structure or processes;

(h)Perform such other functions as required by law, the Corporation’s by-laws or the Board; and

(i)Consider any other matters referred to it by the Board.

The duties and responsibilities of a Committee member are in addition to those duties set out for a Board member.

Revised Effective: July 28, 2021

Cenovus Energy Inc. – 2022 Annual Information Form 69

EX-99.2

Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Year Ended December 31, 2022

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the year ended December 31, 2022

OVERVIEW OF CENOVUS	3
YEAR IN REVIEW	5
OPERATING AND FINANCIAL RESULTS	8
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	14
OUTLOOK	17
REPORTABLE SEGMENTS	19
UPSTREAM	19
OIL SANDS	19
CONVENTIONAL	23
OFFSHORE	25
DOWNSTREAM	29
CANADIAN MANUFACTURING	29
U.S. MANUFACTURING	31
CORPORATE AND ELIMINATIONS	33
QUARTERLY RESULTS	36
OIL AND GAS RESERVES	38
LIQUIDITY AND CAPITAL RESOURCES	39
RISK MANAGEMENT AND RISK FACTORS	45
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	69
CONTROL ENVIRONMENT	71
ADVISORY	72
ABBREVIATIONS AND DEFINITIONS	75
SPECIFIED FINANCIAL MEASURES	76
ADJUSTMENTS TO THE CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND SEGMENTED DISCLOSURES	90

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated February 15, 2023 should be read in conjunction with our December 31, 2022 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”). All of the information and statements contained in this MD&A are made as of February 15, 2023 unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (“the Board”), reviewed and recommended the MD&A for approval by the Board, which occurred on February 15, 2023. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.

Basis of Presentation

This MD&A and the Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, (which includes references to “dollar” or “$”), except where another currency has been indicated, and in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board. Production volumes are presented on a before royalties basis. Refer to the Abbreviations section for commonly used oil and gas terms.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis 2

OVERVIEW OF CENOVUS

We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”). Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. We are the second largest Canadian-based crude oil and natural gas producer, with upstream operations in Canada and the Asia Pacific region, and the second largest Canadian-based refiner and upgrader, with downstream operations in Canada and the United States (“U.S.”). On January 1, 2021, Cenovus and Husky Energy Inc. (“Husky”) closed a transaction    to combine the two companies through a plan of arrangement (the “Arrangement”).

Our upstream operations include oil sands projects in northern Alberta; thermal and conventional crude oil, natural gas and natural gas liquids (“NGLs”) projects across Western Canada; crude oil production offshore Newfoundland and Labrador; and natural gas and NGLs production offshore China and Indonesia. Our downstream operations include upgrading and refining operations in Canada and the U.S., and commercial fuel operations across Canada.

Our operations involve activities across the full value chain to develop, produce, refine, transport and market crude oil and natural gas in Canada and internationally. Our physically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil differentials and contribute to our net earnings by capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels.

Our Strategy

Our strategy is focused on maximizing shareholder value through competitive cost structures and optimizing margins, while delivering top-tier safety performance and sustainability leadership. The Company prioritizes Free Funds Flow generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and share repurchases, reinvest in our business and diversify our portfolio.

On December 6, 2022, we announced our 2023 budget focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost control and positioning the Company for continued growth in shareholder returns. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com. For further details see the Operating and Financial Results section of this MD&A.

Shareholder Returns and Capital Allocation Framework

Maintaining a strong balance sheet with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle is a key element of Cenovus’s capital allocation framework. In April 2022, we announced our updated capital allocation framework to continue to strengthen our balance sheet, which enables flexibility in both high and low commodity price environments, and improves our shareholder value proposition. We have set an ultimate Net Debt Target of $4 billion, which serves as a floor on Net Debt. We plan to return incremental value to shareholders, through share buybacks and/or variable dividends, as follows:

•When Net Debt is less than $9 billion and above $4 billion at quarter-end, we will target to allocate 50 percent of the Excess Free Funds Flow achieved in the following quarter to shareholder returns, while still continuing to deleverage the balance sheet until we reach the Net Debt Target of $4 billion.

•When Net Debt is above $9 billion at quarter-end, we plan to allocate all of the following quarter’s Excess Free Funds Flow to deleveraging the balance sheet.

•When Net Debt is at the $4 billion floor at quarter-end, we will target to return 100 percent of the following quarter’s Excess Free Funds Flow to shareholder returns.

Excess Free Funds Flow for the quarter is defined as Free Funds Flow(1):

•Minus base dividends paid on common shares.

•Minus dividends paid on preferred shares.

•Minus other uses of cash, including settlement of decommissioning liabilities and principal repayment of leases.

•Minus any net acquisition costs from acquisition activities closing in the quarter.

•Plus any proceeds from, or less any payments related to, divestiture activities closing in the quarter.

The Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to common shareholders, with lower leverage and a lower risk profile. Our $4 billion Net Debt Target represents a Net Debt to Adjusted Funds Flow Ratio Target of approximately 1.0 times at the bottom of the commodity price cycle.

Share buybacks will continue to be executed opportunistically, driven by return thresholds. Where the value of share buybacks in a quarter is less than the targeted value of returns, the remainder will be delivered through a variable dividend payable for that quarter, if the remainder is greater than $50 million. Where the value of share buybacks in a quarter is greater than or equal to the targeted value of returns, no variable dividend will be paid for that quarter.

(1)See the Liquidity and Capital Resources section of this MD&A for the calculation of Free Funds Flow.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  3

On September 30, 2022, our long-term debt was $8.8 billion, resulting in a Net Debtposition of $5.3 billion. Therefore, our returns to shareholders target for the three months ended December 31, 2022, was 50 percent of that quarter's Excess Free Funds Flow. During the three months ended December 31, 2022, we generated cash from operating activities of $3.0 billion, Excess Free Funds Flow of $786 million and returned $387 million to our shareholders through share buybacks. Returns to shareholders through share buybacks were within $50 million of our Target Return, as such no variable dividend was declared for the quarter.

	Three Months Ended December 31, 2022
($ millions)
Excess Free Funds Flow (1)	786
Target Return (2)	393
Less: Purchase of Common Shares Under our Normal Course Issuer Bid (“NCIB”)	(387)
Amount Available for Variable Dividend	6

(1)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

(2)Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, being less than $9 billion and greater than $4 billion, target return was determined to be 50 percent of Excess Free Funds Flow for the three months ended December 31, 2022.

On December 31, 2022, our Net Debt position was $4.3 billion and as a result our returns to shareholders target for the three months ended March 31, 2023, will be 50 percent of the first quarter’s Excess Free Funds Flow.

Our Operations

The Company operates through the following reportable segments:

Upstream Segments

•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

•Conventional, includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.

•Offshore, includes offshore operations, exploration and development activities in China and the East Coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

•Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.

•U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima Refinery and Superior Refinery, the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66) and the jointly-owned Toledo Refinery (jointly owned with operator BP Products North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel and jet fuel.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  4

Corporate and Eliminations

Corporate and Eliminations, primarily includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative periods have been re-presented to reflect this change.

YEAR IN REVIEW

In 2022, we continued to focus on health and safety and drive competitive cost structures. High commodity prices in both our upstream and downstream businesses combined with solid upstream operating performance and good operating performance in our operated downstream assets drove strong financial results and allowed us to significantly reduce our total debt. We optimized our asset portfolio as we closed the acquisition of Sunrise and announced the acquisition of Toledo, which will provide us full ownership and operatorship of both assets. In addition, we completed the restructuring of our Atlantic assets and reached an agreement with our partners to restart the West White Rose project. We also sold our Tucker, Wembley and retail assets. These transactions enhanced Cenovus’s core strength in the oil sands and will further optimize margins through increased physical integration of our upstream and downstream assets. Lastly, we improved our shareholder value proposition through an updated shareholder returns and capital allocation framework. The framework returns incremental value back to shareholders through share buybacks and/or variable dividends.

Summary of Annual Results

($ millions, except where indicated)	2022	Percent Change	2021	Percent Change	2020
Upstream Production Volumes (1)(MBOE/d)	786.2	(1)	791.5	68	471.7
Downstream Crude Oil Throughput (2)(Mbbls/d)	493.7	(3)	508.0	173	185.9
Revenues (3)	66,897	44	46,357	242	13,543
Operating Margin (4)	14,263	52	9,373	918	921
Cash From (Used In) Operating Activities	11,403	93	5,919	2,068	273
Adjusted Funds Flow (4)	10,978	51	7,248	6,095	117
Per Share – Basic (4)($)	5.63	57	3.59	3,490	0.10
Per Share – Diluted (4) ($)	5.47	55	3.54	3,440	0.10
Capital Investment	3,708	45	2,563	205	841
Free Funds Flow (4)	7,270	55	4,685	N/A	(724)
Net Earnings (Loss)(5)	6,450	999	587	N/A	(2,379)
Per Share – Basic ($)	3.29	1,119	0.27	N/A	(1.94)
Per Share – Diluted ($)	3.20	1,085	0.27	N/A	(1.94)

(1)Refer to the Operating and Financial Results section of this MD&A for a summary of total upstream production by product type.

(2)Represents Cenovus’s net interest in refining operations.

(3)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

(4)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

(5)Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  5

Summary of Annual Results

($ millions, except where indicated)	2022	Percent Change	2021	Percent Change	2020
Total Assets	55,869	3	54,104	65	32,770
Total Long-Term Liabilities	20,259	(13)	23,191	69	13,704
Long-Term Debt, Including Current Portion	8,691	(30)	12,385	66	7,441
Net Debt	4,282	(55)	9,591	34	7,184
Cash Returns to Shareholders
Common Shares – Base Dividends	682	288	176	129	77
Base Dividends Per Common Share($)	0.350	298	0.088	40	0.063
Common Shares – Variable Dividends	219	N/A	—	—	—
Variable Dividends Per Common Share($)	0.114	N/A	—	—	—
Purchase of Common Shares Under NCIB	2,530	855	265	N/A	—
Preferred Share Dividends	26	(24)	34	N/A	—

In 2022, we delivered on our strategy through five key strategic objectives:

Top Tier Safety Performance and Sustainability Leadership

Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. Safety, asset integrity and corporate governance are foundational to our business, and are the backbone for all of our operations. We promote a safety culture in all aspects of our work and use a variety of programs to always keep safety top of mind. In 2022, we:

•Delivered safe operations at our operated assets.

•Completed planned turnarounds at the operated Lloydminster Upgrader (the “Upgrader”) and Lloydminster Refinery in our downstream operations. In addition, we completed a planned turnaround at Christina Lake in our upstream operations in the second quarter.

•Completed planned turnarounds at the non-operated Toledo, Wood River and Borger refineries in our downstream operations.

•Continued our focus on achieving our targets in each of our five Environmental, Social and Governance (“ESG”) focus areas. Additional information on management’s efforts and performance across ESG topics, including our ESG targets and plans to achieve them, are available in Cenovus’s 2021 ESG report at cenovus.com.

•Actively participated in industry collaborations including the Pathways Alliance.

We continue to work with our partners of our non-operated downstream assets to improve the safety performance.

Competitive Cost Structures and Optimizing Margins

In 2022, we:

•Targeted additional cost savings and margin enhancements through further physical integration of upstream assets with downstream assets, which shortened the value chain and reduced condensate costs associated with heavy oil transportation.

•Improved efficiencies across Cenovus to drive incremental capital, operating, and general and administrative cost reductions.

Maintaining and Further Reducing Debt Levels

In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flowof $7.3 billion, enabling us to substantially decrease Net Debt.

•As at December 31, 2022, our long-term debt, including current portion, was $8.7 billion (December 31, 2021 – $12.4 billion) and our Net Debt position was $4.3 billion (December 31, 2021 – $9.6 billion).

•We deleveraged our balance sheet by purchasing US$2.6 billion in principal of notes due between 2023 and 2043, and $750 million in principal of notes due in 2025.

•Our Net Debt to Adjusted EBITDA Ratio was 0.3 times and our Net Debt to Adjusted Funds Flow Ratio was 0.4 times at December 31, 2022.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  6

Growing Free Funds Flow Through Pricing Cycles

Our top-tier assets and low-cost structure position us to grow Free Funds Flow through pricing cycles. Cenovus's diversified asset and product mix generates predictable and stable Free Funds Flow and reduces risk and cash flow volatility by leveraging pipelines, logistics and marketing to optimize the value chain. We are able to generate strong margins with modest capital investment.

In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, primarily due to high commodity prices combined with solid upstream operating performance. WTI averaged approximately US$94 per barrel in 2022, the highest annual average since 2013, and an increase of approximately 40 percent from 2021. North American market crack spreads also reached historic highs during the year.

In 2022, we continued to optimize our top-tier asset portfolio and grow Free Funds Flow.

In our upstream business:

•We sold our Tucker asset and our Wembley assets for total net proceeds of $951 million.

•We reached an agreement with our partners to restart the West White Rose project in the Atlantic region offshore Newfoundland and Labrador. Major construction is expected to restart in the first quarter of 2023.

•We acquired the remaining 50 percent interest in Sunrise (the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“BP Canada”) for net proceeds of $394 million, a variable payment with a maximum cumulative value of $600 million expiring in eight quarters subsequent to August 31, 2022, and our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador.

•We achieved first oil at our Spruce Lake North thermal plant in the third quarter of 2022.

•In Indonesia, we achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022.

•Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area.

In our downstream business:

•We announced an agreement to purchase the remaining 50 percent interest in the Toledo Refinery from BP (the “Toledo Acquisition”). The transaction is expected to close at the end of February 2023.

•We closed the sale of 337 gas stations within our retail fuels network for net cash proceeds of $404 million.

In addition, we sold our investment in Headwater Exploration Inc. for proceeds of $110 million.

Returns-focused Capital Allocation

The Company’s sustaining capital program and base dividend are sustainable at US$45 WTI per barrel and provide opportunities to sustainably grow shareholder returns. In 2022:

•We renewed our NCIB, which expired on November 8, 2022. Under our new NCIB (the “2023 NCIB”), we are authorized to purchase up to 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023.

•We purchased and cancelled 112 million common shares for $2.5 billion through our NCIBs in 2022.

•We returned $901 million to common shareholders through base dividends of $0.350 per common share and variable dividends of $0.114 per common share.

We declared dividends for the first quarter of 2023:

•On February 15, 2023, the Board declared a first quarter base dividend of $0.105 per common share payable on March 31, 2023, to common shareholders of record as at March 15, 2023.

•On February 15, 2023, the Board declared first quarter dividends for our preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of record as at March 15, 2023.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  7

OPERATING AND FINANCIAL RESULTS

Selected Operating Results — Upstream

		Percent Change		Percent Change
	2022		2021		2020
Upstream Production Volumes by Segment (1) (MBOE/d)
Oil Sands	588.7	1	583.6	53	381.7
Conventional	127.2	(5)	133.6	49	89.9
Offshore	70.3	(6)	74.4	N/A	—
Total Production Volumes	786.2	(1)	791.5	68	471.7
Upstream Production Volumes by Product
Bitumen (Mbbls/d)	570.3	2	561.3	47	381.7
Heavy Crude Oil (Mbbls/d)	16.3	(19)	20.2	648	2.7
Light Crude Oil (Mbbls/d)	19.1	(15)	22.5	400	4.5
NGLs (Mbbls/d)	36.2	(5)	38.3	96	19.5
Conventional Natural Gas (MMcf/d)	866.1	(3)	895.5	136	379.0
Total Production Volumes (MBOE/d)	786.2	(1)	791.5	68	471.7
Total Upstream Sales Volumes (2)(MBOE/d)	696.4	(1)	700.8	67	420.5
Netback (3)(4) ($/BOE)	53.21	44	37.04	267	10.09
Oil and Gas Reserves (MMBOE)
Total Proved	6,082	—	6,077	21	5,030
Probable	2,787	27	2,201	33	1,656
Total Proved Plus Probable	8,869	7	8,278	24	6,686

(1)Refer to the Oil Sands, Conventional or Offshore Operating Results section of this MD&A for a summary of production by product type.

(2)Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 520 MMcf per day for the year ended December 31, 2022 (517 MMcf per day for the year ended December 31, 2021).

(3)Upstream revenue as found in Note 1 of the Consolidated Financial Statements was $36.3 billion for the year ended December 31, 2022 ($25.4 billion for the year ended December 31, 2021).

(4)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

In 2022, total crude oil, NGLs and natural gas production was consistent with 2021. The factors below increased production in 2022 compared with 2021:

•New wells coming online at Foster Creek and Christina Lake in 2022 and the second half of 2021.

•The Sunrise Acquisition on August 31, 2022.

•First oil at the Spruce Lake North thermal plant in the third quarter of 2022.

•A planned turnaround and operational outages at Foster Creek in the second quarter of 2021.

•First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022.

The factors below decreased production in 2022 compared with 2021:

•The disposition of the Tucker asset on January 31, 2022.

•Planned maintenance and an unplanned outage at Foster Creek in the third quarter of 2022.

•Planned turnaround activity at Christina Lake in the second quarter of 2022.

•The disposition of the Wembley asset on February 28, 2022, and the East Clearwater and Kaybob divestitures in the second half of 2021.

•As part of the decision to restart the West White Rose project, we transferred a 12.5 percent working interest in the White Rose field and satellite extensions to our partner on May 31, 2022.

Oil and Gas Reserves

Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), total proved reserves and total proved plus probable reserves at December 31, 2022 were approximately 6.1 billion BOE and 8.9 billion BOE, respectively. Total proved reserves were consistent with 2021, and proved plus probable reserves increased seven percent compared with 2021.

Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  8

Selected Operating Results — Downstream

		Percent Change		Percent Change
	2022		2021		2020
Downstream Crude Oil Throughput (Mbbls/d)
Canadian Manufacturing	92.9	(13)	106.5	N/A	—
U.S. Manufacturing	400.8	—	401.5	116	185.9
Total Throughput	493.7	(3)	508.0	173	185.9
Fuel Sales (1)(millions of litres/d)	6.2	(10)	6.9	N/A	—

(1)On September 13, 2022, we closed the sale of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes cardlock, bulk plant and travel centre locations.

In the Canadian Manufacturing segment, throughput decreased 13.6 thousand barrels per day in 2022 compared with 2021. We completed planned turnarounds at both the Lloydminster Upgrader and Lloydminster Refinery in the second quarter of 2022. In addition, there were multiple temporary unplanned outages at the Upgrader in 2022. In 2021, the Upgrader and Lloydminster Refinery ran at or near capacity throughout the year.

In the U.S. Manufacturing segment, total throughput was consistent in 2022 compared with 2021:

•The Lima Refinery had unplanned operational issues in the first quarter of 2022 coming out of the 2021 fourth quarter turnaround. The refinery performed well during the remainder of the year, achieving crude utilization of 90 percent in 2022.

•At the Toledo Refinery, we completed a significant planned turnaround from April to early August 2022. The refinery remains shut down in a safe state following an incident on September 20, 2022.

•We completed two planned turnarounds at the Wood River Refinery in the second and fourth quarters of 2022. The second quarter turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. In early December, there was an incident at the Wood River Refinery that resulted in damage to one of the units and reduced throughput.

•We completed a turnaround at the Borger Refinery in the first and second quarter of 2022. In addition, the refinery had unplanned operational outages in the fourth quarter of 2022.

•We commenced commissioning for the restart of the Superior Refinery in December 2022.

Selected Consolidated Financial Results

Operating Margin

Operating Margin is a specified financial measure and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods.

($ millions)	2022	2021 (1)(2)	2020
Gross Sales	79,229	54,102	14,523
Less: Royalties	4,868	2,454	371
Revenues	74,361	51,648	14,152
Expenses
Purchased Product	39,334	27,170	5,959
Transportation and Blending	12,194	8,714	4,764
Operating Expenses	6,839	5,499	2,261
Realized (Gain) Loss on Risk Management Activities	1,731	892	247
Operating Margin	14,263	9,373	921

(1)    Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

(2)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no change to total Operating Margin.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  9

Operating Margin by Segment

Year Ended December 31, 2022

(1)Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuel business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.

Operating Margin increased in 2022, mainly due to higher average realized sales prices, resulting from higher benchmark pricing. In addition, realized refining margins almost doubled in our downstream business due to significantly higher market crack spreads from 2021.

These increases in Operating Margin were partially offset by:

•Increased blending costs due to higher condensate prices.

•Higher royalties and fuel costs in our upstream operations, both resulting from significantly higher commodity pricing.

•Increased realized risk management losses on the settlement of benchmark prices relative to our risk management contract prices in 2022. In the second quarter of 2022, all WTI risk management contracts related to our crude oil sales price risk management activities were closed.

•Planned turnarounds and unplanned outages in our downstream operations in 2022, which impacted sales volumes and operating expenses.

•In our realized margin, higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.

•Increased transportation costs due to increased tariffs combined with higher sales volumes at Foster Creek, Christina Lake and Sunrise.

•Higher operating expenses at the Superior Refinery. Costs increased compared with 2021 as we prepared for restart.

•Increased electricity and chemical costs in our upstream operations.

Cash From (Used in) Operating Activities and Adjusted Funds Flow

Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations.

($ millions)	2022	2021	2020
Cash From (Used in) Operating Activities	11,403	5,919	273
(Add) Deduct:
Settlement of Decommissioning Liabilities	(150)	(102)	(42)
Net Change in Non-Cash Working Capital	575	(1,227)	198
Adjusted Funds Flow	10,978	7,248	117

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  10

Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to:

•Increased Operating Margin, as discussed above.

•Lower finance costs which decreased $262 million in 2022 compared with 2021, primarily due to long-term debt purchases in 2021 and 2022.

•Decreased integration and transaction costs, a decline of $243 million in 2022 compared with 2021. The integration of Cenovus and Husky is substantially complete.

The increase was partially offset by higher cash taxes and higher quarterly contingent payments in 2022.

Cash from operating activities also increased as the net change in non-cash working capital increased by $1.8 billion compared to 2021. The increase was due to higher income tax payable and lower accounts receivable, offset by higher inventory at December 31, 2022 compared with December 31, 2021.

Net Earnings (Loss)

($ millions)	2022 vs. 2021	2021 vs. 2020
Net Earnings (Loss), Comparative Year	587	(2,379)
Increase (Decrease) due to:
Operating Margin	4,890	8,452
Corporate and Eliminations:
General and Administrative	(16)	(557)
Finance Costs	262	(546)
Integration and Transaction Costs	243	(320)
Unrealized Foreign Exchange Gain (Loss)	(677)	181
Revaluation Gains	549	—
Re-measurement of Contingent Payments	413	(655)
Gain (Loss) on Divestiture of Assets	40	148
Other Income (Loss), net	223	349
Other (1)	308	(194)
Unrealized Risk Management Gain (Loss)	57	36
Depreciation, Depletion and Amortization	1,207	(2,422)
Exploration Expense	(83)	73
Income Tax Recovery (Expense)	(1,553)	(1,579)
Net Earnings (Loss), Current Year	6,450	587

(1)Includes Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management; share of income (loss) from equity-accounted affiliates; interest income and realized foreign exchange (gains) losses.

Net earnings improved significantly compared with 2021 due to:

•Increased Operating Margin, as discussed above.

•Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of $1.6 billion in the fourth quarter of 2021.

•Revaluation gains of $549 million related to the Sunrise Acquisition in the third quarter of 2022.

•A loss on re-measurement of the contingent payments of $162 million compared with $575 million in 2021. The final payment related to the FCCL Partnership was made in July 2022. Re-measurements related to the Sunrise Acquisition began in the third quarter of 2022.

•Finance costs of $820 million compared with $1.1 billion in 2021, mainly due to a lower average long-term debt balance in 2022.

•Integration and transaction costs of $106 million, compared with $349 million in 2021.

•Higher other income primarily due to insurance proceeds related to the Superior Refinery.

•A realized foreign exchange gain of $22 million in 2022 compared to realized foreign exchange losses of $138 million in 2021. The gains in 2022 related to working capital were partially offset by losses on the purchase of debt.

The increase in net earnings in 2022 was partially offset by:

•Higher income tax expense.

•Unrealized foreign exchange losses as the Canadian dollar at December 31, 2022, weakened relative to the U.S. dollar.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  11

Net Debt

As at ($ millions)	December 31, 2022	December 31, 2021
Short-Term Borrowings	115	79
Current Portion of Long-Term Debt	—	—
Long-Term Debt	8,691	12,385
Total Debt	8,806	12,464
Less: Cash and Cash Equivalents	(4,524)	(2,873)
Net Debt	4,282	9,591

Long-term debt decreased by $3.7 billion and Net Debt decreased by $5.3 billion from December 31, 2021. In 2022, we purchased US$2.6 billion of principal related to notes due between 2023 and 2043, and paid a premium on redemption of US$41 million, collectively. In addition, we paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025 at par. The decrease in long-term debt was partially offset as the Canadian dollar weakened relative to the U.S. dollar on December 31, 2022, impacting our U.S. dollar debt.

Capital Investment (1)

($ millions)	2022	2021	2020
Upstream
Oil Sands	1,792	1,019	427
Conventional	344	222	78
Offshore	310	175	—
Total Upstream	2,446	1,416	505
Downstream
Canadian Manufacturing (2)	117	68	33
U.S. Manufacturing	1,059	995	243
Total Downstream	1,176	1,063	276
Corporate and Eliminations	86	84	60
Total Capital Investment	3,708	2,563	841

(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes cost incurred in our equity-accounted investment in Indonesia.

(2)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.

Oil Sands capital investment in 2022 was primarily focused on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal assets and Sunrise, and the drilling of stratigraphic test wells as part of our integrated winter program.

Conventional capital investment in 2022 focused on drilling, completion and tie-in activities, and infrastructure projects to support multi-year development.

Offshore capital investment in 2022 was primarily for the Terra Nova asset life extension (“ALE”) project and capital for the West White Rose project in the Atlantic region. On May 31, 2022, Cenovus and our partners announced the restart of the West White Rose project offshore Newfoundland and Labrador.

U.S. Manufacturing capital investment in 2022 focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery.

Drilling Activity

	Net Stratigraphic Test Wells and Observation Wells			Net Production Wells (1)
	2022	2021	2020	2022	2021	2020
Foster Creek (2)	68	32	38	29	6	—
Christina Lake (3)	—	25	117	31	18	—
Sunrise	15	—	—	10	2	—
Lloydminster Thermal	98	115	—	33	46	—
Lloydminster Conventional Heavy Oil	8	15	—	11	3	—
Tucker (4)	6	—	—	—	—	—
	195	187	155	114	75	—

(1)SAGD well pairs in the Oil Sands segment are counted as a single producing well.

(2)Includes Ipiatik.

(3)Includes Narrows Lake.

(4)The Tucker asset was sold on January 31, 2022.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  12

Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and to further progress the evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions.

	2022			2021			2020
(net wells)	Drilled	Completed	Tied-in	Drilled	Completed	Tied-in	Drilled	Completed	Tied-in
Conventional	31	35	36	27	19	18	6	1	3

In the Offshore segment, we drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields in Indonesia in 2022 (2021 — drilled one exploration well in China). We achieved first gas production at the MBH and MDA fields in the fourth quarter of 2022.

Future Capital Investment

Future Capital Investment is a specified financial measure. See the Specified Financial Measures Advisory of this MD&A. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com.

The following table shows guidance for 2023:

	Capital Investment ($ millions)	Production (MBOE/d)	Crude Throughput (Mbbls/d)
Upstream
Oil Sands	2,200 - 2,400	582 - 642
Conventional	350 - 450	125 - 140
Offshore	600 - 700	65 - 78
Downstream	800 - 900		610 - 660
Corporate and Eliminations	40 - 50

2023 guidance for total capital investment is between $4.0 billion and $4.5 billion. This includes sustaining capital of approximately $2.8 billion, and between $1.2 billion and $1.7 billion in optimization and growth capital.

Sustaining capital is mainly related to:

•Investment in the Oil Sands segment.

•Safety and reliability initiatives in the Canadian Manufacturing segment.

•The planned restart of the Superior Refinery.

•Offsetting natural declines and optimizing gas handling infrastructure in the Conventional segment.

Optimization and growth capital including downstream initiatives that will further mitigate the Company’s exposure to light-heavy differentials. Optimization and growth capital is mainly related to:

•Construction of the West White Rose project and the completion of the Terra Nova ALE project.

•Progressing the Narrows Lake tie-back to Christina Lake.

•Continued optimization of Foster Creek and the Lloydminster thermal projects.

•Application of Cenovus’s operating model at Sunrise.

•Margin expansion and debottlenecking opportunities in our downstream assets, which include feedstock replacement at the Lloydminster Refinery as part of the Company’s Rewire Alberta initiative.

•Increasing heavy crude oil conversion capacity and distillate output at the Wood River and Borger refineries.

Further information on the changes in our financial and operating results can be found in the Reportable Segments section of this MD&A. Information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  13

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Key performance drivers for our financial results include commodity prices, quality and location price differentials, refining crack spreads as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.

Selected Benchmark Prices and Exchange Rates (1)

(Average US$/bbl, unless otherwise indicated)	2022	Percent Change	2021	2020	Q4 2022	Q4 2021
Dated Brent	101.19	43	70.73	41.67	88.71	79.73
WTI	94.23	39	67.91	39.40	82.65	77.19
Differential Dated Brent-WTI	6.96	147	2.82	2.27	6.06	2.54
WCS at Hardisty	76.01	39	54.87	26.80	56.99	62.55
Differential WTI-WCS	18.22	40	13.04	12.60	25.66	14.64
WCS (C$/bbl)	98.51	43	68.73	35.59	77.42	78.71
WCS at Nederland	85.77	34	64.09	35.86	67.65	71.62
Differential WTI-WCS at Nederland	8.46	121	3.82	3.54	15.00	5.57
Condensate (C5 @ Edmonton)	93.78	38	68.20	37.16	83.40	79.13
Differential WTI-Condensate (Premium)/Discount	0.45	N/A	(0.29)	2.24	(0.75)	(1.94)
Differential WCS-Condensate (Premium)/Discount	(17.77)	(33)	(13.33)	(10.36)	(26.41)	(16.58)
Average (C$/bbl)	121.78	42	85.47	49.44	113.25	99.64
Synthetic @ Edmonton	98.66	49	66.28	36.25	86.79	75.40
Differential WTI-Synthetic (Premium)/Discount	(4.43)	N/A	1.63	3.15	(4.14)	1.79
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	120.63	42	85.07	45.24	102.80	91.84
Chicago Ultra-low Sulphur Diesel (“ULSD”)	143.85	67	86.37	50.08	140.95	96.53
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)	34.15	95	17.54	7.54	32.87	16.06
Group 3 3-2-1 Crack Spread (2)	33.21	86	17.82	8.67	29.99	15.82
Renewable Identification Numbers (“RINs”)	7.72	14	6.76	2.48	8.54	6.11
Natural Gas Prices
AECO (C$/Mcf)	5.56	56	3.56	2.24	5.58	4.94
NYMEX (US$/Mcf)	6.64	73	3.84	2.08	6.26	5.83
Foreign Exchange Rates
US$ per C$1 - Average	0.769	(4)	0.798	0.746	0.737	0.794
US$ per C$1 - End of Period	0.738	(6)	0.789	0.785	0.738	0.789
RMB per C$1 - Average	5.170	—	5.147	5.147	5.241	5.073

(1)These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management results, refer to the Netback tables in the Reportable Segments section of this MD&A.

(2)The average 3-2-1 crack spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.

Crude Oil and Condensate Benchmarks

In 2022, global crude oil prices improved significantly compared to 2021. Prices rose steadily through 2021 and during the first half of 2022 as global supply and demand balances remained tight, while inventories were low. Demand for crude oil and refined products continued to grow towards pre-pandemic levels despite macroeconomic challenges, weakness in Chinese consumption due to COVID-19 lockdowns, and geopolitical uncertainty around Russia’s invasion of Ukraine. Crude oil supply grew considerably in 2022 but struggled to match growing demand, with nearly all short-term supply sources accessed to meet demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”). Global spare production capacity remains low.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties.

The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI differential widened compared with 2021 due to higher shipping costs and supply disruptions as a result of Russia’s invasion of Ukraine.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  14

WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude and the cost of transport. In 2022, the average WTI-WCS differential at Hardisty widened compared to 2021, primarily due to a wider quality differential at the U.S. Gulf Coast (“USGC”) outlined below, as well as higher production activity in Western Canada.

WCS at Nederland is a heavy oil benchmark for sales of our product at the USGC. The WTI-WCS at Nederland differential is representative of the heavy oil quality discount and is influenced by global heavy oil refining capacity and global heavy oil supply. The WTI-WCS at Nederland differential widened significantly compared with 2021, particularly in the second half of 2022. It is mainly attributed to reduced demand due to planned and unplanned refinery maintenance, high global refining utilization, volatile refined product pricing and increased supply due to some incremental medium and heavy oil barrels into the market from OPEC+, and from the release of volume from SPRs in the U.S.

In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Lloydminster Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.

Synthetic crude at Edmonton strengthened significantly in 2022 compared with 2021 as a result of widespread upgrader maintenance in Western Canada and strong refinery demand for light crude oil. In 2022, the WTI-Synthetic differential was at a premium compared with a discount in 2021 as synthetic crudes continue to be supported by strong demand for refined products.

Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated as diluent volumes as a percentage of total blended volumes, range from approximately 22 percent to 35 percent. The WCS-Condensate differential is an important benchmark as a wider differential generally results in a decrease in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending as well as timing of sales of blended product.

The average Edmonton condensate benchmark remained near parity with WTI in 2022 as Alberta demand for condensate is strong and supply remains tight.

Refining Benchmarks

RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI- based crude oil feedstock prices and valued on a last in, first out basis.

The Chicago 3-2-1 market crack spread reflects the market for our Toledo, Lima and Wood River refineries. The Group 3 3-2-1 market crack spread reflects the market for the Borger Refinery.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  15

Average Chicago refined product prices increased significantly in 2022 compared with 2021. While gasoline prices strengthened year-over-year, the increase in market crack spreads were primarily driven by a substantial rise in distillate prices. The strength in market crack spreads and refined product prices has also been driven by refinery rationalization since the beginning of the pandemic, leading to high refinery utilization globally, combined with low global inventories of refined products. RINs costs remain high as a result of a tight biofuel market, rising feedstock prices and uncertainty around policies that drive RINs demand.

North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices. The strength of refining market crack spreads in the U.S. Midwest and Midcontinent generally reflects the differential between Brent and WTI benchmark prices.

Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock; refinery configuration and product output; where feedstocks are acquired and the time lag between the purchase and delivery of crude oil feedstock; and the cost of feedstock, which is valued on a first in, first out (“FIFO”) accounting basis. The market crack spreads do not precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator.

(1)There are no forward prices for RINs.

Natural Gas Benchmarks

Average NYMEX natural gas prices increased significantly in 2022, compared with 2021, due to a rebound in U.S. domestic demand and high liquified natural gas exports, coupled with a muted supply response and strong global pricing amid Russian supply concerns. Average AECO prices also increased significantly in 2022 compared with 2021 along with NYMEX prices, but the differentials between AECO and NYMEX widened slightly due to higher Western Canadian production as well as planned and unplanned pipeline maintenance limiting egress at points during 2022. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.

Foreign Exchange Benchmarks

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported revenue. In addition to our revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. In addition, changes in foreign exchange rates impact the translation of our U.S. and Asia Pacific operations.

In 2022, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2021, positively impacting our revenues year-over-year. The Canadian dollar weakened relative to the U.S. dollar as at December 31, 2022, compared with December 31, 2021, resulting in unrealized foreign exchange losses of $365 million on the translation of our U.S. dollar debt into Canadian dollars.

A portion of our long-term sales contracts in the Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. In 2022, the Canadian dollar on average was relatively flat compared with RMB, resulting in minimal impact on our revenues year-over-year.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  16

Interest Rate Benchmarks

Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. An increase in interest rates could increase our net interest expense and affect how certain liabilities are measured, and could negatively impact our cash flow and financial results.

As at December 31, 2022, the Bank of Canada’s Policy Interest Rate was 4.25 percent, an increase from 0.25 percent on December 31, 2021, due to concerns over inflation. On January 25, 2023, the rate increased a further 0.25 percent to 4.50 percent.

OUTLOOK

COMMODITY PRICE OUTLOOK

Crude oil prices improved significantly in 2022, but waned in the second half of the year due to demand concerns amid a weakening macroeconomic environment and COVID-19 lockdowns in China. The geopolitical premium associated with Russian supply uncertainty also faded in the back half of 2022 as Russian exports of crude oil and refined products remained resilient. Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers and government policy playing a large role in supply and demand dynamics. Policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shifting global trade patterns. OPEC+ policy will continue to be a key driver of crude oil prices and the recent announcement of a cut to the group’s production quotas is supportive of pricing.

Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions, the timing and ability of producers and governments to replace reduced supply, the refilling or release of SPRs and OPEC+ policy. In addition, potential incremental COVID-19 outbreaks and variants, weakening global economic activity, inflation and rising interest rates, and the potential for a recession remain a risk to the pace of demand growth.

In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:

•We expect that the WTI-WCS differential will remain largely tied to global supply factors and heavy crude oil processing capacity as long as supply stays within Canadian crude oil export capacity.

•We expect market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies could impact demand. Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America.

•We expect both NYMEX and AECO prices to remain strong but increasing supply and limited LNG export capacity from North America will put downward pressure on prices. Prices will continue to be impacted by weather.

•We expect the Canadian dollar to continue to be impacted by crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other and emerging macro-economic factors.

Most of our upstream crude oil and downstream refined products production are exposed to movements in the WTI crude oil price. Natural gas and NGLs production associated with our Conventional operations provide economic integration for the fuel, solvent and blending requirements at our Oil Sands operations.

Our refining capacity is focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to the market crack spreads in all of these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  17

Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our refining capacity, and to a lesser degree in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differentials, which could be subject to transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product differentials through the following:

•Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.

•Integration – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil as well as from spreads on refined products.

•Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil price differentials.

•Traditional crude oil storage tanks in various geographic locations.

All WTI contracts related to our crude oil sales price risk management activities closed by June 30, 2022. We continue to use financial instruments to mitigate our exposure to the prices of various commodities, including some WTI contracts for exposure management unrelated to crude oil sales price risk management; and contracts for management of price exposures associated with crude oil, crude oil differentials, condensate, natural gas liquids, refined products, refining margins, natural gas, electricity and renewable power contracts.

KEY PRIORITIES FOR 2023

At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy continues to focus on maximizing shareholder value through competitive cost structures and optimizing margins while delivering top-tier safety performance and sustainability leadership. We prioritize Free Funds Flow generation that enables debt reduction, shareholder returns through a combination of base dividend growth and flexible return mechanisms, reinvestment in the business and diversification of our portfolio.

Our 2023 priorities will focus on:

Top Tier Safety and Operational Performance

Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, including top-tier health and safety performance.

We will continue to target improved downstream operating performance, including the safe return of the Superior Refinery to full operations and, following the close of the Toledo Acquisition, integration of the Toledo Refinery with a focus on demonstrating consistent and reliable performance at our operated assets.

Sustainability Leadership

Sustainability has always been deeply engrained in Cenovus’s culture. We have established ambitious targets in our five ESG focus areas and continue to progress tangible plans to meet these targets. Our five ESG focus areas are:

•Climate & GHG Emissions.

•Water Stewardship.

•Biodiversity.

•Indigenous reconciliation.

•Inclusion & diversity.

Additional information on management’s efforts and performance across ESG focus areas, including our ESG targets and plans to achieve them, are available in Cenovus’s 2021 ESG report on our website at cenovus.com.

Cost Leadership

We aim to maximize shareholder value through competitive cost structures and optimized margins. While we strive to optimize our cost structure in all areas of our business, one of our focus areas will be to optimize infrastructure, reduce operating and capital costs, and reduce GHG emissions at our conventional assets.

Financial Discipline and Free Funds Flow Growth

We are focused on achieving and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles. We plan to continue to deliver meaningful returns to shareholders in alignment with our financial and shareholder returns framework.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  18

Returns-Focused Capital Allocation

We continue to take a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle and provide opportunities to sustainably grow shareholder returns.

We plan to materially progress the West White Rose project while remaining on track to deliver first oil in 2026.

REPORTABLE SEGMENTS

UPSTREAM

Oil Sands

In 2022, we:

•Delivered safe and reliable operations.

•Produced 586.6 thousand barrels of crude oil per day.

•Generated Operating Margin of $9.0 billion, an increase of $2.6 billion compared with 2021 primarily due to higher average realized sales prices.

•Sold our Tucker asset for net proceeds of $730 million on January 31, 2022. Crude oil production at the time of sale was approximately 20 thousand barrels per day.

•Purchased the remaining 50 percent interest in Sunrise from BP Canada on August 31, 2022, giving Cenovus full ownership and further enhancing our core strength in oil sands. The Sunrise Acquisition immediately added over 20 thousand barrels per day of crude oil production, and more than offset lost production from the sold Tucker asset.

•Achieved first oil at our Spruce Lake North thermal plant in September. Production averaged approximately 12.0 thousand barrels per day in the fourth quarter.

•Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area. This is expected to provide future bitumen feedstock to the Foster Creek plant. Pad construction is expected to begin in 2024 and we anticipate first steam in 2029.

•Invested capital of $1.8 billion primarily on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal assets and Sunrise.

•Achieved a Netback of $49.10 per BOE.

Financial Results

($ millions)	2022	2021 (1)	2020
Revenues
Gross Sales	34,775	22,827	8,804
Less: Royalties	4,493	2,196	331
	30,282	20,631	8,473
Expenses
Purchased Product	4,810	2,404	1,262
Transportation and Blending	12,036	8,625	4,683
Operating	2,930	2,451	1,156
Realized (Gain) Loss on Risk Management	1,527	786	268
Operating Margin	8,979	6,365	1,104
Unrealized (Gain) Loss on Risk Management	(68)	18	57
Depreciation, Depletion and Amortization	2,763	2,666	1,687
Exploration Expense	9	16	9
(Income) Loss from Equity-Accounted Affiliates	8	(5)	—
Segment Income (Loss)	6,267	3,670	(649)

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  19

Operating Margin Variance

Year Ended December 31, 2022

(1)Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases.

(2)Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.

Operating Results

	2022	2021	2020
Total Sales Volumes(MBOE/d)	585.8	579.9	386.6
Total Realized Price (1)($/BOE)	91.70	62.82	28.64
Crude Oil Production by Asset (Mbbls/d)
Foster Creek	191.0	179.9	163.2
Christina Lake	246.5	236.8	218.5
Sunrise (2)	31.3	25.9	—
Lloydminster Thermal	99.9	97.7	—
Lloydminster Conventional Heavy Oil	16.3	20.2	—
Tucker (3)	1.6	21.0	—
Total Crude Oil Production (4) (Mbbls/d)	586.6	581.5	381.7
Natural Gas (5) (MMcf/d)	12.3	12.6	—
Total Production (MBOE/d)	588.7	583.6	381.7
Effective Royalty Rate (percent)	25.2	18.7	11.6
Transportation and Blending Cost (1)($/BOE)	7.89	7.23	8.70
Operating Expense (1)($/BOE)	13.75	11.52	7.84
Per Unit DD&A (1) ($/BOE)	11.90	11.28	10.40

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

(2)Represents Cenovus’s 50 percent interest in Sunrise up to August 31, 2022. On August 31, 2022, we acquired the remaining 50 percent interest from BP Canada.

(3)The Tucker asset was sold on January 31, 2022.

(4)Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.

(5)Conventional natural gas product type.

Revenues

Price

Our heavy oil and bitumen production must be blended with condensate to reduce its viscosity to transport it to market through pipelines. Our realized bitumen sales price does not include the sale of condensate; however, it is influenced by the price of condensate. As the cost of condensate increases relative to the price of blended crude oil, our realized heavy oil and bitumen sales price decreases. Up to three months may lapse from when we purchase condensate to when we sell our blended production.

Our realized sales price averaged $91.70 per BOE in 2022 compared with $62.82 per BOE in 2021 due to higher WTI benchmark prices, partially offset by wider WTI-WCS differentials. To improve our realized sales price, we sold approximately 20 percent (2021 – 20 percent) of our crude oil volumes at U.S. destinations.

For the year ended December 31, 2022, gross sales included $4.5 billion (2021 – $2.1 billion), from third-party sourced volumes which are not included in our realized price or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  20

For the year ended December 31, 2022, gross sales included $358 million (2021 – $329 million), relating to construction, transportation and blending activities. These amounts are not included in our realized price or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.

Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including storage and pipeline assets, to optimize product mix, delivery points, and transportation commitments and customer diversification. In order to price protect our inventories associated with storage or transport decisions, Cenovus employs various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.

In 2022, we incurred realized risk management losses of $1.5 billion, of which $431 million related to the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized risk management gains of $68 million on our crude oil and condensate financial instruments.

Production Volumes

Oil Sands crude oil production increased slightly to 586.6 thousand barrels per day in 2022 compared with 581.5 thousand barrels per day in 2021.

We sold the Tucker asset on January 31, 2022, resulting in decreased production of 19.4 thousand barrels per day in 2022 compared with 2021.

Production at Foster Creek increased 11.1 thousand barrels per day to 191.0 thousand barrels per day in 2022 compared with 2021, due to new wells coming online in 2022 and the last half of 2021. In addition, we completed a planned turnaround in the second quarter of 2021. The increase was partially offset as production reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Also offsetting the increase was planned maintenance and an unplanned outage in the third quarter of 2022.

Production at Christina Lake increased 9.7 thousand barrels per day to 246.5 thousand barrels per day in 2022 compared with 2021. We added incremental production from redevelopment wells drilled in 2022 and the last half of 2021. The increase was offset by a planned turnaround in the second quarter of 2022.

The Sunrise Acquisition was completed on August 31, 2022 and added 5.4 thousand barrels per day of production in 2022 compared with 2021. The increase in production at Sunrise in 2022 was partially offset by base declines and wells taken offline in preparation for a redevelopment program.

Production from our Lloydminster thermal assets increased slightly in 2022 compared with 2021. The Spruce Lake North thermal plant achieved first oil in August, and production averaged approximately 12.0 thousand barrels per day in the fourth quarter. The increase was partially offset by base declines at other thermal plants and wells taken offline in preparation for a redevelopment program in the fourth quarter of 2022 and into 2023.

Lloydminster conventional heavy oil production decreased marginally in 2022 compared with 2021, as wells were shut-in to meet new emissions regulations in Alberta.

Royalties

Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Saskatchewan.

Our Alberta oil sands royalty projects (Foster Creek, Christina Lake and Sunrise) are based on government prescribed pre- and post-payout royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.

Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.

Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales revenues less diluent costs and transportation costs. Net revenues are calculated as sales revenues less diluent costs, transportation costs, and allowed operating and capital costs.

Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.

For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes each project's Crown and freehold split. For Crown royalties, the pre-payout calculation is based on a one percent rate and the post-payout calculation is based on a 20 percent rate. The freehold calculation is limited to post-payout projects and is based on an eight percent rate.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  21

Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates. For the year ended December 31, 2022, royalties were $4.5 billion (2021 – $2.2 billion).

Expenses

Transportation and Blending

In 2022, blending costs rose $3.2 billion to $10.3 billion compared with 2021. The increases were largely due to higher condensate prices.

Transportation costs increased $179 million to $1.7 billion in 2022 compared with 2021. The increases were primarily due to higher costs as discussed below combined with increased sales volumes at Foster Creek, Christina Lake and Sunrise.

Per-unit Transportation Expenses

Transportation costs were $7.89 per BOE in 2022 up slightly from $7.23 per BOE in 2021.

At Foster Creek, per-unit transportation costs increased 12 percent to $11.78 per barrel in 2022 compared with 2021. The increase was mainly due to increased tariffs, partially offset by reduced reliance on rail. For the year ended December 31, 2022, we shipped 40 percent (2021 – 35 percent), of our volumes from Foster Creek to U.S. destinations.

At Christina Lake, transportation costs were $6.51 per barrel in 2022, consistent with $6.19 per barrel in 2021.

At Sunrise, transportation costs were $12.26 per barrel in 2022, consistent with $12.14 per barrel in 2021, as we shipped a similar percentage of our total volumes to the U.S.

At our Other Oil Sands assets, transportation costs in 2022 were $3.49 per barrel, compared with $4.01 per barrel in 2021. In the first quarter of 2021, we stopped shipping volumes to U.S. destinations to optimize our pipeline capacity, reducing per-unit costs year-over-year.

Operating

Primary drivers of our operating expenses in 2022 were fuel, workforce, chemical, repairs and maintenance, and electricity costs. Total operating expenses increased largely due to higher fuel costs as a result of higher natural gas prices. AECO benchmark natural gas prices increased 56 percent in 2022 compared with 2021. In addition, total operating expenses increased due to higher electricity, repairs and maintenance and chemical costs. Chemical costs and electricity costs are also influenced by rising crude oil and natural gas benchmark prices. We have experienced minimal inflationary pressures on our costs, as we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.

Unit Operating Expenses (1)

($/BOE)	2022	Percent Change	2021	Percent Change	2020
Foster Creek
Fuel	6.07	49	4.07	44	2.83
Non-Fuel	6.52	(2)	6.67	4	6.41
Total	12.59	17	10.74	16	9.24
Christina Lake
Fuel	5.07	44	3.52	61	2.18
Non-Fuel	4.87	3	4.72	2	4.61
Total	9.94	21	8.24	21	6.79
Sunrise
Fuel	7.01	26	5.58	—	—
Non-Fuel	10.48	(9)	11.57	—	—
Total	17.49	2	17.15	—	—
Other Oil Sands (2)
Fuel	7.35	50	4.91	—	—
Non-Fuel	15.10	29	11.73	—	—
Total	22.45	35	16.64	—	—
Total	13.75	19	11.52	47	7.84

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

(2)Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  22

Per-unit fuel prices increased largely due to higher natural gas prices as discussed above.

Foster Creek per-unit non-fuel costs were consistent with 2021. Higher chemical, electricity and repairs and maintenance costs were offset by higher sales volumes.

Christina Lake per unit non-fuel costs were consistent with 2021. Higher electricity and repairs and maintenance costs were offset by higher sales volumes in 2022.

Sunrise per unit non-fuel costs decreased in 2022 compared with 2021. The decrease in non-fuel costs were primarily related to the planned turnaround costs in the second quarter of 2021, partially offset by higher electricity, chemical and workover costs in 2022.

Per-unit non-fuel costs at our Other Oil Sands assets increased in 2022 compared with 2021, primarily due to higher chemical and workover costs.

Netbacks

($/BOE)	2022	2021	2020
Sales Price (1)	91.70	62.82	28.64
Royalties (1)	20.96	10.38	2.34
Transportation (1)	7.89	7.23	8.70
Operating Expenses (1)	13.75	11.52	7.84
Netback (2)	49.10	33.69	9.76

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

(2)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

DD&A

In the year ended December 31, 2022, DD&A remained relatively consistent at $2.8 billion, compared with $2.7 billion in 2021. The average depletion rate for the year ended December 31, 2022, was $11.90 per BOE, compared with $11.28 per BOE in 2021.

Conventional

In 2022, we:

•Delivered safe and reliable operations.

•Sold our assets in the Wembley area for net proceeds of $221 million on February 28, 2022.

•Generated Operating Margin of $1.2 billion, an increase of $432 million compared with 2021, largely due to higher average realized sales prices.

•Invested capital of $344 million focused on drilling, completion and tie-in activities, and infrastructure projects to support multi-year development.

•Achieved a Netback of $27.43 per BOE.

Financial Results

($ millions)	2022	2021	2020
Revenues
Gross Sales	4,332	3,235	904
Less: Royalties	298	150	40
	4,034	3,085	864
Expenses
Purchased Product	2,023	1,655	268
Transportation and Blending	143	74	81
Operating	541	551	320
Realized (Gain) Loss on Risk Management	92	2	—
Operating Margin	1,235	803	195
Unrealized (Gain) Loss on Risk Management	13	1	—
Depreciation, Depletion and Amortization	370	3	880
Exploration Expense	1	(3)	82
Segment Income (Loss)	851	802	(767)

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  23

Operating Margin Variance

Year Ended December 31, 2022

(1)Reflects Operating Margin from processing facilities.

Operating Results

	2022	2021	2020
Total Sales Volumes(MBOE/d)	127.2	133.4	89.8
Total Realized Price (1) ($/BOE)	48.15	31.20	17.84
Heavy Crude Oil ($/bbl)	—	—	31.45
Light Crude Oil ($/bbl)	118.64	76.32	42.78
NGLs($/bbl)	63.22	42.93	22.04
Conventional Natural Gas($/Mcf)	6.50	4.07	2.37
Production by Product
Heavy Crude Oil (Mbbls/d)	—	—	2.7
Light Crude Oil (Mbbls/d)	7.5	8.4	4.5
NGLs(Mbbls/d)	23.8	25.6	19.5
Conventional Natural Gas (MMcf/d)	576.1	597.6	379.0
Total Production(MBOE/d)	127.2	133.6	89.9
Conventional Natural Gas Production (percentage of total)	75	75	70
Crude Oil and NGLs Production (percentage of total)	25	25	30
Effective Royalty Rate (percent)	15.4	10.3	7.9
Transportation Costs (1) ($/BOE)	3.16	1.53	2.46
Operating Expense (1)($/BOE)	11.18	10.66	8.99
Per Unit DD&A (1) ($/BOE)	8.23	9.11	9.85

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

Revenues

Price

Our total realized sales price increased in 2022, due to higher crude oil and natural gas benchmark prices.

For the year ended December 31, 2022, gross sales included $2.0 billion (2021 – $1.7 billion), relating to third-party sourced volumes, which are not included in our realized prices or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.

For the year ended December 31, 2022, revenues included amounts relating to processing and transportation activities undertaken for third-parties of $71 million (2021 – $61 million), which are not included in our realized prices or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.

Production Volumes

Production volumes decreased 6.4 thousand BOE per day in 2022 compared with 2021, mainly due to asset sales in the first quarter of 2022 and the second half of 2021, and natural declines. The production decrease is partially offset by 36 net new wells (2021 – 18 net new wells) brought on production during the year, combined with production from well reactivations and workover activity.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  24

Royalties

The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Total royalties and effective royalty rates increased in 2022 compared with 2021, primarily due to higher realized pricing.

Expenses

Transportation

Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. Transportation costs increased $69 million in 2022, compared with 2021. Per-unit transportation costs averaged $3.16 per BOE in 2022, compared with $1.53 per BOE in 2021.

Operating

Primary drivers of our operating expenses in 2022, were repairs and maintenance, workforce, electricity, property taxes and lease costs. Operating expenses per BOE in the year ended December 31, 2022, increased compared with 2021 primarily due to higher workover, energy and electricity costs, combined with lower sales volumes. Total operating expenses in 2022 were flat compared with 2021, due to the same factors that increased operating expenses per BOE, partially offset by asset sales in the first quarter of 2022 and the second half of 2021.

Netbacks

($/BOE)	2022	2021	2020
Sales Price (1)	48.15	31.20	17.84
Royalties (1)	6.38	3.06	1.23
Transportation and Blending (1)	3.16	1.53	2.46
Operating Expenses (1)	11.18	10.66	8.99
Netback (2)	27.43	15.95	5.16

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

(2)Contains a Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

DD&A

For the year ended December 31, 2022, total Conventional DD&A was $370 million (2021 – $3 million). The increase was due to impairment reversals of $378 million in 2021.

The average depletion rate for 2022 was $8.23 per BOE (2021 – $9.11 per BOE). The average depletion rate excludes the impact of impairments and impairment reversals.

Offshore

In 2022, we:

•Delivered safe and reliable operations.

•Completed the dry-dock portion of the Terra Nova ALE project. We expect the Terra Nova field to resume production in the second quarter of 2023.

•Announced our decision to proceed with the completion of the West White Rose project.

•Sold our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador as part of our consideration in the Sunrise Acquisition.

•Generated Operating Margin of $1.6 billion, an increase of $190 million compared with 2021, largely due to higher average realized sales prices, partially offset by increased operating expenses and lower sales volumes.

•Earned a Netback of $68.90 per BOE.

•Invested capital of $310 million mainly for the Terra Nova ALE and the West White Rose projects in the Atlantic region.

In September 2021, Cenovus announced an agreement with its partners to restructure its working interest in the Atlantic region and proceed with the ALE project for Terra Nova. The agreement increased Cenovus’s working interest in Terra Nova to 34 percent from 13 percent and, pending a decision to restart the West White Rose Project, would decrease Cenovus’s working interest in the White Rose field and satellite extensions by 12.5 percent.

On May 31, 2022, Cenovus and its partners announced the restart of the West White Rose project resulting in the reduction of our working interest in the White Rose field and satellite extensions. The West White Rose project is anticipated to have peak production of 80 thousand barrels per day (45 thousand barrels per day, net to Cenovus) with first oil expected in the first half of 2026. Total capital required to achieve first oil is expected to be approximately $2.0 billion to $2.3 billion net to Cenovus. At December 31, 2022, the project was around 65 percent complete. Since our decision to restart the project, we have invested approximately $85 million in 2022.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  25

At our equity-accounted assets in Indonesia, we drilled and completed two MBH field development wells and five MDA field development wells planned for the year. We achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022. In Indonesia we also have the MAC and MDK fields under development. At the MAC field, we drilled and completed two development wells in the fourth quarter of 2022, of the three planned at the field. We expect first gas production from the MAC and MDK fields by 2023 and 2025, respectively.

In China, we finalized an agreement in the second quarter that increases gas sales at Liuhua 29-1 for the duration of the contract. This partially offsets some of the reduction in contracted natural gas sales from Liwan 3-1, due to the conclusion of an amendment that temporarily increased sales volumes. In addition, in the first quarter we terminated the production sharing contract (“PSC”) at Block 23/07, which was in the exploration phase, and never produced or had drilling activity.

Financial Results

	2022			2021
($ millions)	Asia Pacific	Atlantic	Offshore	Asia Pacific	Atlantic	Offshore
Revenues
Gross Sales	1,442	578	2,020	1,342	440	1,782
Less: Royalties	80	(3)	77	79	29	108
	1,362	581	1,943	1,263	411	1,674
Expenses
Transportation and Blending	—	15	15	—	15	15
Operating	114	204	318	103	136	239
Operating Margin (1)	1,248	362	1,610	1,160	260	1,420
Depreciation, Depletion and Amortization			585			492
Exploration Expense			91			5
(Income) Loss from Equity-Accounted Affiliates			(23)			(47)
Segment Income (Loss)			957			970

(1)Asia Pacific and Atlantic Operating Margin are Non-GAAP financial measures. See the Specified Financial Measures Advisory of this MD&A.

Operating Margin Variance

Year Ended December 31, 2022

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  26

Operating Results

	2022	2021
Total Sales Volumes (MBOE/d)	70.0	73.5
Atlantic	11.3	13.2
Asia Pacific (1)	58.7	60.3
Total Realized Price (2)($/BOE)	89.72	74.75
Atlantic - Light Crude Oil ($/bbl)	140.65	91.01
Asia Pacific (1) ($/BOE)	79.96	71.19
NGLs ($/bbl)	110.05	79.83
Conventional Natural Gas ($/Mcf)	11.98	11.48
Production by Product
Atlantic - Light Crude Oil (Mbbls/d)	11.6	14.1
Asia Pacific (1)
NGLs(Mbbls/d)	12.4	12.7
Conventional Natural Gas (MMcf/d)	277.7	285.3
Asia Pacific Total(MBOE/d)	58.7	60.3
Total Production(MBOE/d)	70.3	74.4
Effective Royalty Rate (percent)
Atlantic	(0.5)	6.7
Asia Pacific (1)	11.5	8.4
Operating Expense (2)($/BOE)	12.64	9.86
Atlantic	42.03	28.34
Asia Pacific (1)	7.00	5.80
Per Unit DD&A (2) ($/BOE)	30.76	25.62

(1)Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.

(2)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

Revenues

Price

The price we receive for natural gas sold in Asia is set under long-term contracts. Our realized sales price on light crude oil and NGLs increased in 2022 compared with 2021, primarily due to higher Brent benchmark pricing.

Production Volumes

Asia Pacific production decreased slightly in 2022 compared with 2021, due to changes to contracts at Liwan 3-1 and Liuhua 29-1 resulting in a net decrease in production. The decrease was partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022.

Atlantic production decreased slightly in 2022 compared with 2021, due to the decrease in Cenovus’s working interest at the White Rose field and satellite extensions in the second quarter of 2022. Light crude oil from production at the White Rose fields is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales.

Royalties

Royalty rates in China and Indonesia are governed by production sharing contracts in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for 2022 was 11.5 percent (2021 – 8.4 percent). The increase in the effective royalty rates in 2022 are due to the full recovery of development costs at the Madura-BD gas project in the third quarter of 2021.

Royalties at the White Rose fields are based on an amended agreement between our working interest partners and the Government of Newfoundland and Labrador. For 2022, retroactive to January 1, 2022, we paid a basic royalty of 1.0 percent of gross sales from the White Rose fields and 1.0 percent of gross sales from the satellite extensions. As a result, royalties were negative $3 million in 2022 (2021 – $29 million).

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  27

Expenses

Operating

Primary drivers of our Asia Pacific operating expenses in 2022 were repairs and maintenance, insurance and workforce. Total and per-unit operating expenses increased marginally year-over-year, primarily due to planned maintenance in China in the second and third quarter, combined with lower production in China. Also contributing to the increase in per-unit operating expenses were costs related to the MBH and MDA fields coming online in the fourth quarter of 2022.

Primary drivers of our Atlantic operating expenses in 2022 were vessel and helicopter costs, repairs and maintenance, and workforce. Total operating expenses increased mainly due to continued preparations for the Terra Nova FPSO’s return to field and a higher working interest in the Terra Nova field. The increase was partially offset by the working interest restructuring on the White Rose fields in the second quarter of 2022. Per-unit operating expenses increased due to lower sales volumes, combined with increased costs at Terra Nova discussed above.

Transportation

Transportation in the Atlantic region remained consistent year-over-year and include the cost of transporting crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs.

Netbacks

	2022
($/BOE, except where indicated)	China	Indonesia (1)		Atlantic ($/bbl)		Total Offshore
Sales Price (2)	81.99		70.66		140.65		89.72
Royalties (2)	4.57		30.19		(0.74)		7.57
Transportation and Blending (2)	—		—		3.79		0.61
Operating Expenses (2)	5.62		13.32		42.03		12.64
Netback (3)	71.80		27.15		95.57		68.90

	2021
($/BOE, except where indicated)	China	Indonesia (1)		Atlantic ($/bbl)		Total Offshore
Sales Price (2)	72.44		64.52		91.01		74.75
Royalties (2)	4.25		14.93		6.07		5.96
Transportation and Blending (2)	—		—		3.02		0.54
Operating Expenses (2)	5.10		9.55		28.34		9.86
Netback (3)	63.09		40.04		53.58		58.39

(1)    Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.

(2)    Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

(3)     Contains a Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

DD&A

In 2022, total Offshore DD&A was $585 million (2021 – $492 million). The average depletion rate in 2022 was $30.76 per BOE, (2021 – $25.62 per BOE).

Exploration Expense

In 2022, we recorded exploration expense of $91 million, primarily due to a $58 million write-off related to our decision not to pursue development at Block 15/33 in China, penalties related to terminating the PSC at Block 23/07 in China and spending at Bay du Nord in the Atlantic region prior to its divestiture.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  28

DOWNSTREAM

Canadian Manufacturing

In 2022, we:

•Delivered safe operations.

•Completed planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter.

•Averaged combined crude utilization of 84 percent at the Upgrader and Lloydminster Refinery. There were several unplanned outages, primarily at the Upgrader in 2022.

•Generated Operating Margin of $699 million, an increase of $126 million compared with 2021, primarily due to a higher upgrading differential, and higher distillate and asphalt pricing, partially offset by the impact of turnaround activities and unplanned outages on sales volumes and operating expenses.

•We closed the sales of 337 gas stations within our retail fuels network for net cash proceeds of $404 million.

Following the sale of the retail business, we retained our commercial fuels business, which at December 31, 2022, includes 170 cardlock, bulk plant and travel center locations. The commercial fuels business and historical retail fuels business are aggregated into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada.

Financial Results

($ millions)	2022	2021 (1)	2020
Revenues	7,792	6,215	82
Purchased Product	6,389	5,156	—
Gross Margin (2)	1,403	1,059	82
Expenses
Operating	704	486	37
Operating Margin	699	573	45
Depreciation, Depletion and Amortization	208	226	8
Segment Income (Loss)	491	347	37

(1)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.

(2)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  29

Select Operating Results

	2022	2021	2020
Heavy Crude Oil Throughput Capacity (Mbbls/d)	110.5	110.5	—
Lloydminster Upgrader	81.5	81.5	—
Lloydminster Refinery	29.0	29.0	—
Heavy Crude Oil Throughput (Mbbls/d)	92.9	106.5	—
Lloydminster Upgrader	68.7	79.0	—
Lloydminster Refinery	24.2	27.5	—
Crude Utilization (1)(percent)	84	96	—
Refined Products Output(Mbbls/d)	93.4	107.9	—
Upgrading Differential (2)	32.84	16.83	—
Refining Margin (3)(4)($/bbl)	33.92	18.09	—
Lloydminster Upgrader (4)	36.04	18.96	—
Lloydminster Refinery (4)	27.91	15.60	—
Unit Operating Expense (5)($/bbl)	13.91	7.55	—
Ethanol Production (millions of litres/d)	0.8	0.7	—
Rail
Volumes Loaded (6) (Mbbls/d)	1.8	12.1	30.4
Fuel Sales (7)
Fuel Sales (millions of litres/d)	6.2	6.9	—
Fuel Sales per Outlet (thousands of litres/d)	15.0	13.0	—

(1)Based on crude oil throughput volumes and results of operations at the Upgrader and Lloydminster Refinery.

(2)Based on benchmark price differential between heavy oil feedstock and synthetic crude.

(3)Contains a Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader for the year ended December 31, 2022, were $3.8 billion (2021 – $3.2 billion). Revenues from the Lloydminster Refinery for the year ended December 31, 2022, were $1.1 billion (2021 – $816 million).

(4)Comparative information has been re-presented to include marketing activities.

(5)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A. Comparative information has been re-presented to include only operating expenses and throughput at the Upgrader and Lloydminster Refinery.

(6)Volumes transported outside of Alberta, Canada.

(7)On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes approximately 170 cardlock, bulk plant and travel centre locations. Total fuel sales volumes include the historical retail business and the remaining commercial fuels business. For the period of September 14, 2022 to December 31, 2022, the commercial fuels business averaged 0.7 million litres per day of gasoline sales volumes and 4.6 million litres per day of diesel fuel sales volumes, for a total of 5.3 million litres per day of sales volumes.

In 2022, crude oil throughput decreased 13.6 thousand barrels per day compared with 2021 due to planned turnarounds at the Lloydminster Upgrader and Lloydminster Refinery completed in the second quarter. Cold weather impacts and operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of January 2023. In addition, there were temporary unplanned outages at the Upgrader in the first and third quarters of 2022.

Revenues and Gross Margin

The Lloydminster Upgrader processes blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur distillates. Revenues are dependent on the sales price of synthetic crude oil and diesel. Upgrading gross margin is primarily dependent on the differential between the sales price of synthetic crude oil and diesel, and the cost of heavy crude oil feedstock.

The Lloydminster Refinery processes blended heavy crude oil into asphalt and industrial products. Revenues are dependent on market prices for asphalt and other industrial products. The gross margin is largely dependent on asphalt and industrial products pricing and the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery increase during paving season, which typically runs from May through October each year.

The Lloydminster Upgrader sources crude oil feedstock primarily from our Lloydminster thermal production. The Lloydminster Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil production.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  30

In 2022, revenues increased by $1.6 billion to $7.8 billion, mainly due to higher synthetic crude oil benchmark prices and higher asphalt and industrial products prices. In addition, revenues from our commercial fuels business and historical retail network increased due to significantly higher benchmark gasoline and diesel prices. The increase in total revenues year-over-year was partially offset by lower sales volumes.

Gross margin increased $344 million in 2022 compared with 2021, due to a higher upgrading differential and higher margins on asphalt and industrial products. The year-over-year increase was offset by lower sales volumes, the 2021 settlement of a take-or-pay contract of $55 million and reduced activity at the Bruderheim crude-by-rail terminal.

See the Specified Financial Measures Advisory of this MD&A for revenues and gross margin by asset.

Operating Expenses

Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce and energy costs. Total operating costs increased in 2022 compared with 2021, primarily due to planned turnarounds and operational outages, combined with higher energy costs, maintenance, workforce and chemical costs.

Per-unit operating expenses increased primarily due to the same factors discussed above, combined with lower crude oil throughput volumes. Per-unit operating costs apply only to operating costs and throughput at the Upgrader and Lloydminster Refinery.

DD&A

In 2022, Canadian Manufacturing DD&A was $208 million, compared with $226 million in 2021.

U.S. Manufacturing

In 2022, we:

•Delivered safe operations at our operated assets.

•Generated Operating Margin of $1.7 billion, an increase of $1.5 billion compared with 2021, largely due to significantly higher market crack spreads.

•Achieved crude utilization of 90 percent at the Lima Refinery.

•Completed a significant planned turnaround at the non-operated Toledo Refinery, from April and through to early August. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state.

•Completed planned turnarounds at the non-operated Wood River and Borger refineries in the first and second quarters, and an additional planned turnaround at the Wood River Refinery in September and October.

•Commenced commissioning activities for the Superior Refinery restart in December 2022 and will progress into the first quarter of 2023. The refinery remains on schedule to ramp up to full operations in the second quarter of 2023.

•Averaged crude utilization of 80 percent and crude oil throughput of 400.8 thousand barrels per day across all U.S. Manufacturing assets.

•Invested capital of $1.1 billion focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery.

On August 8, 2022, we announced an agreement with BP to acquire their 50 percent interest in the Toledo Refinery in Ohio. The Toledo Acquisition will provide us full ownership and operatorship and further integrate our heavy oil production and refining capabilities. The transaction is expected to give us an additional 80.0 thousand barrels per day of downstream throughput capacity, including 45.0 thousand barrels per day of heavy oil refining capacity, with opportunities to further optimize our heavy oil value chain through integration with our upstream assets. The transaction is expected to close at the end of February 2023.

Financial Results

($ millions)	2022	2021	2020
Revenues	30,310	20,043	4,733
Purchased Product	26,112	17,955	4,429
Gross Margin (1)	4,198	2,088	304
Expenses
Operating	2,346	1,772	748
Realized (Gain) Loss on Risk Management	112	104	(21)
Operating Margin	1,740	212	(423)
Unrealized (Gain) Loss on Risk Management	18	1	(1)
Depreciation, Depletion and Amortization	640	2,381	728
Segment Income (Loss)	1,082	(2,170)	(1,150)

(1)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  31

Select Operating Results

	2022	2021	2020
Crude Oil Throughput Capacity (Mbbls/d)	552.5	502.5	247.5
Lima Refinery	175.0	175.0	—
Superior Refinery (1)	50.0	—	—
Toledo Refinery (2)	80.0	80.0	—
Wood River and Borger Refineries (2)	247.5	247.5	247.5
Crude Oil Throughput (Mbbls/d)	400.8	401.5	185.9
Lima Refinery	157.9	126.9	—
Superior Refinery (1)	—	—	—
Toledo Refinery (2)	36.3	69.9	—
Wood River and Borger Refineries (2)	206.6	204.7	185.9
Throughput by Product (Mbbls/d)
Heavy Crude Oil	116.1	138.7	74.6
Light and Medium Crude Oil	284.7	262.8	111.3
Crude Utilization(percent)	80	80	75
Refining Margin (3)(4)($/bbl)	28.70	14.25	4.47
Unit Operating Expense (4)(5)($/bbl)	16.04	12.09	11.00

(1)    The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d and is not included in the crude utilization calculation.

(2)    Represents Cenovus’s 50 percent interest in the non-operated Wood River, Borger and Toledo refinery operations.

(3)    Contains a Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

(4)    Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries.

(5)    Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

In 2022, total crude utilization across the segment was 80 percent (2021 – 80 percent):

•The Lima Refinery had unplanned operational issues in the first quarter of the year following the turnaround completed in late 2021. The refinery performed well in the remainder of the year, until the winter storm Elliott events in December. Lima returned to normal rates in early January 2023. Crude utilization in 2022 was 90 percent (2021 – 73 percent).

•At the Toledo Refinery, we completed a significant planned turnaround starting in April and ramped up to full rates by mid-August 2022. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state. Crude utilization in 2022 was 45 percent (2021 – 87 percent).

•We completed two planned turnarounds at the Wood River Refinery in 2022. The spring turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. The second turnaround was completed in September and October. In December 2022, an incident occurred at the Wood River Refinery that reduced throughput. Crude utilization has steadily increased since the first week of January 2023, and the refinery is currently operating at a substantial proportion of normal throughput. The refinery is expected to return to normal rates in the second quarter of 2023.

•We completed a turnaround at the Borger Refinery in the first and second quarters of 2022. In addition, the refinery had unplanned operational outages in the fourth quarter of 2022. The refinery returned to full rates by January 2023.

•Combined crude utilization for the Wood River and Borger refineries was 83 percent (2021 – 83 percent).

Early in the year, we operated at reduced rates at the Toledo, Lima and Wood River refineries due to low market crack spreads. In December, throughput at all the U.S. Manufacturing sites was significantly impacted by extreme cold weather. Wood River and Borger were also impacted by outages on a third party pipeline that brings feedstock to the refineries. Cold weather also impacted Toledo delaying the start up of certain operational areas that could be restarted.

The Superior Refinery commenced commissioning in December and will progress into the first quarter of 2023. The refinery is expected to ramp up to full operations in the second quarter of 2023.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  32

Revenues and Gross Margin

Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as a general market indicator. While market crack spreads are an indicator of margin from processing crude oil into refined products, the refining realized crack spread, which is the gross margin on a per-barrel basis, is affected by many factors. These factors include the type of crude oil feedstock processed, refinery configuration and the proportion of gasoline, distillate and secondary product output, the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the refineries, and the cost of feedstock. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued on a FIFO accounting basis.

Revenues increased $10.3 billion to $30.3 billion in 2022 compared with 2021. The increase was primarily due to significantly higher refined product pricing.

Gross margin increased $2.1 billion to $4.2 billion in 2022 compared with 2021, largely due to significantly improved market crack spreads. In 2022, RINs costs were $1.1 billion (2021 – $880 million). RINs prices averaged US$7.72 per barrel in 2022, compared with US$6.76 in 2021.

In 2022, we incurred realized risk management losses of $112 million (2021 – $104 million), which included a $36 million loss on the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized losses of $18 million (2021 – $1 million) on our crude oil and refined products financial instruments.

Operating Expenses

Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce, and energy costs.

Operating expenses increased $574 million in 2022, compared with 2021. The increase was mainly due to costs related to:

•Planned turnarounds at the Toledo, Wood River and Borger refineries.

•Increased maintenance and preparation work at the Superior Refinery as we prepare for restart.

•Higher energy and utility pricing.

•Higher workforce and chemical costs.

In 2022, per-unit operating expenses increased $3.95 per barrel of crude oil throughput in 2022, compared with 2021. The increase was primarily due to the same factors as discussed above. Superior Refinery operating expenses are included in per-unit operating expenses.

DD&A

U.S. Manufacturing DD&A was $640 million in 2022, compared with $2.4 billion in 2021. DD&A decreased compared with 2021 due to impairment charges of $1.9 billion recorded in the fourth quarter of 2021 related to the Lima, Wood River and Borger cash generating units (“CGUs”). In the fourth quarter of 2022, we recorded net impairment charges of $266 million. Refer to Note 11 of the Consolidated Financial Statements for further details.

CORPORATE AND ELIMINATIONS

In 2022, our corporate risk management activities resulted in:

•Unrealized risk management gains of $89 million (2021 – $18 million). Unrealized risk management gains in 2022 relate to renewable power contracts and foreign exchange risk management contracts.

•Realized risk management losses of $31 million related to foreign exchange risk management contracts. Losses of $101 million in 2021 were mainly due to the realization of WTI put and call option contracts acquired as part of the Arrangement.

Expenses

($ millions)	2022	2021	2020
General and Administrative	865	849	292
Finance Costs	820	1,082	536
Interest Income	(81)	(23)	(9)
Integration and Transaction Costs	106	349	29
Foreign Exchange (Gain) Loss, Net	343	(174)	(181)
Revaluation (Gains)	(549)	—	—
Re-measurement of Contingent Payments	162	575	(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)	(81)
Other (Income) Loss, Net	(532)	(309)	40
	865	2,120	546

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  33

General and Administrative

Primary drivers of our general and administrative expenses were employee long-term incentive costs, workforce costs and information technology costs. General and administrative expenses, excluding stock-based compensation expense, declined $198 million year-over-year, primarily due to the provision for incentive rewards related to reaching our synergy targets in 2021. Stock-based compensation expense increased significantly by $214 million due to changes in our share price in 2022. Our closing common share price on December 31, 2022, was $26.27, an increase from $15.51 on December 31, 2021.

Finance Costs

Finance costs decreased by $262 million in 2022 compared with 2021 primarily as a result of debt purchases that lowered the Company’s average long-term debt in 2022 compared with 2021. In addition, we recorded a net discount on the redemption of long-term debt of $29 million in 2022. Comparatively, we recorded a $121 million net premium on the redemption of long-term debt in 2021. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.

The weighted average interest rate of outstanding debt for the year ended December 31, 2022, was 4.7 percent (2021 – 4.6 percent).

Integration and Transaction Costs

We incurred $90 million of integration costs as a result of the Arrangement, not including capital expenditures, in 2022, compared with $349 million in 2021. The integration of Cenovus and Husky is substantially complete.

In 2022, we incurred $95 million of Total Arrangement Integration Costs(1), which include capital expenditures (2021 – $402 million).

Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022 associated with the Sunrise Acquisition and the pending Toledo Acquisition.

Foreign Exchange

($ millions)	2022	2021	2020
Unrealized Foreign Exchange (Gain) Loss	365	(312)	(131)
Realized Foreign Exchange (Gain) Loss	(22)	138	(50)
	343	(174)	(181)

In 2022, unrealized foreign exchange losses of $365 million were mainly as a result of the translation of our U.S. dollar denominated debt. Realized foreign exchange gains of $22 million were recorded in 2022, related to net gains on working capital, offset by losses on the purchase of long-term debt.

Revaluation Gains

Cenovus recognized revaluation gains of $549 million in the third quarter of 2022 as part of the Sunrise Acquisition. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is remeasured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). Refer to Note 5 of the Consolidated Financial Statements for further details.

(1)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  34

Re-measurement of Contingent Payments

The contingent payment associated with the acquisition of a 50 percent interest in the FCCL Partnership from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022, and the final payment was made in July 2022. In 2022, we paid $631 million under this agreement, which was recognized as cash flow from operating activities and reduced Adjusted Funds Flow.

In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments to BP Canada for up to eight quarters subsequent to August 31, 2022, if the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment is $600 million. For accounting purposes, the variable payment will be re-measured at fair value at each reporting date until the earlier of the cumulative maximum $600 million is reached or the eight quarters have lapsed, with changes in fair value recognized in net earnings (loss). The variable payment was recorded at a fair value of $600 million on the date of acquisition using an option pricing model.

As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million resulting in a non-cash re-measurement gain of $89 million. The first quarterly period ended on November 30, 2022. As at December 31, 2022, $92 million is payable under this agreement.

As of December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is approximately $72.79 per barrel.

(Gain) Loss on Divestiture of Assets

In 2022, we recognized a gain on divestiture of assets of $269 million (2021 – $229 million), due to the closing of the sales of our Tucker and Wembley assets in the first quarter, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions in the second quarter, and the divestiture of 337 gas stations within our retail fuels network in the third quarter.

Other (Income) Loss, Net

In 2022, other income increased by $223 million compared with 2021, primarily due to insurance proceeds related to 2018 incidents at the Superior Refinery and in the Atlantic region and funding received under the Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites. The increase was partially offset by the settlement of a legal claim in favour of Cenovus in the third quarter of 2021.

DD&A

DD&A for year ended December 31, 2022, was $113 million (2021 – $118 million).

Income Tax

($ millions)	2022	2021	2020
Current Tax
Canada	1,252	104	(14)
United States	104	—	1
Asia Pacific	262	171	—
Other International	21	1	—
Current Tax Expense (Recovery)	1,639	276	(13)
Deferred Tax Expense (Recovery)	642	452	(838)
Total Tax Expense (Recovery)	2,281	728	(851)

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and with consideration of the current economic environment, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.

For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  35

QUARTERLY RESULTS

	2022				2021
($ millions, except where indicated)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Average Commodity Prices (US$/bbl)
Dated Brent	88.71	100.85	113.78	101.41	79.73	73.47	68.83	60.90
WTI	82.65	91.55	108.41	94.29	77.19	70.56	66.07	57.84
WCS at Hardisty	56.99	71.69	95.61	79.76	62.55	56.98	54.58	45.37
Chicago 3-2-1 Crack Spread	32.87	38.87	46.50	18.35	16.06	20.67	20.50	12.93
RINs	8.54	8.11	7.80	6.44	6.11	7.32	8.12	5.49
Upstream Production Volumes
Bitumen (Mbbls/d)	593.5	568.2	540.3	578.8	606.0	576.5	528.6	532.9
Heavy Crude Oil (Mbbls/d)	15.8	16.8	16.4	16.2	18.9	20.5	20.8	20.5
Light Crude Oil (Mbbls/d)	17.1	16.0	20.8	21.9	17.8	22.6	24.4	25.6
NGLs (Mbbls/d)	38.5	32.1	36.7	37.6	35.6	35.5	41.1	41.1
Conventional Natural Gas (MMcf/d)	852.0	868.7	882.2	865.3	883.5	897.9	905.6	894.9
Total Production Volumes (MBOE/d)	806.9	777.9	761.5	798.6	825.3	804.8	765.9	769.3
Downstream Crude Oil Throughput (1)    (Mbbls/d)	473.5	533.5	457.3	501.8	469.9	554.1	539.0	469.1
Revenues (2)	14,063	17,471	19,165	16,198	13,726	12,701	10,637	9,293
Operating Margin (3)	2,782	3,339	4,678	3,464	2,600	2,710	2,184	1,879
Cash From (Used in) Operating Activities	2,970	4,089	2,979	1,365	2,184	2,138	1,369	228
Adjusted Funds Flow (3)	2,346	2,951	3,098	2,583	1,948	2,342	1,817	1,141
Per Share - Basic (3)($)	1.22	1.53	1.57	1.30	0.97	1.16	0.90	0.57
Per Share - Diluted (3) ($)	1.19	1.49	1.53	1.27	0.97	1.15	0.89	0.56
Capital Investment	1,274	866	822	746	835	647	534	547
Free Funds Flow (3)	1,072	2,085	2,276	1,837	1,113	1,695	1,283	594
Excess Free Funds Flow (3)(4)	786	1,756	2,020	2,615	1,169	1,626	1,244	462
Net Earnings (Loss) (5)	784	1,609	2,432	1,625	(408)	551	224	220
Per Share - Basic ($)	0.40	0.83	1.23	0.81	(0.21)	0.27	0.11	0.10
Per Share - Diluted ($)	0.39	0.81	1.19	0.79	(0.21)	0.27	0.11	0.10
Total Assets	55,869	55,086	55,894	55,655	54,104	54,594	53,384	53,378
Total Long-Term Liabilities	20,259	19,378	20,742	21,889	23,191	22,929	22,972	24,266
Long-Term Debt, Including Current Portion	8,691	8,774	11,228	11,744	12,385	12,986	13,380	13,947
Net Debt	4,282	5,280	7,535	8,407	9,591	11,024	12,390	13,340
Cash Returns to Shareholders
Common Shares – Base Dividends	201	205	207	69	70	35	36	35
Base Dividends Per Common Share($)	0.105	0.105	0.105	0.035	0.035	0.018	0.018	0.018
Common Shares – Variable Dividends	219	—	—	—	—	—	—	—
Variable Dividends Per Common Share($)	0.114	—	—	—	—	—	—	—
Purchase of Common Shares Under NCIB	387	659	1,018	466	265	—	—	—
Preferred Share Dividends (6)	—	9	8	9	8	9	8	9

(1)Represents Cenovus’s net interest in refining operations.

(2)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

(3)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

(4)New metric as of June 30, 2022, used to determine returns to shareholders.

(5)Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.

(6)Preferred share dividends declared on November 1, 2022, were paid on January 3, 2023.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  36

Fourth Quarter 2022 Results Compared with the Fourth Quarter 2021

The summary below compares financial and operating results for the three months ended December 31, 2022 compared with the same period in 2021.

Upstream Production Volumes

Total upstream production decreased 18.4 thousand BOE per day in the fourth quarter of 2022 compared with the same period in 2021.

Oil Sands crude oil production decreased 15.6 thousand barrels per day to 609.3 thousand barrels per day in 2022 compared with 2021. The decrease was primarily due to the sale of the Tucker asset on January 31, 2022. Crude oil production at the time of sale was approximately 20 thousand barrels per day. In addition, production decreased at Foster Creek as production reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Offsetting the decrease was the Sunrise Acquisition on August 31, 2022, and production of approximately 12.0 thousand barrels per day from the Spruce Lake North thermal plant in the fourth quarter of 2022. In the fourth quarter of 2022, we sold approximately 25 percent (2021 – 20 percent) of our Oil Sands crude oil volumes at U.S. destinations, improving our realized sales prices.

Conventional production was 125.5 thousand BOE per day in 2022, essentially unchanged from 125.3 thousand BOE per day in 2021. Production decreases from asset sales in the first quarter of 2022 were offset by 36 net new wells brought on production in the year-ended 2022, combined with production from well reactivations and workover activity.

Offshore production was 70.2 thousand BOE per day in 2022, compared with 73.1 thousand BOE per day in 2021. The decrease was primarily due to the working interest restructuring on the White Rose fields in the second quarter of 2022, combined with contract amendments in China. These were partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022.

Downstream Manufacturing Throughput

Total crude oil throughput was consistent in the fourth quarter of 2022 compared with the same period in 2021.

Canadian Manufacturing throughput decreased 14.0 thousand barrels per day to 94.3 thousand barrels per day in 2022. Cold weather impacts and unplanned operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of January 2023. The Lloydminster Refinery had minor unplanned outages in the fourth quarter of 2022, but ran well in December and into 2023.

U.S. Manufacturing throughput increased 17.6 thousand barrels per day to 379.2 thousand compared with 2021, primarily due to the completion of a planned turnaround in the fourth quarter of 2021 at the Lima Refinery. The increase was partially offset by unplanned operational issues, weather-related impacts and third-party outages impacting the Lima, Wood River and Borger refineries in December, in addition to the shutdown of the Toledo Refinery, and Wood River running at reduced rates in December due to an operational incident.

Revenues

Revenues increased $337 million to $14.1 billion in 2022 compared with 2021. Downstream revenues increased $370 million primarily due to higher refined product pricing. Upstream revenues were flat compared with 2021, as higher realized prices in the Conventional segment were offset by lower sales volumes in the Atlantic region. Oil Sands revenues were consistent with 2021, due to flat sales volumes and realized prices year-over year.

Operating Margin

Operating Margin increased in the fourth quarter of 2022, primarily due to increased refining margins from our downstream business resulting from higher market crack spreads. The increase was partially offset by:

•Increased blending costs due to higher condensate prices impacting our Oil Sands segment.

•Higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.

•Increased transportation costs from our upstream business, due to increased tariff rates and higher rail costs due to pipeline outages in the quarter.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  37

Cash From (Used in) Operating Activities and Adjusted Funds Flow

Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to increased Operating Margin, as discussed above, and no quarterly contingent payments in 2022 (2021 – $119 million). The increase was partially offset by higher cash taxes in 2022.

Cash from operating activities also increased as the change in non-cash working capital was $402 million greater than 2021. The increase was due to lower accounts receivable and higher income tax payable, partially offset by lower accounts payable on December 31, 2022, compared with September 30, 2022.

Net Earnings (Loss)

Net earnings in the fourth quarter of 2022 was $784 million compared with a net loss of $408 million 2021 due to:

•Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of $1.6 billion in the fourth quarter of 2021.

•Higher operating margin, as discussed above.

The increase was partially offset by:

•Unrealized risk management losses of $37 million in 2022 (2021 – $222 million gain).

•Higher gain on divestiture of assets in 2021.

Capital Investment

Capital investment in the fourth quarter of 2022 was $1.3 billion, compared with $835 million in 2021. The increase is primarily due to higher capital spending in our upstream operations, including higher investment in Sunrise following the closing of the Sunrise Acquisition, incremental capital at Foster Creek, Christina Lake and Lloydminster thermal assets, increased drilling in the Conventional segment and work on the West White Rose project.

Excess Free Funds Flow

Excess Free Funds Flow was $786 million in the fourth quarter of 2022 (2021 – $1.2 billion). The decrease was due to higher capital spending and base dividends paid in 2022, partially offset by higher adjusted funds flow in 2022.

OIL AND GAS RESERVES

As at December 31, 2022 (before royalties)	Bitumen (1) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (2) (Bcf)	Total (MMBOE)
Total Proved	5,592	42	82	2,194	6,082
Probable	2,448	129	39	1,029	2,787
Total Proved Plus Probable	8,040	171	121	3,223	8,869

As at December 31, 2021 (before royalties)	Bitumen (1) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (2) (Bcf)	Total (MMBOE)
Total Proved	5,573	45	89	2,219	6,077
Probable	1,850	152	39	959	2,201
Total Proved Plus Probable	7,423	197	128	3,178	8,278

(1)Includes heavy crude oil that is not material.

(2)Includes shale gas that is not material.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  38

Developments in 2022 compared with 2021 include:

•Bitumen gross total proved and gross total proved plus probable reserves increased by 19 million barrels and 617 million barrels, respectively. The increases were due to additions from the regulatory approval at Foster Creek, the Sunrise Acquisition and improved recovery performance at Sunrise and Lloydminster thermal, partially offset by the Tucker asset sale and current year production.

•Light and medium oil gross total proved and gross total proved plus probable reserves decreased by three million barrels and 26 million barrels, respectively. The decreases were due to the disposition of 12.5 percent of the Company’s working interest in the White Rose field and satellite extensions, the Wembley asset sale and current year production, partially offset by additions from updates to the Atlantic region and Conventional segment development plans.

•NGLs gross total proved and gross total proved plus probable reserves decreased by seven million barrels each, due to dispositions in the Conventional segment and current year production, partially offset by additions from updates to the development plan and economic factors related to increased product pricing for the Conventional segment.

•Conventional natural gas gross total proved reserves decreased by 25 billion cubic feet due to the Wembley asset sale and current year production, partially offset by updates to the development plans, improved recovery performance, and economic factors due to improved product pricing for the Conventional segment. Conventional natural gas gross total proved plus probable reserves increased by 45 billion cubic feet due to updates to the development plan and economic factors due to improved product pricing for the Conventional segment, partially offset by the Wembley asset sale and current year production.

The reserves data is presented as at December 31, 2022 using an average of forecasts (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast prices and costs are dated January 1, 2023. Comparative information as at December 31, 2021 uses the January 1, 2022 Average Forecast prices and costs.

Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101,“Standards of Disclosure for Oil and Gas Activities” is contained in our AIF for the year ended December 31, 2022. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this MD&A in the Risk Management and Risk Factors section and the Advisory section in this MD&A.

LIQUIDITY AND CAPITAL RESOURCES

During 2022, we further defined our capital allocation framework to ensure we continue to strengthen our balance sheet, enable flexibility in both high and low commodity price environments, and improve our shareholder value proposition. The Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to shareholders with lower leverage and a lower risk profile. Our long-term Net Debt to Adjusted Funds Flow Target is approximately 1.0 times at the bottom of the commodity price cycle.

We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and cash equivalents and other sources of liquidity. This includes draws on our committed credit facility, draws on our uncommitted demand facilities and other corporate and financial opportunities which provide timely access to funding to supplement cash flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service, DBRS Morningstar and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.

($ millions)	2022	2021	2020
Cash From (Used In)
Operating Activities	11,403	5,919	273
Investing Activities	(2,314)	(942)	(863)
Net Cash Provided (Used) Before Financing Activities	9,089	4,977	(590)
Financing Activities	(7,676)	(2,507)	837
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency	238	25	(55)
Increase (Decrease) in Cash and Cash Equivalents	1,651	2,495	192
As at ($ millions)	2022	2021	2020
Cash and Cash Equivalents	4,524	2,873	378
Total Debt	8,806	12,464	7,562

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  39

Cash From (Used in) Operating Activities

For the year ended December 31, 2022, cash generated from operating activities increased compared with 2021 due to higher Operating Margin, changes in non-cash working capital, lower finance costs and lower integration and transaction costs.

Excluding the contingent payment, our adjusted working capital was $4.7 billion at December 31, 2022. At December 31, 2021, adjusted working capital excluding the contingent payment and assets held for sale and liabilities related to assets held for sale was $3.8 billion. The increase was primarily due to the improved commodity price environment as discussed in the Operating and Financial Results section of this MD&A. Working capital increased due to higher cash and inventories, partially offset by higher income tax payable and lower accounts receivable.

We anticipate that we will continue to meet our payment obligations as they come due.

Cash From (Used in) Investing Activities

Cash used in investing activities was higher in 2022 compared with 2021 largely due to higher capital spending, cash paid on the Sunrise Acquisition in 2022 and cash acquired in the Arrangement in 2021. The increase was partially offset by higher proceeds from divestitures in 2022.

Cash From (Used in) Financing Activities

As part of our overall deleveraging in 2022, we:

•Paid US$402 million to purchase the full amount of our 3.80 percent unsecured notes due in 2023 and 4.00 percent unsecured notes due in 2024, with principal amounts of US$115 million and US$269 million, respectively. We paid a premium on redemption of US$18 million.

•Paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025 at par.

•Paid US$2.2 billion to purchase unsecured notes due between 2025 and 2043, at a premium of US$23 million.

During 2022, net short-term borrowings increased by $34 million, related to draws on the WRB Refining LP uncommitted demand facilities.

In 2022, the Company purchased 112 million common shares through our NCIBs, at a volume weighted average price of $22.49 per common share for a total of $2.5 billion (December 31, 2021 – $265 million). The common shares were subsequently cancelled. During 2022, we paid base dividends of $682 million and variable dividends of $219 million on our common shares.

Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow

Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns plan.

	Three Months Ended December 31,		Year Ended December 31,
($ millions)	2022	2021	2022	2021	2020
Cash From (Used in) Operating Activities	2,970	2,184	11,403	5,919	273
(Add) Deduct:
Settlement of Decommissioning Liabilities	(49)	(35)	(150)	(102)	(42)
Net Change in Non-Cash Working Capital	673	271	575	(1,227)	198
Adjusted Funds Flow	2,346	1,948	10,978	7,248	117
Capital Investment	1,274	835	3,708	2,563	841
Free Funds Flow	1,072	1,113	7,270	4,685	(724)
Add (Deduct):
Base Dividends Paid on Common Shares	(201)	(70)
Dividends Paid on Preferred Shares	—	(8)
Settlement of Decommissioning Liabilities	(49)	(35)
Principal Repayment of Leases	(74)	(78)
Acquisitions, Net of Cash Acquired	(7)	—
Proceeds From Divestitures	45	247
Excess Free Funds Flow	786	1,169

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  40

Returns to Shareholders Target

	Three Months Ended
($ millions)	December 31, 2022	September 30, 2022	June 30, 2022
Excess Free Funds Flow	786	1,756	2,020
Target Return (1)	393	878	1,010
Less: Purchase of Common Shares Under NCIBs	(387)	(659)	(1,018)
Amount Available for Variable Dividend	6	219	(8)

(1)Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, June 30, 2022 and March 31, 2022, being less than $9 billion and greater than $4 billion, Target Return was determined to be 50 percent of Excess Free Funds Flow.

In the fourth quarter of 2022, we paid variable dividends of $219 million. Returns to shareholders through share buybacks were within $50 million of the fourth quarter Target Return, as such no variable dividend was declared for the quarter.

Short-Term Borrowings

As at December 31, 2022, US$170 million was drawn on the WRB uncommitted demand facility, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US$63 million (C$79 million)).

Long-Term Debt and Total Debt

Total Debt as at December 31, 2022, was $8.8 billion (December 31, 2021 – $12.5 billion), which includes $8.7 billion of long-term debt (December 31, 2021 – $12.4 billion). The decrease in Total Debt and long-term debt was due to the purchase of US$2.6 billion and $750 million of principal related to outstanding unsecured notes in 2022.

As at December 31, 2022, we were in compliance with all of the terms of our debt agreements.

Available Sources of Liquidity

The following sources of liquidity are available as at December 31, 2022:

($ millions)	Maturity	Amount Available
Cash and Cash Equivalents	N/A	4,524
Committed Credit Facility (1)
Revolving Credit Facility – Tranche A	November 10, 2026	3,700
Revolving Credit Facility – Tranche B	November 10, 2025	1,800
Uncommitted Demand Facilities (2)
Cenovus Energy Inc. (3)	N/A	1,002
WRB Refining LP (4)	N/A	190

(1)No amounts were drawn on the committed credit facility as at December 31, 2022 (December 31, 2021 - $nil).

(2)On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility.

(3)Our uncommitted demand facilities includes $1.9 billion, of which $1.4 billion may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at December 31, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no direct borrowings.

(4)Represents Cenovus's 50 percent share of US$450 million (our proportionate share – US$225 million) available to cover short-term working capital requirements. As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US $63 million (C$79 million)).

On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to $5.5 billion and to extend the maturity dates.

Under the terms of our committed credit facility,    we are required to maintain a debt to capitalization ratio, as defined in the debt agreements, not to exceed 65 percent. We are well below this limit.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  41

U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes

At December 31, 2022, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$4.8 billion and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.0 billion.

	Unsecured Notes
	U.S. Dollar Denominated (US $ millions)	Canadian Dollar Denominated ($ millions)
As at December 31, 2021	7,385	2,750
Purchases	(2,558)	(750)
As at December 31, 2022	4,827	2,000

Base Shelf Prospectus

We have a base shelf prospectus that allows us to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere, where permitted by law. The base shelf prospectus will expire in November 2023. As at December 31, 2022, US$4.7 billion remained available under the base shelf prospectus for permitted offerings (December 31, 2021 – US$4.7 billion). Offerings under the base shelf prospectus are subject to market availability.

Financial Metrics

We monitor our capital structure and financing requirements using the Net Debt to Capitalization Ratio, Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio. Refer to Note 26 of the Consolidated Financial Statements for further details.

We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholders Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow Ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA Ratio, as net earnings before finance costs, net of capitalized interest, interest income, income tax expense (recovery), DD&A, E&E write-down, goodwill impairments, unrealized (gain) loss on risk management, foreign exchange (gain) loss, revaluation (gains), re-measurement of contingent payment, (gain) loss on divestiture of assets, other (income) loss, net and share of (income) loss from equity-accounted affiliates calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and as measures of our overall financial strength.

As at	2022	2021	2020
Net Debt to Capitalization Ratio (percent)	13	29	30
Net Debt to Adjusted Funds Flow Ratio (times)	0.4	1.3	61.4
Net Debt to Adjusted EBITDA Ratio (times)	0.3	1.2	11.9

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  42

Our Net Debt to Adjusted Funds Flow Ratio and our Net Debt to Adjusted EBITDA Ratio Targets are approximately 1.0 times at the bottom of the commodity price cycle, which we believe is approximately US$45 per barrel WTI. This ratio may fluctuate periodically outside the range due to factors such as persistently high or low commodity prices. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares.

Our Net Debt to Capitalization Ratio as at December 31, 2022 decreased compared with December 31, 2021, primarily due to higher net earnings and ongoing reductions in Net Debt.

Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2022 decreased compared with December 31, 2021, as a result of higher Operating Margin and lower Net Debt. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt.

Share Capital and Stock-Based Compensation Plans

As at December 31, 2022, there were approximately 1,909 million common shares outstanding (December 31, 2021 – 2,001 million common shares) and 36 million preferred shares outstanding (December 31, 2021 – 36 million preferred shares). Refer to Note 32 of the Consolidated Financial Statements for further details.

In November 2021, we commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares between November 9, 2021 and November 8, 2022. On November 7, 2022, we renewed the NCIB program to purchase up to an additional 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023. In 2022, Cenovus purchased and cancelled 112 million common shares for $2.5 billion (year ended December 31, 2021 – 17 million common shares for $265 million), at a volume weighted average price of $22.49 per common share through our NCIBs. Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB.

As at December 31, 2022, there were approximately 56 million Cenovus Warrants outstanding (December 31, 2021 – 65 million Cenovus Warrants). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years (from the date of issue) at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to Note 32 of the Consolidated Financial Statements for further details.

Refer to Note 34 of the Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans.

Our outstanding share data is as follows:

As at February 13, 2023	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	1,907,867	N/A
Cenovus Warrants	55,691	N/A
Series 1 First Preferred Shares	10,740	N/A
Series 2 First Preferred Shares	1,260	N/A
Series 3 First Preferred Shares	10,000	N/A
Series 5 First Preferred Shares	8,000	N/A
Series 7 First Preferred Shares	6,000	N/A
Stock Options	17,373	8,312
Other Stock-Based Compensation Plans	16,891	1,581

Common Share Dividends

In 2022, we paid base dividends of $682 million or $0.350 per common share (2021 – $176 million or $0.088 per common share) and variable dividends of $219 million or $0.114 per common share (2021 – $nil).

The Board declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023.

The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  43

Cumulative Redeemable Preferred Share Dividends

In 2022, dividends of $26 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (December 31, 2021 — $34 million). The decrease from 2021 is related to timing differences between the declaration date and payment date. The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly. The Board declared a first quarter dividend on the series 1, 2, 3, 5 and 7 preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of record as of March 15, 2023.

Capital Investment Decisions

Our 2023 capital program is forecast to be between $4.0 billion and $4.5 billion, including approximately $2.8 billion of sustaining capital and between $1.2 billion to $1.7 billion of optimization and growth capital. Our Future Capital Investment is focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost control and positioning the Company for continued growth in shareholder returns. We expect our annual upstream production to average between 800 thousand BOE per day and 840 thousand BOE per day and our downstream crude oil throughput average between 610 thousand barrels per day to 660 thousand barrels per day in 2023. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com.

Contractual Obligations and Commitments

We have obligations for goods and services entered into in the normal course of business. Commitments are largely related to transportation agreements. Commitments that have original maturities of less than one year are excluded from the table below. For further information, see Note 40 to the Consolidated Financial Statements.

Our total commitments were $33.0 billion as at December 31, 2022, of which $21.1 billion are for various transportation and storage commitments and $9.4 billion are for product purchase commitments. Transportation commitments include $9.1 billion that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the date of commencement and should help align with the Company’s future transportation requirements.

Our commitments with HMLP at December 31, 2022, include $2.2 billion related to long-term transportation and storage commitments.

As at December 31, 2022 ($ millions)	2023	2024	2025	2026	2027	Thereafter	Total
Commitments (1)
Transportation and Storage (2)	1,747	2,011	1,542	1,416	1,360	13,005	21,081
Product Purchases (3)	1,626	1,509	922	922	922	3,457	9,358
Real Estate (4)	48	50	50	50	54	604	856
Obligation to Fund Equity-Accounted Affiliate (5)	92	105	96	96	91	143	623
Other Long-Term Commitments	381	90	75	74	65	395	1,080
Total Commitments	3,894	3,765	2,685	2,558	2,492	17,604	32,998
Long-Term Debt (Principal and Interest)	401	401	582	392	1,622	11,196	14,594
Decommissioning Liabilities	263	254	249	248	247	5,979	7,240
Contingent Payments	271	167	—	—	—	—	438
Lease Liabilities (Principal and Interest) (6)	426	407	339	320	276	2,889	4,657
Total Commitments and Obligations	5,255	4,994	3,855	3,518	4,637	37,668	59,927

(1)Commitments are reflected at Cenovus’s proportionate share of the underlying contract.

(2)Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the commencement of the contract.

(3)Prior to September 30, 2022, product purchases were included in Transportation and Storage.

(4)Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(5)Relates to funding obligations for HCML.

(6)Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment.

As at December 31, 2022, outstanding letters of credit issued as security for performance under certain contracts totaled $490 million (December 31, 2021 – $565 million).

Legal Proceedings

We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements.

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Transactions with Related Parties

Transactions with HMLP are related party transactions as we have a 35 percent ownership interest in HMLP. As the operator of the assets held by HMLP, we provide management services for which we recover shared service costs. We are also the contractor for HMLP and construct its assets on a cost recovery basis with certain restrictions. For the year ended December 31, 2022, we charged HMLP $188 million for construction and management services (2021 – $243 million).

We pay an access fee to HMLP for the use of its pipeline systems that are used by our blending business. We also pay HMLP for transportation and storage services. For the year ended December 31, 2022, we incurred costs of $263 million for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million).

RISK MANAGEMENT AND RISK FACTORS

We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the energy industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, our business, reputation, financial condition, results of operations and cash flows, which may, without limitation, reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, respond to changes in our operating environment, repurchase our shares, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and/or may materially affect the market price of our securities.

Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of our risks and is integrated with the Cenovus Operations Integrity Management System (“COIMS”). In addition, we continuously monitor our risk profile as well as industry best practices.

Risk Governance

The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Building on the ERM Policy, we have established risk management standards, a risk management framework and risk assessment tools, including the Cenovus risk matrix. Our risk management framework contains the key attributes recommended by the International Organization for Standardization (“ISO”) in its ISO 31000 – Risk Management Guidelines. The results of our ERM program are documented in semi-annual risk reports presented to our Board as well as through regular updates.

Risk Factors

The following discussion describes the financial, operational, regulatory, environmental, reputational, and other risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks, have a material impact on, among other things, our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund share repurchases, dividend payments and/or business plans, and/or the market price of our securities. These factors should be considered when investing in securities of Cenovus.

Pandemic Risk

The COVID-19 pandemic remains a risk for the Company. While restrictions have ended or been relaxed in many parts of the world, other jurisdictions continue to impose measures to combat the virus. The COVID-19 pandemic (including the emergence of variant strains of COVID-19) and measures taken in response by governments and health authorities around the world have created ongoing uncertainty that has resulted in and may continue to result in restrictions on movement and businesses being maintained, re-imposed or imposed on a stricter basis, which could negatively impact our business, results of operations and financial condition.

The COVID-19 pandemic, or other pandemics, endemics or outbreaks, may increase our exposure to, and the magnitude of, each of the risks identified in this Risk Management and Risk Factors section of this MD&A and identified in other documents we file with securities regulators from time to time. The duration or extent of the impacts of the COVID-19 pandemic on our business, results of operations and financial condition will depend on future developments, which are highly uncertain and are difficult to predict with any degree of precision, and include but are not limited to: the severity, duration, spread or resurgence of COVID-19 or its variants; the timing, extent and effectiveness of actions taken to contain or treat COVID-19 or its variants, including the availability, distribution rate, effectiveness and public uptake of any vaccines or boosters; and the speed at which, and extent to which, normal economic and operating conditions resume.

There are no comparable recent events that provide guidance as to the effect the COVID-19 pandemic may have, and, as a result, the ultimate impact of the COVID-19 pandemic is highly uncertain and subject to change. The COVID-19 pandemic and the corresponding measures we take to protect the health and safety of our staff and the continuity of our business may result in new legal challenges and disputes, including, but not limited to, litigation involving contract parties or employees and class action claims.

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Financial Risk

Commodity Prices

Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural gas and NGLs. Crude oil prices are impacted by a number of factors, including, but not limited to: global and regional supply of and demand for crude oil; the ability of producers and governments to replace reduced supply; processing and export capacity; global economic conditions; and activity; inflation and rising interest rates; the potential for a recession; market competitiveness; the actions of OPEC and other oil exporting nations, including, but not limited to, compliance or non-compliance with quotas agreed upon by OPEC members and decisions by OPEC not to impose production quotas on its members; the release of SPRs; developments related to the market for crude oil; levels of oil inventories; current and potential future environmental regulations, including regulations pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; prices and availability of alternate sources of energy; actions of domestic or foreign governments or regulatory bodies that may impact commodity prices; enforcement of government or environmental regulations; public sentiment towards the use of non-renewable resources, including crude oil; political stability and social conditions in oil-producing countries; market access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions.

The financial performance of our oil sands operations could also be impacted by discounted or reduced commodity prices for our oil sands production relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell products to domestic and international markets and the quality of oil produced. Of particular importance to us are diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy crude oil. Bitumen is more expensive for refineries to process and therefore generally trades at a discount to the market price for light to medium crude oil and heavy crude oil which, along with higher diluent costs, can adversely affect our financial condition.

Our natural gas and NGL production is currently located in Western Canada and Asia Pacific. Natural gas and NGL prices are impacted by a number of factors, including, but not limited to: global and regional supply and demand for natural gas and NGLs; global economic conditions; market competitiveness; developments related to the market for liquefied natural gas; levels of natural gas and NGL inventories; export capacity; current and potential future environmental regulations, including regulations pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; prices and availability of alternate sources of energy; actions of domestic or foreign governments or regulatory bodies that may impact commodity prices; enforcement of government or environmental regulations; public sentiment towards the use of non-renewable resources, including natural gas and NGLs; political stability and social conditions in natural gas and NGL-producing countries; market access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions.

Refined product prices are impacted by a number of factors, including, but not limited to: global and regional supply and demand for refined products; the ability of producers and governments to replace reduced supply; global economic conditions and activity; inflation and rising interest rates; central bank policies; seasonal trends; the potential for a recession; market competitiveness; developments related to the market for refined products; levels of refined product inventories; refinery availability; planned and unplanned refinery maintenance; current and potential future environmental regulations, including the United States Renewable Fuel Standard (“RFS”) and other regulations pertaining to the production and use of refined products and non-renewable resources; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; prices and availability of alternate sources of energy; public sentiment towards the use of non-renewable resources, including refined products; market access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions.

The financial performance of our refining operations is also impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production levels change to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact on our business, results of operations, cash flows and financial condition.

In addition, relating to the level of future demand (and corresponding price levels) for each of crude oil, refined products, natural gas and NGLs, there has been a significant increase in focus on the timing for and pace of the transition to a lower-carbon economy. See “Climate Change Transition – Demand and Commodity Prices” below. All of these factors are beyond our control and can result in a high degree of both cost and price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars. See “Foreign Exchange Rates” below.

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Fluctuations in the commodity prices, associated price differentials and refining margins may impact our ability to meet guidance targets, the value of our assets, our cash flows, level of shareholder returns and our ability to maintain our business and fund projects. A substantial decline in these commodity prices or an extended period of low commodity prices may result in an inability to meet all of our financial obligations as they come due, a delay or cancellation of existing or future drilling, development or construction programs, curtailment in production, unutilized long-term transportation commitments and/or low utilization levels at our refineries. Fluctuations in commodity prices, associated price differentials and refining margins impact our financial condition, results of operations, cash flows, growth, access to capital and cost of borrowing.

The commodity price risks noted above, as well as other risks such as market access constraints and transportation restrictions, reserves replacement and reserves estimates and cost management that are more fully described herein, may have a material impact on our business, financial condition, results of operations, cash flows and reputation and may be considered indicators of impairment. Another potential indicator of impairment is the comparison of the carrying value of our assets to our market capitalization.

As discussed in this MD&A, we conduct an assessment, at each reporting date, of the carrying value of our assets in accordance with IFRS. If crude oil, NGLs, refined product, and natural gas prices decline significantly and remain at low levels for an extended period of time, or if the costs of our development of such resources significantly increase, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.

We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts, and market access commitments, and generally through our access to our committed credit facility. In certain instances, we will use derivative instruments to manage exposure to price volatility on a portion of our refined product, oil and gas production, inventory or volumes in long-distance transit. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 37 and 38 of the Consolidated Financial Statements.

Hedging Activities

Our Market Risk Management Policy, which has been approved by our Board, allows Management to use derivative instruments, including exchange-traded futures contracts, commodity put and call options and other approved instruments such as non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil and condensate prices and differentials, natural gas spreads, basis and prices, NGLs, electricity prices, refined product and crack spread margins, as well as fluctuations in foreign exchange rates and interest rates. We may also use fixed-price commitments for the purchase or sale of crude oil, natural gas, NGLs and refined products. We may also use derivative instruments in various operational markets to help optimize our supply costs or sales of our production.

These hedging activities may expose us to risks which may cause significant loss. These risks include, but are not limited to: changes in the valuation of the hedge instrument being poorly correlated to the change in the valuation of the underlying exposures being hedged; change in price of the underlying commodity or market value of the instrument; lack of market liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; and the unenforceability of contracts.

For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3, 37 and 38 of the Consolidated Financial Statements.

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Risks Associated with Derivative Financial Instruments

Derivative financial instruments expose us to the risk that a counterparty may default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Board-approved Credit Policy. Derivative financial instruments also expose us to the risk of a loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical transaction. These risks are managed through hedging limits authorized according to our Market Risk Management Policy. Although we have suspended our crude oil sales price risk management activities related to WTI, certain financial instruments related to our condensate, feedstock and refined product price risk management programs which include WTI, remain outstanding and will continue to be used, in addition to financial instruments related to natural gas, electricity, interest and exchange rates applicable to our business. As such, we will be exposed to the risk of a loss from adverse changes in the market value of any such financial instruments. These financial instruments may also limit the benefit to us if commodity prices, interest or foreign exchange rates change. Fluctuations in the price of WTI may have a larger impact on our financial condition, results of operations, cash flows, growth, access to capital, ability to fund share repurchases and/or dividends and cost of borrowing, compared to the periods prior to the suspension of our crude oil sales price risk management activities related to WTI.

For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3, 37 and 38 of the Consolidated Financial Statements.

Impact of Financial Risk Management Activities

Cenovus makes storage and transportation decisions, considering our marketing and transportation infrastructure including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification. In order to price protect our inventories associated with storage or transport decisions, Cenovus employs various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.

In a rising commodity price environment, we expect to realize losses on our risk management activities but recognize gains on the underlying physical inventory sold in the period, and we expect the opposite to occur in a falling commodity price environment. In 2022, we incurred a realized loss on our risk management positions due to the settlement of benchmark prices relative to our risk management contract prices but recognized a gain on the underlying physical inventory sold during such period due to changing benchmark prices.

Transactions typically span across periods, as such, these transactions reside across both realized and unrealized risk management. As the financial contracts settle, they will flow from unrealized to realized risk management gains and losses.

The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices on our open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

As at December 31, 2022	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	1	(1)
WCS and Condensate Differential Price(1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	13	(13)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(1)	1
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
Natural Gas Basis Price	± US$0.50/MCF Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/Megawatt Hour Applied to Power Hedges	113	(113)
U.S. to Canadian Dollar Exchange Rate	± 0.05 in the U.S. to Canadian Dollar Exchange Rate	14	(17)

(1)    Excludes WCS (Hardisty) differential.

For further information on our risk management positions, see Notes 37 and 38 of the Consolidated Financial Statements.

Exposure to Counterparties

In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders, customers and other counterparties for the provision and sale of goods and services and also in connection with our hedging activities, and in respect of asset or securities acquisitions and dispositions. If such counterparties do not fulfill their contractual obligations on a timely basis or at all, we may suffer financial losses or delays of our development plans, or we may have to forego other opportunities, all of which could materially impact our business, results of operations and financial condition.

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Credit, Liquidity and Availability of Future Financing

The future development of our business may be dependent on our ability to obtain additional capital, including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn or significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations or investor or lender policy or sentiment, may impede our ability to secure and maintain cost-effective financing. Stakeholders are increasingly considering ESG matters, including climate-related targets, and failure to achieve our emissions reduction targets, or the perception that our targets are insufficient or will not be achieved, could adversely affect our ability to access cost-effective capital. An inability to access capital, on terms acceptable to us or at all, could affect our ability to make future capital expenditures, to maintain desirable financial ratios and to meet all of our financial obligations as they come due, potentially resulting in a material adverse effect on our business, financial condition, results of operations, cash flows, ability to comply with various financial and operating covenants, credit ratings and reputation.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, regulatory, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, we may take actions such as reducing or suspending share repurchases and/or dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional capital that could have less favourable terms.

Our liquidity risk is mitigated through actively managing cash and cash equivalents, cash flow provided by operating activities, available credit facility capacity, and accessing the capital markets.

We are required to comply with various financial and operating covenants under our credit facility and the indentures governing our debt securities. We routinely review our covenants to ensure compliance. In the event that we do not comply with such covenants, our access to capital could be restricted or repayment could be accelerated.

Credit Ratings

Our Company and our capital structure are regularly evaluated by credit rating agencies. Credit ratings are based on our financial and operational strength and a number of factors not entirely within our control, including but not limited to, conditions affecting the oil and gas industry generally, industry risks associated with the transition to a lower-carbon economy, and the general state of the economy. There can be no assurance that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency.

A reduction in any of our credit ratings, particularly a downgrade below investment grade ratings, or a negative change in the Company’s credit ratings outlook could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. A failure to maintain our current credit ratings could affect our business relationships with counterparties, operating partners and suppliers.

If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post collateral in the form of cash, letters of credit or other financial instruments in order to establish or maintain business arrangements. Additional collateral may be required due to further downgrades below certain ratings thresholds. Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated.

Foreign Exchange Rates

Fluctuations in foreign exchange rates between various currencies may affect our results, particularly the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. Global prices for crude oil, refined products, and natural gas are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A change in the value of the Canadian dollar, as a result of changing benchmark lending rates, macroeconomic factors or otherwise, relative to the U.S. dollar will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas sales. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related U.S. dollar interest expense, as expressed in Canadian dollars. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. A change in the value of the Canadian dollar relative to RMB will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of natural gas and NGLs in the region. We may periodically enter into transactions to manage our exposure to exchange rate fluctuations. However, the fluctuations in exchange rates are beyond our control and could have a material adverse effect on our cash flows, results of operations and financial condition.

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Interest Rates

Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation. Interest rates have increased in response to inflation and additional rate increases may be implemented. Increases in interest rates could increase our net interest expense and affect how certain liabilities are recorded, both of which could negatively impact our cash flow and financial results. Additionally, we are exposed to interest rate fluctuations upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates. We may periodically enter into transactions to manage our exposure to interest rate fluctuations.

Dividend Payments and Purchase of Securities

The payment of dividends, whether base, variable or preferred, the continuation of our dividend reinvestment plan and any potential purchase by Cenovus of our securities is at the discretion of our Board, and is dependent upon, among other things, financial performance, debt covenants, satisfying solvency tests, our ability to meet financial obligations as they come due, working capital requirements, future tax obligations, future capital requirements, commodity prices and other risks identified in the Risk Management and Risk Factors section of this MD&A. Specifically, in connection with Cenovus’s capital allocation framework, the Company will target returns to shareholders as a percentage of Excess Free Funds Flow, through share buybacks or variable dividends, based on Net Debt at the preceding quarter-end, as described in this MD&A. The frequency and amount of variable dividend payments, if any, may vary significantly over time as a result of our Net Debt and Excess Free Funds Flow, amount of share buybacks and other factors inherent with our capital allocation framework from time to time and our Net Debt and Excess Free Funds Flow may vary from time to time as a result of, among other things, our business plans, results of operations, financial condition and impact of any of the risks identified in the Risk Management and Risk Factors section of this MD&A. The Company can provide no assurance that it will continue to pay base or variable dividends or authorize share buybacks at the current rate or at all as the capital allocation framework, and any share repurchases and payment of dividends thereunder, remains at the discretion of our Board and is dependent on, among other things, the factors described above. Further, the individual or aggregate amount of base or variable dividends, if any, paid by Cenovus from time to time may result in adjustments to the exercise price and the exchange basis (the number of common shares received for each Cenovus Warrant exercised) of the Cenovus Warrants under the terms of the indenture governing the Cenovus Warrants. Such adjustments may impact the value received by Cenovus upon the exercise of Cenovus Warrants and may result in additional issuances of common shares on the exercise of Cenovus Warrants which may have a further dilutive effect on the ownership interest of shareholders of Cenovus and on Cenovus’s earnings per share.

Disclosure Controls and Procedures and Internal Control Over Financial Reporting (“ICFR”)

Based on their inherent limitations, disclosure controls and procedures and ICFR may not prevent or detect misstatements, and even those controls determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on our business, financial condition, results of operations, cash flows and reputation.

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Operational Risk

Operational Considerations (Safety, Environment and Reliability)

Our operations are subject to risks generally affecting the energy industry and normally incidental to: (i) the storing, transporting, processing and marketing of crude oil, refined products, natural gas, NGLs and other related products; (ii) drilling and completion of onshore and offshore crude oil and natural gas wells; (iii) the operation and development of crude oil and natural gas properties; and (iv) the operation of refineries, terminals, pipelines and other transportation and distribution facilities in the jurisdictions in which we conduct our business, including at facilities operated by our partners or third-parties. These risks include but are not limited to: the effects of government actions or regulations, policies and initiatives; encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; explosions; blowouts; loss of containment; gaseous leaks; power outages; migration of harmful substances into water systems; releases or spills, including releases or spills from offshore operations, shipping vessels or other marine transport incidents; aviation, railcar or road transportation incidents; iceberg incidents; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or operate within established operating parameters; adverse weather conditions; corrosion; pollution; freeze-ups and other similar events; the breakdown or failure of equipment, pipelines and facilities, information technology and systems and processes; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; railcar incidents or derailments; failure to maintain adequate supplies of spare parts; the compromise of information technology and control systems and related data; operator error; labour disputes; disputes with interconnected facilities and carriers; planned or unplanned operational disruptions or apportionment on third-party systems or refineries, which may prevent the full utilization of such party’s facilities and pipelines; spills at truck terminals and hubs; spills associated with the loading and unloading of potentially harmful substances; loss of product; unavailability of feedstock; price and quality of feedstock; epidemics or pandemics; catastrophic events, including, but not limited to, war, adverse sea conditions, acts of activism, vandalism or terrorism, extreme weather events and natural disasters and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites.

If any such risks materialize, they may interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology and control systems, related data, cause environmental damage that may include polluting water, land or air, and may result in regulatory action, fines, penalties, civil suits or criminal or regulatory charges against us, any of which may have a material adverse effect on our business, financial condition, results of operations, cash flows and reputation.

In addition, our oil sands operations are susceptible to reduced production, slowdowns, shutdowns and restrictions on our ability to produce higher value products due to the interdependence of our component systems. Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production.

To partially mitigate our risks, we have policies and an associated system of standards, processes and procedures to identify, assess and mitigate safety, operational and environmental risk across our operations. In addition, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations. However, not all potential occurrences and disruptions in respect of our assets or operations are insured or are insurable, and it cannot be guaranteed that our insurance coverage will be available or sufficient to fully cover any claims that may arise from such occurrences or disruptions. The occurrence of an event that is not fully covered by our insurance program could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Market Access Constraints and Transportation Restrictions

Our production is transported through various pipelines, terminals and marine, rail and truck networks, and our refineries are reliant on various pipelines and marine, rail and truck networks to transport feedstock and refined products to and from our facilities. Increased tariffs or disruptions in, or restricted availability of, pipeline service and/or marine, rail or truck transport, could adversely affect crude oil, refined products, natural gas and NGLs sales, projected production growth, upstream or refining operations and cash flows.

Interruptions or restrictions in the availability of these pipeline, terminals, marine, rail and truck systems may also limit the ability to deliver production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our products. These interruptions and restrictions may be caused by, among other things, the inability of the pipeline or marine, rail or truck networks to operate, or may be related to capacity constraints if supply into the system exceeds the infrastructure capacity. There can be no certainty that investments in new pipeline projects will be made by applicable third-party pipeline providers, that any applications to expand capacity will receive the required regulatory approvals, or that any such approvals will result in the construction of the pipeline project, or that such projects would provide sufficient transportation capacity.

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There is no certainty that rail, marine transport and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, our rail, marine and truck shipments may be impacted by service delays, shortages of skilled labour, inclement weather, vessel, railcar or truck availability, railcar derailment or other rail, marine or truck transport incidents and could adversely impact sales volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal injury, loss of equipment or property, or environmental damage. In addition, rail, marine and trucking regulations are constantly being reviewed to ensure the safe operation of the supply chain. Should regulations change, the costs of complying with those regulations will likely be passed on to shippers and may adversely affect our ability to transport by-rail, marine or truck transport or the economics associated with such transportation. Finally, planned or unplanned shutdowns, outages or closures of our refineries or third-party systems or refineries may limit our ability to deliver product with negative implications on our business, financial condition, results of operations and cash flows.

Reserves Replacement and Reserve Estimates

If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves. Exploring for, developing or acquiring reserves is capital intensive. To the extent our cash flow is insufficient to fund capital expenditures and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and expand our crude oil and natural gas reserves will be impaired. In addition, we may be unable to find and develop or acquire additional reserves to replace our crude oil and natural gas production at acceptable costs.

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including, but not limited to: geological and engineering estimates; product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes, and environmental and emissions related regulations and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary materially from estimated results.

All such estimates are uncertain, and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material.

Estimates with respect to reserves that may be developed and produced in the future are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based on production history will result in variations, which may be material, in the estimated reserves.

The production rate of oil and gas properties tends to decline as reserves are depleted while the associated operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on schedule; and the application of successful exploitation techniques on mature properties. Our business, reputation, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves.

Cost Management and Inflation

Development, operating and construction costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies; inflationary price pressure; changes in regulatory compliance costs; scheduling delays; interruptions to existing market access infrastructure; failure to maintain quality construction and manufacturing standards; equipment limitations, including the cost or availability of oil and gas field equipment; commodity prices; higher steam-oil ratios in our Oil Sands operations; additional government or environmental regulations and supply chain disruptions, including access to skilled labour and critical third-party services. In addition, if our development, operating, construction or labour costs were to become subject to significant inflationary pressures, we may not be able to fully offset such higher costs through corresponding increases in commodity prices. Further, there can be no assurance that any governmental action to mitigate inflationary cycles will be taken or will be effective. Central banks have increased interest rates in response to inflation and additional rate increases may be implemented. Governmental actions, such as the imposition of higher interest rates or wage controls may also negatively impact the Company’s costs and magnify the impacts of other risks identified in the Risk Management and Risk Factors section of this MD&A, including those set out under the “Financial Risk - Interest Rates” section above.

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Continued inflation, any governmental response thereto, our inability to manage costs, or our inability to secure equipment, materials, skilled labour or third-party services necessary to our business activities for the expected price, on the expected timeline, or at all, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Competition

The Canadian and international energy industry is highly competitive in all aspects, including accessing capital, the exploration for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas interests and the refining, distribution and marketing of oil and gas products. We compete with other producers, refiners and marketers, some of which may have lower operating costs or greater resources than our Company does. Competitors may develop and implement technologies which are superior to those we employ. The oil and gas industry also competes with other industries in supplying energy, fuel and related products to consumers, including renewable energy sources which may become more prevalent in the future. Cenovus may not be able to compete successfully against current and future competitors, and competitive pressures on Cenovus could have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows.

Project Execution

We manage a variety of oil, natural gas and refining projects across our global portfolio of assets, including the current rebuild of our Superior Refinery and the restart of the West White Rose Project. The wide range of risks associated with project development and execution, as well as the commissioning and integration of new facilities with existing assets, can impact the economic viability of our projects. These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory approvals; our ability to obtain favourable terms or to be granted access within land-use agreements; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of supply chain disruptions; the impact of general economic, business and market conditions including inflationary pressures; the impact of weather conditions; risk related to the accuracy of project cost estimates; our ability to finance capital expenditures and expenses; our ability to source or complete strategic transactions; the effect of the COVID-19 pandemic on project execution and timelines; and the effect of changing government regulation and public expectations in relation to the impacts of oil and gas operations on the environment. The commissioning and integration of new facilities within our existing asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could affect our safety and environmental record and have a material adverse effect on our financial condition, results of operations and cash flows and reputation.

Partner Risks

Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures. Therefore, our results of operations and cash flows may be affected by the actions of third-party operators or partners in areas where our ability to control and manage risks may be reduced. We rely on the judgment and operating expertise of our partners in respect of the development and operation of such assets and to provide information on the status of such assets and related results of operations; however, we are, at times, dependent upon our partners for the successful execution of various projects, their management of operational issues and their reporting.

Our partners may have objectives and interests that do not align with or may conflict with our interests. No assurance can be provided that our future demands or expectations relating to such assets will be satisfactorily met in a timely manner or at all. If a dispute with a partner or partners were to occur over the development and operation of a project or if a partner or partners were unable to fund their contractual share of the capital expenditures, a project could be delayed, and we could be partially or totally liable for our partner’s share of the project. Should one of our partners become insolvent, we may similarly be directed by applicable regulators to carry out obligations on behalf of our partner and may not be able to obtain reimbursement for these costs. Failure to manage these partner risks could have a material adverse effect on our business, financial condition, results of operations, reputation, and cash flows.

SAGD Technology

Current technologies used for the recovery of bitumen is energy intensive, including SAGD which requires significant consumption of natural gas in the production of steam used in the recovery process. The amount of steam required in the recovery process varies and therefore impacts costs. The performance of the reservoir affects the timing and levels of production using SAGD technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial condition, results of operations, and cash flows. There are risks associated with growth and other capital projects that rely largely or partly on new technologies, the incorporation of such technologies into new or existing operations, and acceptance of new technologies in the market. The success of projects incorporating new technologies cannot be assured.

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Technology, Information Systems and Data Privacy

We rely heavily on technology, including operating technology and information technology, to effectively operate our business. This may include on premise systems (such as networks, computer hardware and software), networks and telecommunications systems, mobile applications, cloud services and other technology systems and services. Such systems and services may be provided by third parties. In the event we are unable to access, use, rely upon, secure, upgrade, and take other steps to maintain or improve the efficiency, resiliency and efficacy of such systems and services, the operation of such systems and services could be interrupted, resulting in operational interruptions or the loss, corruption, or release of data.

In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary information, business information, and personal information. Despite our security measures, our technology systems and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties) or to disruptions from staff or third-party error or malfeasance, or natural disasters and acts of state or industrial espionage, activism, terrorism, or war. These risks also include, but are not limited to, cyber-related fraud or attacks such as attempts to circumvent electronic communications controls, impersonating internal personnel or business partners to divert payments and financial assets to accounts controlled by the perpetrators, or introducing ransomware into one or more systems or services to extract a payment, among others.

Any such incident, breach, or disruption of our or our service providers’ technology systems or services, or other vendor technology systems or services (including where a threat actor is successful in bypassing our cyber-security measures and business process controls), could result in loss or the exposure of internal, confidential, financial, proprietary, personal or other sensitive information. These could result in financial losses, remediation and recovery costs, legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative consequences, including damage to our reputation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in which we operate. We must comply with increasingly complex and rigorous, and sometimes conflicting, regulatory standards enacted to protect business and personal information in Canada, the United States, and elsewhere. These laws impose additional obligations on companies regarding the handling of personal information and provide certain individual privacy rights to persons whose information is collected, used, stored, processed or disclosed. Compliance with existing, proposed and recently enacted laws and regulations can be costly and time consuming, and any failure to comply with these regulatory standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in violation of data privacy laws and regulations, proceedings against the Company by governmental entities or others, imposition of fines by governmental authorities and damage to our reputation and credibility and could have a negative impact on financial condition. Compliance with such legislation may also result in increased operating costs. Failure to comply with such legislation may result in severe fines and penalties, which may adversely impact our reputation, financial condition, results of operations and cash flows.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact our personnel, or those of partners, customers, and suppliers, and could result in situations of injury, loss of life, extortion, hostage situations and/or kidnapping or unlawful confinement, destruction or damage to property of Cenovus or others, impact to the environment, and business interruption. A security threat, terrorist attack or activist incident targeted at a facility, terminal, pipeline, rail or trucking network, office or offshore vessel/installation owned or operated by Cenovus or any of our systems, services, infrastructure, market access routes, or partnerships could result in the interruption or cessation of key elements of our operations. Outcomes of such incidents could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Activism and Disruptions to Operations

Increasing public engagement and activism generally, and in connection with the energy industry and the continued development of fossil fuel-based energy, has, from time to time, resulted in temporary disruptions to oil and gas development, operations and transportation. Such opposition has not yet materially impacted our facilities directly; however, activist groups and individuals may engage in protests, demonstrations or blockades that may disrupt our facilities or operations, or to facilities or operations on which we rely. Any such disruptions may have an adverse impact on our business, operations, financial condition or reputation.

While we have systems, policies and procedures designed to prevent or limit the effects of such disruptive events, there can be no assurance that these measures will be sufficient and that such disruptions will not occur or, if they do occur, that they will be adequately addressed in a timely manner.

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Leadership and Talent

Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our workforce. If we are unable to attract and retain key personnel and critical and diverse talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our business, financial condition, results of operations, and our ability to meet our leadership related ESG targets.

Litigation and Claims

From time to time, we may be involved in demands, disputes, proceedings, arbitrations and/or litigation (“Claims”) arising out of or related to our operations and other contractual relationships. Claims may be material. Due to the nature of our operations we may be involved with various types of Claims including, but not limited to, failure to comply with applicable laws and regulations including potential claims that we have violated laws related to discrimination and harassment, health and safety, the environment, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, derivative actions, patent infringement, privacy, employment, labour relations, personal injury and other Claims. We may be required to incur substantial expenses or devote significant resources in respect of any such Claims, which could result in unfavourable judgments, decisions, fines, sanctions, monetary damages, temporary or permanent suspensions of operations, or the inability to engage in certain transactions. The outcome of such claims can be difficult to assess or quantify and may have a material adverse effect on our business, reputation, financial condition and results of operations and cash flows. In addition, we may be subject to or impacted by climate change related litigation, including class actions. See “Climate Change Related Litigation” below.

Indigenous Land and Rights Claims

Opposition by Indigenous people to our Company, our operations, development or exploration in the jurisdictions in which we conduct business may adversely impact us. Such impacts include impacts to our reputation, relationship with host governments, local communities and other Indigenous communities, diversion of Management’s time and resources, increased legal, regulatory and other advisory expenses, and could adversely impact our progress and ability to explore, develop and continue to operate properties.

Some Indigenous groups have established or asserted Indigenous rights and may have treaty rights to portions of Canada. There are outstanding Indigenous and treaty rights claims, which may include land title claims, on lands where we operate, and such claims, if successful, could have a material adverse impact on our operations or pace of growth. No certainty exists that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims. Some Indigenous groups have also brought private nuisance claims against project operators for infringement of Indigenous rights. Such claims, if successful, could adversely affect our business, results of operations, financial condition or reputation.

The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect the asserted or proven Indigenous rights or affect treaty rights and, in certain circumstances, accommodate their interests. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of ongoing litigation. The fulfillment of the duty to consult Indigenous people and any associated accommodations may adversely affect our ability to, or increase the timeline to, obtain or renew, permits, leases, licences and other approvals, or to meet the terms and conditions of those approvals.

In addition, the Canadian federal government passed legislation which requires it to take all necessary measures to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). Other Canadian jurisdictions have also introduced or passed similar legislation, or begun considering the principles and objectives of UNDRIP, or may do so in the future. The means and timelines associated with UNDRIP’s implementation by government is ongoing and uncertain; additional processes have been and are expected to continue to be created or legislation amended or introduced associated with project development and operations, further increasing uncertainty with respect to project regulatory approval timelines and requirements.

Governmental Risk

Shifts in government policy by existing administrations or following changes in government in jurisdictions in which we operate or elsewhere can impact our operations and ability to grow our business. Restrictions on fossil fuel-based energy use, cross-border economic activity, and development of new infrastructure can impact our opportunities for continued growth. We are committed to working with all levels of government in the jurisdictions in which we operate to ensure we remain competitive and risks are understood, and mitigation strategies are implemented; however, we cannot guarantee the outcomes of changes in government policy which may adversely affect our business, results of operations, financial condition or reputation.

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Regulatory Risk

The oil and gas industry and refining industry in general and our operations in particular are subject to regulation and intervention under international, federal, provincial, territorial, state, regional and municipal legislation in the countries in which we conduct operations, development or exploration in matters such as, but not limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government fees; production rates; environmental protection; protection of certain species or lands; cumulative effects and/or impacts from all types of industrial development; provincial and federal land and water use designations or management plans; the reduction of GHG and other emissions; the export of crude oil, natural gas and other products; the transportation of crude-by-rail, pipeline or marine transport; generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding or acquisition of exploration, development and production rights, oil sands or other interests; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possibly expropriation or cancellation of contract rights. The petroleum refining sector in the U.S. has been and continues to be subject to intensive environmental regulations, oversight, and enforcement from both federal and state governments. Third-party non-governmental organizations (“NGOs”) and citizen groups can also directly influence environmental regulations and have been active against the U.S. refinery sector for many years. Any changes to the regulatory regime, including the implementation of new regulations or the modification or changed interpretation of existing regulations could impact our existing and planned projects requiring increased capital investment, operating expenses or compliance costs, which could adversely impact our financial condition, results of operations, cash flows and reputation. To mitigate these risks, we have regulatory programs that cover stakeholder engagement, air emissions, water quantity and quality, deep disposal well operations, solid and hazardous waste management, spills, and legacy contamination issues.

Regulatory Approvals

Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that we will be able to obtain and maintain, or obtain and maintain on acceptable conditions, all necessary licenses, permits and other approvals that may be required to carry out certain exploration, development and operating activities on our properties. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder consultation, Indigenous consultation, consensus seeking and collaboration, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; environmental and habitat assessments; and other commitments or obligations. Failure to obtain applicable regulatory approvals or satisfy any conditions on a timely basis or satisfactory terms could result in increased costs, project delays, abandonment and/or restructuring of projects.

Abandonment and Reclamation Cost Risk

We are subject to oil and gas asset abandonment, remediation and reclamation (“A&R”) liabilities for our operations, development and exploration, including those imposed by regulation under federal, provincial, territorial, state, regional and municipal legislation in the jurisdictions in which we conduct operations, development or exploration.

We maintain estimates of our A&R liabilities; however, it is possible that these costs may change materially before decommissioning due to regulatory changes, technological changes, ecological risks, acceleration of decommissioning timelines, and inflation, among other variables. For our Atlantic Canada offshore operations, the present value cost for decommissioning and abandonment of the offshore wells and facilities is estimated based on known regulations, procedures and costs today for undertaking the decommissioning, the majority of which is projected to be incurred in the late 2030s.

In Alberta and Saskatchewan, the A&R liability regimes include orphan well funds that are funded through a levy imposed on licensees, including Cenovus, based on the licensees' proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites. The aggregate value of the A&R liabilities assumed has increased in recent years and will remain at elevated levels until a significant number of orphaned wells are decommissioned utilizing the orphan funds. The Alberta and Saskatchewan regulators may seek additional funding for such liabilities from industry participants, including Cenovus.

The AER has discretion in the consideration of licence eligibility, transfer applications and the requirement to post security or carry out A&R work. Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within their asset bases may be negatively impacted, including our potential counterparties. This may result in future insolvencies and additional orphaned assets. In addition, this may impact our ability to transfer our licences, approvals or permits, and may result in increased costs and delays or require changes to our abandonment of projects and transactions.

We have an ongoing environmental monitoring program of owned and leased retail locations, and former owned or leased retail locations where we have retained environmental liability, and perform remediation where required to comply with contractual and legal obligations. The costs of such remediation depend on a number of uncertain factors such as the extent and type of remediation required. Due to uncertainties inherent in the estimation process, it is possible that existing estimates may need to be revised and that conditions may exist at various retail locations that require future expenditures. Such future costs may not be determinable due to the unknown timing and extent of corrective actions that may be required.

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The impact on our business of any legislative, regulatory or policy decisions relating to the A&R liability regulatory regime in the jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated. Any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows.

Royalty Regimes

Our cash flows may be directly affected by changes to royalty regimes. The governments of the jurisdictions where we have producing assets receive royalties on the production of hydrocarbons from lands in which they respectively own the mineral rights and which we produce under agreement with each respective government. Government regulation of royalties is subject to change for a number of reasons, including, among other things, political factors. In Canada, there are certain provincial mineral taxes payable on hydrocarbon production from lands other than Crown lands. The potential for changes in the royalty and mineral tax regimes applicable in the jurisdictions in which we operate, or changes to how existing royalty regimes are interpreted and applied by the applicable governments, creates uncertainty relating to the ability to accurately estimate future royalty rates or mineral taxes and could have a significant impact on our business, financial condition, results of operations and cash flows. An increase in the royalty rates or mineral taxes in jurisdictions where we have producing assets would reduce our earnings and could make, in the respective jurisdiction, future capital expenditures or existing operations uneconomic and may reduce the value of our associated assets.

Canada-United States-Mexico Agreement (“CUSMA”)

On July 1, 2020, the new CUSMA entered into force, which is known in the United States as the United States-Mexico-Canada Agreement (or “USMCA”), replacing the North American Free Trade Agreement (“NAFTA”). The investor-state dispute settlement provisions that were present within NAFTA will no longer be available in the CUSMA to protect future investments of Canadians in the U.S. or U.S. investments in Canada. For three years after the termination of NAFTA, existing legacy investments will maintain their access to the investor-state dispute settlement under NAFTA Chapter 11. However, starting July 1, 2023, such legacy disputes and disputes related to investments established or acquired on after July 1, 2020 will fall to the appropriate courts in the United States, or Cenovus may seek intervention of the Canadian government to pursue relief through state-to-state dispute resolution.

Labour Risk

We depend on unionized labour for the operation of certain facilities and may be subject to adverse employee relations and labour disputes, which may disrupt operations at such facilities. As of December 31, 2022, approximately 7 percent of our employees are represented by unions under collective bargaining agreements, which includes just over 50 percent of our U.S. workforce. At unionized worksites, there is risk that strikes or work stoppages could occur. Any strike or work stoppage (for any reason, including a health and safety shutdown) may have a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows.

During periods of contract negotiation or in the event of a strike or work stoppage, mitigation and emergency operation plans come with significant additional expenditures to ensure continuity of operations. In addition, we may not be able to renew or renegotiate collective bargaining agreements on satisfactory terms or at all and a failure to do so may increase our costs. Any renegotiation of our existing collective bargaining agreements may result in terms that are less favourable to us, which may materially and adversely affect our financial condition, results of operations and cash flows.

Moreover, employees who are not currently represented by unions may seek union representation in the future and efforts may be made from time to time to unionize other portions of our workforce. Future unionization efforts or changes in legislation and regulations may result in labour shortages, higher labour costs, as well as wage, benefit, and other employment consequences, especially during critical maintenance and construction periods, all of which may increase our costs, reduce our revenues or limit our operational flexibility.

International Developments and Geopolitical Risk

We are exposed to the financial and operational risks associated with uncertain international relations. Our business includes Asia Pacific assets in the South China Sea and the Madura Strait offshore Indonesia, and includes cooperation agreements with China National Offshore Oil Corporation or its subsidiaries (collectively, “CNOOC”), which also operates certain of these assets.

Political developments impacting international trade, including trade disputes, increased tariffs and sanctions, particularly between the U.S. and China and Canada and China, may negatively impact markets and cause weaker macroeconomic conditions or drive political or national sentiment, weakening demand for crude oil, natural gas and refined products. For example, U.S. government trade policy has resulted in, and could result in more, U.S. trading partners adopting responsive trade policy and may make it more difficult or costly for us to operate in and export our products to those countries.

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We may be affected by changes to bilateral relationships, the frameworks and global norms that govern international trade, and other geopolitical developments. This includes acute shocks (such as civil unrest or sanctions) and chronic stresses (such as political or business disputes and other forms of conflict, including military conflict) that may pose longer-term threats to our business. Unilateral action by, or changes in relations between, countries in which we operate, including the U.S. and China, and such countries’ approach to multilateralism and trade protectionism can impact our ability to access markets, technology, talent and capital. Disruptions or unanticipated changes of this nature may affect our ability to sell our products for optimum value or access inputs required for effective operations and has the potential to adversely affect our financial condition.

Increased tensions between the U.S. and China caused by escalated military exercises around Taiwan and the South China Sea could lead to geopolitical uncertainty in the area, which may negatively impact our China business and operations, and ultimately affect our financial condition.

Moreover, our operations may be materially adversely affected by political, economic or social instability or events, including the renegotiation or nullification of agreements and treaties, the imposition of onerous regulations, embargoes, sanctions, and fiscal policy, changes in laws governing existing operations, financial constraints, including currency restrictions and exchange rate fluctuations, unreasonable taxation and the behaviour of international public officials, joint venture partners or third-party representatives. Specifically, our Asia Pacific assets expose us to the effects of the changing U.S.-China, Canada-China and EU-China relations.

In response to foreign sanctions, China has enacted multiple blocking laws intended to diminish the effectiveness and impact of foreign trade sanctions. Specifically, China has enacted regulations granting itself the ability to unilaterally nullify the effects of certain foreign restrictions that are deemed to be unjustified to Chinese nationals and entities, which came into force on January 9, 2021. Additionally, on June 10, 2021, China enacted the Anti-Foreign Sanctions Law. The Anti-Foreign Sanctions Law grants the right to take corresponding countermeasures if a foreign country violates international law and basic norms of international relations or adopts discriminatory restrictive measures against Chinese nationals and entities, and interferes in China's internal affairs. The language of the Anti-Foreign Sanctions Law is very broad, and beyond the laws themselves, little guidance has been provided regarding how the blocking laws will be enforced by the Chinese government and effectuated through the private rights of action created by these laws. The breadth and lack of specificity of such laws create additional risk and uncertainty for foreign companies operating in China, as they may result in conflicting rules and regulations in home and host countries.

Although formal export restrictions imposed against China and Chinese entities (including the placement of CNOOC on the U.S. Department of Commerce’s Entity List) have not so far had a material impact on our business activities in Asia, increased export restrictions on China and Chinese entities may limit the range of certain supplies to our operations in Asia and have an adverse effect on operational efficiency, results of operations, financial condition or reputation.

It is possible that additional related actions taken by the U.S. (and its trading partners and allies), Canada, China and other nations may limit or restrict foreign companies' ability to participate in projects and operate in certain sectors of the Chinese economy, including the energy sector. The nature, extent and magnitude of the effect of dynamic trade relations cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, and results of operations, cash flows, and reputation.

U.S. and Canadian sanctions and trade controls related to China do not currently prevent or significantly impair our offshore operations in Asia, but they could do so in the future, particularly if U.S. sanctions and trade controls against CNOOC were to be expanded. We cannot accurately predict the implementation of U.S. or Canadian policy affecting any current or future activities by CNOOC, Cenovus's other international partners or Cenovus. Similarly, we cannot accurately predict whether U.S. restrictions will be further tightened or the impact of government action on Cenovus's offshore operations in Asia. It is possible that the U.S. or Canadian government may subject CNOOC or Cenovus's other international partners to restrictions or sanctions that may adversely impact our offshore operations in Asia.

In addition, to the extent there are business disputes or legal claims involving our business in China, there is the potential for Cenovus personnel to be subject to an entry/exit ban in China. Moreover, it is possible that, as a result of our partnership with CNOOC, we may be subject to negative media attention which may affect investors’ perception of Cenovus in Canada, the U.S. and globally, and which may negatively affect our share price and reputation.

Geopolitical events, such as a shift in the relationship, an escalation or imposition of sanctions, tariffs or other trade tensions between the U.S. and China and Canada and China, may affect the supply, demand and price of crude oil, natural gas and refined products and therefore our financial condition. The timing, extent and fallout of the ongoing tensions between the U.S. and China, as well as Canada and China remain uncertain and the impact on our business is unknown.

Shifts in global power relations may also introduce greater uncertainty with respect to issues requiring global co-ordination (such as climate change, trade agreements, tax regulation, freedom of navigation and technology regulation), as well as raise questions on the efficacy of and trust in international institutions, including those that underpin international trade. These types of changes may cause restrictions or impose costs on our business and may inhibit our future opportunities or affect our financial condition.

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Our financial condition, operations and business may be adversely affected by any of the foregoing risks associated with international relations and specifically those risks arising from evolving U.S.-China, Canada-China and EU-China relations. The nature, extent and magnitude of the effect of dynamic trade relations on us cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, results of operations, cash flows, and reputation.

The War in Ukraine

Uncertainty regarding the duration and ultimate effects of the Russia – Ukraine war may result in major disruptions in oil and natural gas supply and continuing commodity price volatility. Further, Canada, the U.S. and other countries have imposed significant sanctions on Russia and many Russian officials, agencies, NGOs, companies and individuals some of whom are involved in the energy business or are significant buyers of crude oil or other hydrocarbons. Cenovus does not conduct business with sanctioned entities or persons and has no operations or significant business in Russia, Ukraine or other regions affected by these sanctions. Consequently, these sanctions have not had a material impact on Cenovus or our business. However, the scope and impact of the war, and any related international action, including any future sanctions, cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, results of operations, cash flows, and reputation.

Climate-Related Risks

There is growing international concern regarding climate change and a significant increase in focus on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, NGOs, environmental and governance organizations, institutional investors, social and environmental activists, shareholders, and individuals, are increasingly seeking to implement, among other things, regulatory and policy changes, changes in investment patterns, and modifications in energy consumption habits and trends which, individually and collectively are intended to or have the effect of accelerating the reduction in the global consumption of fossil fuel-based energy, the conversion of energy usage to less carbon-intensive forms and the general migration of energy usage away from fossil fuel-based forms of energy.

Climate change and its associated impacts may increase our exposure to, and magnitude of, each of the risks identified in the Risk Management and Risk Factors section of this MD&A. Overall, we are not able to estimate at this time the degree to which climate change related regulatory, climatic conditions, and climate-related transition risks could impact our business, financial condition, and results of operations. Our business, financial condition, results of operations, cash flows, reputation, access to capital and insurance, cost of borrowing, ability to fund dividend payments and/or business plans may, in particular, without limitation, be adversely impacted as a result of climate change and its associated impacts.

Transition Risks – Policy & Legal

Climate Change Regulation

We operate in several jurisdictions that regulate or have proposed to regulate GHG emissions, often with a view to transitioning to a lower-carbon economy. Some of these regulations are in effect while others remain in various phases of review, discussion or implementation. Uncertainties exist relating to the timing and effects of these emerging regulations and other contemplated legislation, including how they may be harmonized, making it difficult to accurately determine the cost impacts. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time.

The Government of Canada has announced the carbon tax will increase to $170/tonne CO2e by 2030. To reach that level, the price imposed on carbon will rise from the 2022 rate of $50/tonne CO2e by $15/tonne CO2e each year until 2030. To the extent a province's carbon pricing system does not meet the federal stringency requirements, the federal "backstop" regulations apply. Most of our Canadian-based large emitting facilities operate in British Columbia, Alberta, Saskatchewan, or Newfoundland and Labrador where provincial carbon pricing regulations apply. These provincial programs are expected to continue to be deemed equivalent to the federal carbon pricing system.

In July 2022, the Government of Canada released an oil and gas emissions cap discussion document. The government is currently considering the form that any future regulation designed to meet the goals of the emission cap will take. The options proposed in the discussion document are a cap-and-trade system (under the Canadian Environmental Protection Act (“CEPA”) that sets a regulated limit on emissions from the sector or modifying the pollution pricing benchmark requirements to create price-driven limits on emissions from the oil and gas sector. The government is expected to release details on the form of the emissions cap in 2023. The Government has also committed to engaging provinces, territories, and Indigenous organizations in an interim review of the benchmark by 2026 after which, regulatory measures designed to meet the goals of the emissions cap could come into force.

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The Government of Canada has implemented regulation to enable the reduction of methane emissions from the crude oil and natural gas sector by 40 percent to 45 percent from 2012 levels by 2025. Regulatory requirements for fugitive equipment leaks and venting from well completion and compressors came into force on January 1, 2020. Further restrictions on facility production venting restrictions and venting limits for pneumatic equipment came into force on January 1, 2023. Certain provinces have since implemented provincial methane regulations that have been found to be equivalent with federal requirements. The Government of Canada has announced an additional target to reduce oil and gas methane emissions by at least 75 percent below 2012 levels by 2030. In November 2022 the Government of Canada published for comment, a proposed regulatory framework to support their methane emissions reduction target. The proposal includes source by source requirements as well as additional performance-based requirements and is to be regulated under CEPA.

The U.S. does not have federal legislation establishing targets for the reduction of, or setting individualized limits on, GHG emissions from our U.S. facilities. The Renewable Fuel Standard (“RFS”) was created to reduce GHG emissions and risks from that program are described below. Additionally, the federal Environmental Protection Agency (“EPA”) has and may continue to promulgate regulations concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program (“GHGRP”) requires any facility releasing more than 25,000 tonnes of CO2e emissions per year to report those emissions on an annual basis. In addition to reporting direct CO2e emissions, the GHGRP requires refineries to estimate the CO2e emissions from the potential subsequent combustion of the refinery’s products. In early 2021, the U.S. rejoined the Paris Agreement and subsequently announced a 2030 target to reduce GHG emissions by 50 percent to 52 percent from 2005 levels. It is expected that this target will be met largely through clean energy incentives introduced under the Inflation Reduction Act as opposed to regulatory measures.

Negative consequences which could arise as a result of changes to the current regulatory environment include, but are not limited to, changes in environmental and emissions regulation of current and future projects by governmental authorities, which could result in changes to facility design and operating requirements, potentially increasing the cost of construction, operation and abandonment. Other possible effects from emerging regulations may also include but are not limited to: increased compliance costs; permitting delays; and substantial costs to generate or purchase emission credits or allowances, all of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be available on an economic basis, required emissions reductions may not be technically or economically feasible to implement, in whole or in part, and failure to have access to resources or technology to meet emissions reduction requirements or other compliance mechanisms may have a material adverse effect on our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations.

The extent and magnitude of any adverse impacts of current or additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time, in part because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the timeframes for compliance. Consequently, no assurances can be given that the effect of future climate change regulations will not be significant to us.

Low Carbon Fuel Standards

Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian provinces and territories, the Canadian federal government and members of the European Union, regulating carbon fuel standards could result in increased costs and reduced revenue for us. The potential regulation may negatively affect the marketing of our bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to effect sales in such jurisdictions.

Environment and Climate Change Canada published final regulations in 2022 for the Clean Fuel Standard under the Canadian Environmental Protection Act, 1999. The Clean Fuel Standard will replace the current Renewable Fuels Regulations, which requires producers and importers of transportation fuels to acquire a certain number of compliance units commensurate with the volumes of fuel they produce or import. The new regulatory framework will impose lifecycle carbon intensity requirements for certain liquid fuels and establish rules relating to the trading of compliance credits. Carbon intensity requirements under the Clean Fuel Standard regulation become more stringent over time and are differentiated between different types of fuels to reflect the associated emissions reduction potential. Regulated parties have some flexibility with respect to how to achieve lower-carbon fuels in Canada. The cost of compliance will depend on a number of factors including, but not limited to, credit market supply and demand dynamics, development costs associated with low carbon fuels, and technology developments that could reduce demand for liquid transportation fuels. The Clean Fuel Standard regulation has the potential to impact our business, financial condition, results of operations and cash flows, though at this time it is difficult to predict or quantify any such impacts.

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Renewable Fuel Standards

Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. The EPA has implemented the RFS program that mandates that a certain volume of renewable fuel replace or reduce the quantity of certain petroleum-based transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of gasoline or diesel fuel, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into transportation fuel, or by purchasing renewable identification numbers (RINs) from other parties on the open market. RINs are credits used for compliance, and are the “currency” of the RFS program.

Cenovus and our refinery operating partners comply with the RFS by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market, where prices fluctuate. We cannot predict the future prices of RINs and renewable fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. Our financial position, results of operations and cash flows may be materially impacted if we are required to pay significantly higher prices for RINs or blendstocks to comply with the RFS mandated standards. We have an RFS program to help mitigate risk related to fluctuating RINs pricing.

Light-Duty Vehicle Greenhouse Gas Emission Standards

The U.S. EPA has mandated federal GHG emissions standards applicable to automakers by setting fuel economy standards related to passenger cars and light trucks for Model Years 2023 through 2026. The EPA’s stated intention for the rule is to prompt automakers to produce more electric vehicles and set a path to a zero-emissions transportation future. The EPA stated that it intends to initiate future rulemaking to establish multi-pollutant emissions standards for Model Year 2027 and beyond. The impact these standards may have on the future demand (and corresponding price levels) for our products is unknown and dependent upon a number of factors. In addition, the Canadian federal government has published proposed regulated sales targets for electric vehicles. See “Climate Change Transition – Demand and Commodity Prices” below.

Climate Change Related Litigation

In recent years there has been an increase in climate change related demands, disputes, and litigation in various jurisdictions including the U.S. and Canada, asserting various claims, including that energy producers contribute to climate change, that such entities are not reasonably managing business risks associated with climate change, and that such entities have not adequately disclosed business risks of climate change. While many of the climate change related actions are in preliminary stages of litigation, and in some cases assert novel or untested causes of action, there can be no assurance that legal, societal, scientific and political developments will not increase the likelihood of successful climate change related litigation against energy producers, including Cenovus. The outcome of any such litigation is uncertain and may materially impact our business, financial condition or results of operations. We may also be subject to adverse publicity associated with such matters, which may negatively affect public perception and our reputation, regardless of whether we are ultimately found responsible. We may be required to incur significant expenses or devote significant resources in defense against any such litigation.

Transition Risks – Technology

We depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business goals, including our ESG targets. Limitations related to the development, adoption and success of these technologies or the development of disruptive technologies could have a negative impact on our long-term business resilience.

Transition Risks – Market

Demand and Commodity Prices

The recent increase in focus on the timing and pace of the transition to a lower-carbon economy and resulting trends will likely affect global energy demand and usage, including the composition of the types of energy generally used by industry and individual consumers. Under certain aggressive low‑carbon scenarios, potential demand erosion could contribute to commodity price fluctuations and structural commodity price declines. However, it is not currently possible to predict the timelines for, and precise effects of, this transition to a potential lower-carbon economy, which will depend on a multitude of factors including increased decarbonization policies, the ability to develop adequate alternative sources of energy, technology development and adaptation including in the area of transportation electrification, the ability to conceptualize, develop and commercialize technologies for the production, storage and distribution of adequate supplies of alternative energy, consumption patterns, global growth, industrial activity, weather patterns and climate conditions, including as a result of climate change. All of these factors are beyond our control and could result in a high degree of price volatility for each of crude oil, natural gas, NGLs, electricity and refined products.

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Market Access

Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about GHG emissions associated with fossil fuel-based energy development and end‑use combustion of fuels. Additional concerns about pipeline spills can create opposition to pipeline projects at a local level. Our inability to optimize market access for either the delivery of our production or refining feedstock may negatively impact our business, financial condition, cash flows and results of operations.

Access to Capital and Insurance

Capital markets are adjusting to the risks that climate change poses and as a result, our ability to access capital and secure adequate or prudent insurance coverage may also be adversely affected in the event that financial institutions, investors, credit rating agencies, lenders and/or insurers adopt more restrictive decarbonization policies. Certain insurance companies have taken actions or announced policies to limit available coverage for companies which derive some or all of their revenue from the oil sands sector. As a result of these policies, premiums and deductibles for some or all of our insurance policies could increase substantially and/or coverage may be reduced or become unavailable. As a result, we may not be able to renew our existing policies or procure other desirable insurance coverage, either on commercially reasonable terms, or at all. Additionally, certain financial institutions have taken actions or announced policies related to decarbonization of their loan portfolios. As a result, costs of financing could increase over time and we may not be able to refinance our debt, renew or extend credit facilities or procure additional financing at reasonable costs and interest rates, or at all. The future development of our business may be dependent upon our ability to obtain additional capital, including debt and equity financing. See “Credit, Liquidity and Availability of Future Financing” above.

Accuracy of Climate Scenarios and Assumptions

We integrate the potential impact of GHG regulations and the cost of carbon at various price levels into our business planning processes. To mitigate uncertainty surrounding future emissions regulation, we evaluate our development plans under a range of carbon-constrained scenarios. We have considered the International Energy Agency (“IEA”) scenarios in our strategic planning for several years and also conduct ongoing assessments of both public and private scenarios. Although management believes that our climate-related estimates are reasonable, aligned with current, pending and potential future regulations, and informed by the IEA's climate scenarios, they are based on numerous assumptions that, if false, may have a material adverse effect on our business, financial condition and results of operations. Specifically, climate-related estimates influence our financial planning and investment decisions. Since we plan and evaluate opportunities partially on the basis of climate-related estimates, variations between actual outcomes and our expectations may have a material adverse effect on our business, financial condition, results of operations, reputation and cash flows.

Shareholder Activism

Shareholder activism has been increasing in the energy industry, and investors may from time to time attempt to effect changes to our business, governance, or reporting practices with respect to climate change or otherwise, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our Board and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of our business. In the event such activist shareholders are successful, Cenovus may be required to incur costs and dedicate time to adopting new practices. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in significant fluctuation in the market price of our securities.

Transition Risks – Reputation and Public Perception of the Oil and Gas Sector

Development of fossil fuel-based energy, and in particular the Alberta oil sands, has received considerable attention on the subjects of environmental impact, climate change, GHG emissions and Indigenous reconciliation. Concerns about oil sands may, directly or indirectly, impair the profitability of our current oil sands projects, and the viability of future oil sands projects, by creating significant regulatory, economic and operating uncertainty. Increased public opposition to and stigmatization of the oil and gas sector, and in particular the oil sands industry, could lead to constrained access to insurance, liquidity and capital and changes in demand for our products, which may adversely impact our business, financial condition or results of operations.

For example, legislation or policies that limit the purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or foreign jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in stranded assets or an inability to further develop oil resources. See “Reputation Risk” below.

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Climate Change – Physical Risks

Systemic climatic changes or extreme climatic conditions may also have material adverse effects on our business, reputation, financial condition, results of operations and cash flows. Weather and climate affect demand, and therefore, the predictability of the demand for energy is affected to a large degree by the predictability of weather and climate. In addition, our exploration, refining, pipeline, production and construction operations, and the operations of major customers and suppliers, can be affected by acute physical climate risks, such as floods, forest fires, earthquakes, hurricanes, storms, extreme temperatures and other extreme weather events or natural disasters. This may result in cessation or diminishment of production or throughput, delay of exploration and development activities or delay of plant construction.

Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations, business and financial results. For example, our Atlantic operations may be impacted by severe weather conditions, including winds, flooding and variable temperatures, which are contributing to the melting of northern ice and increased creation of icebergs. Icebergs off the coast of Newfoundland and Labrador pose a risk to Atlantic oil production facilities. An operational incident as a result of severe weather conditions, has the potential to result in spills, asset damage, and production or refining disruption. Climate change may result in an increased level of risk resulting in increased or additional mitigation requirements.

Our other operations are also subject to chronic physical risks such as a shorter timeframe for our winter drilling program, changes in the water table and reduced access to water due to drought conditions. A systemic change in temperature or precipitation patterns could result in more challenging conditions for the construction of ice roads, execution of our winter drilling program and reclamation activities and could reduce the availability of water due to the increasing likelihood of drought conditions.

Environmental Regulation Risks

All phases of our operations are subject to environmental regulation pursuant to a variety of federal, provincial, territorial, state, regional and municipal laws, and regulations in the jurisdictions in which we operate (collectively, the “environmental regulations”). Environmental regulations provide that exploration areas, wells, facility sites, refineries and other properties and practices associated with our operations be constructed, operated, maintained, abandoned, reclaimed, and undertaken in accordance with the requirements set out therein. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications.

We anticipate that further changes in environmental legislation will occur, which may result in approval delays for critical licences and permits, stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, increased compliance costs and increased costs for closure, controls on land and resource access, reclamation, and ecological restoration. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to our business.

Compliance with environmental regulations requires significant expenditures. Our future capital expenditures and operating expenses could continue to increase as a result of, among other things, developments in our business, operations, plans and objectives and changes to existing, or implementation of new, environmental regulations. Failure to comply with environmental regulations may result in, among other things, the imposition of fines, penalties, environmental protection orders, suspension of operations, prosecution, and could adversely affect our reputation. The costs of complying with environmental regulations and remedying noncompliance issues may have a material adverse effect on our business, financial condition, results of operations and cash flows. The implementation of new environmental regulations or changes in interpretation or the modification of existing environmental regulations affecting the crude oil, natural gas, NGL and refining industry generally could reduce demand for our products as well as shift hydrocarbon demand toward relatively lower-carbon sources and affect our long-term prospects.

U.S. environmental regulations and aggressive enforcement from regulators present challenges and risks to our U.S. operations. New emission standards, more stringent water quality standards, and regulation of emerging contaminants such as Per- and Polyfluoroalkyl Substances ("PFAS") can increase compliance costs, require capital projects, lengthen project implementation times, and have an adverse effect on our business, financial condition, results of operations and cash flows. U.S. regulators have proposed that certain PFAS be characterized as a regulatory defined hazardous waste, which could lead to additional cleanup liability at U.S. sites. See “Water Regulation” below.

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Canadian Species at Risk Act

The Canadian federal Species at Risk Act, as well as provincial regulation regarding threatened or endangered species and their habitat may limit the pace and the amount of development or activity in areas identified as critical habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal government in relation to their obligations under the Species at Risk Act have raised issues associated with the protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, a suite of initiatives has been undertaken to support caribou recovery, including the conservation agreements under the Species at Risk Act and the elaboration of sub-regional plans. If plans and actions undertaken by the provinces are deemed insufficient to support caribou recovery, the federal legislation includes the ability to implement measures that would preclude further development or modification of existing operations. The extent and magnitude of any potential adverse impacts of legislation on in situ oil sands project development and operations cannot be estimated, as uncertainty exists as to whether plans and actions undertaken by the provinces will be sufficient to support caribou recovery.

Canadian Federal Air Quality Management System

The Multi Sector Air Pollutants Regulations (“MSAPR”), issued under the Canadian Environmental Protection Act, 1999, seek to protect the environment and health of Canadians by setting mandatory, nationally consistent air pollutant emission standards. The MSAPR are aimed at equipment-specific Base-Level Industrial Emissions Requirements (“BLIERs”). Nitrogen oxide BLIERs from our non-utility boilers, heaters and stationary engines are regulated in accordance with specified performance standards. We anticipate that the MSAPR will result in adverse impacts to Cenovus including but not limited to capital investment required to retrofit existing equipment and increased operating costs.

Canadian Ambient Air Quality Standards (“CAAQS”) for nitrogen dioxide, sulphur dioxide, fine particulate matter and ozone were introduced as part of a national Air Quality Management System. Provinces may implement the CAAQS at the regional air zone level and air zone management actions may include more stringent emissions standards applicable to industrial sources from approval holders in regions where we operate that may result in adverse impacts including but not limited to capital investment related to retrofitting existing facilities and increased operating costs.

Review of Environmental and Regulatory Processes

Increased environmental assessment obligations imposed by federal, provincial, territorial, state and municipal governments in the jurisdictions in which we conduct operations, development or exploration may create risk of increased costs and project development delays. The regulatory frameworks within the jurisdictions where we operate are constantly evolving and changing and may become more onerous or costly which may impede our ability to economically develop our resources. The extent and magnitude of any adverse impacts of changes to the regulatory framework on project development and operations cannot be estimated at this time.

The Impact Assessment Agency of Canada leads and coordinates federal impact assessments for all designated projects within Canada. Assessment considerations beyond the environment expressly include health, economic, social, and gender impacts, as well as considerations related to sustainability and Canada’s climate change commitments. For as long as the Alberta provincial government maintains the cap on oil sands emissions in Alberta and the cap has not been reached, our in-situ oil sands projects should be exempted from the application of the federal impact assessment system, provided a number of additional conditions are met. However, other types of projects would undergo a federal assessment, including those within our Atlantic operations.

Water Regulation

We utilize fresh water in certain operations, which is obtained under licenses issued within each respective jurisdiction’s regulations. If water use fees increase, the terms of the licences change or there are reductions in the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial condition. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. There is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted on favourable terms. This may adversely affect our business, including the ability to operate our assets and execute development plans.

Our U.S. refineries are subject to water discharge requirements that necessitate treatment of wastewater prior to discharging. Permits for discharging water are renewed from time to time to incorporate new water quality standards and may require modifications and expansion of water treatment facilities at the sites. Pollutants such as selenium, total dissolved solids, arsenic, mercury, and others may require advanced wastewater treatment, and discharge levels will depend on the types of crude processed at our refineries. Non-compliance with permit limits can lead to enforcement actions by regulators including issuance of fines, orders to upgrade treatment plants, and suspension of operations. Federal and state regulators in the U.S. are currently addressing the emerging pollutant PFAS in water discharge permits by requiring installation of additional wastewater treatment units and requiring monitoring of PFAS in discharges.

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Hydraulic Fracturing

Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and suggest that additional federal, provincial, territorial, state, regional and/or municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

In addition, some areas of British Columbia and Alberta have experienced increased localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been correlated with hydraulic fracturing in conjunction with horizontal drilling techniques in Western Canada, which has prompted legislative and regulatory initiatives intended to address these concerns.

New laws, regulations or permitting requirements regarding hydraulic fracturing may lead to limitations or restrictions to oil and gas development activities, operational delays, increased compliance costs, additional operating requirements, or increased third-party or governmental claims resulting in increased cost of doing business as well as impacting the amount of natural gas and oil that we are ultimately able to produce from our reserves.

Cenovus ESG Focus Areas, Targets and Ambitions

We have set ambitious, achievable targets for each of our five ESG focus areas, as discussed below, including reducing our absolute emissions, decreasing freshwater intensity, reclaiming more land, supporting Indigenous reconciliation and increasing the number of women in leadership positions. To achieve these goals and to respond to changing market demand, we may incur additional costs and invest in new technologies and innovation. It is possible that the return on these investments may be less than we expect, which may have an adverse effect on our business, financial condition and reputation.

Generally, our ESG targets and ambitions depend significantly on our ability to execute our current business strategy, which can be impacted by the numerous risks and uncertainties associated with our business and the industry in which we operate, as outlined in the Risk Management and Risk Factors section of this MD&A. We recognize that our ability to adapt to and succeed in a lower-carbon economy will be compared against our peers. Investors and stakeholders increasingly compare companies based on ESG-related performance, including climate-related performance. Failure to achieve our ESG targets and ambitions, or a perception among key stakeholders that our ESG targets and ambitions are insufficient or unattainable, could adversely affect our reputation and our ability to attract capital and insurance coverage.

There is also a risk that some or all of the expected benefits and opportunities of achieving the various ESG targets and ambitions may fail to materialize, may cost more to achieve or may not occur within the anticipated time periods. In addition, there are risks that the actions we take in implementing targets and ambitions relating to our ESG focus areas may have a negative impact on our existing business and increase capital expenditures, which could have a negative impact on our future operating and financial results.

Climate and GHG Emissions Target and Ambition

We have set a target to reduce our absolute scope 1 and 2 GHG emissions by 35 percent by year-end 2035 from 2019 levels and have a long‑term ambition to achieve net zero emissions from our operations by 2050. Our ability to meet our 2035 GHG reduction target and 2050 net zero ambition are subject to numerous risks and uncertainties and our actions taken in implementing such target and ambition may also expose us to certain additional and/or heightened financial and operational risks. Furthermore, our long-term ambition of reaching net zero emissions by 2050 is inherently less certain due to the longer timeframe and certain factors outside of our control, including the commercial application of future technologies that may be necessary for us to achieve this long-term ambition.

A reduction in GHG emissions relies on, among other things, our ability to develop, access and implement commercially viable and scalable emission reduction strategies and related technology and products. In addition, there are other operational risks that may hinder our ability to successfully meet our GHG emission targets and goals, including: unexpected impediments to, or effects of, the implementation of methane abatement and electrification initiatives in our Conventional segment; the purchase of renewable electricity; the unavailability of, or limited benefits from, technology that is expected to be commercially viable in the near term and its associated future benefits, including SAGD enhancement technologies, such as solvent-aided process and solvent-driven process technologies, carbon capture, utilization and storage technology and downhole technology improvements; and a failure to capture the anticipated benefits of continued technological development, and industry collaboration and innovation to find solutions to reduce costs and GHG emissions. If we are unable to implement these strategies and technologies as planned without negatively impacting our expected operations or cost structure, or such strategies or technologies do not perform as expected, we may be unable to meet our 2035 GHG reduction target or 2050 net zero emissions ambition on the planned timelines, or at all.

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In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework, support from government, financial or otherwise, and will require capital expenditures and company resources, with the potential that actual costs may differ from our original estimates and the differences may be material. Furthermore, the cost of investing in emissions-reduction technologies, and the resultant change in the deployment of resources and focus, could have a negative impact on our business, financial condition, results of operations and cash flows.

Water Stewardship Targets

Our ability to reduce freshwater intensity by 20 percent in oil sands and in thermal operations from 2019 levels by year-end 2030 or maintain such improvements will depend on the commercial viability and scalability of relevant water reduction strategies and related steam and water usage technology and products. There are risks associated with relying largely or partly on new technologies, the incorporation of such technologies into new or existing operations and acceptance of new technologies in the market. In the event we are unable to effectively and efficiently deploy the necessary technology, or such strategies or technologies do not perform as expected, achieving our stated target of reducing our water intensity could be interrupted, delayed or abandoned.

Biodiversity Targets

Our biodiversity targets include the goal to reclaim 3,000 decommissioned well sites by year-end 2025 and to restore more habitat than we use within the Cold Lake caribou range by year-end 2030. Our ability to meet these targets is subject to various environmental and regulatory risks, which could impose significant costs, restrictions, liabilities, and obligations on us. See “Abandonment and Reclamation Cost Risk” above. In addition, an increase in operating costs, changes to market conditions and access to additional capital, if needed, could result in our inability to fund, and ultimately meet, our biodiversity targets on the current timelines, or at all.

Indigenous Reconciliation Targets

Our Indigenous reconciliation targets to spend a minimum of $1.2 billion with Indigenous owned or operated businesses between 2019 and year-end 2025 and attain Progressive Aboriginal Relations gold certification from the Canadian Council for Aboriginal Business by year-end 2025 are subject to a number of financial, operational and efficiency risks relating to actions taken in implementing such targets.

In addition, a failure or delay in achieving our Indigenous reconciliation targets may adversely affect our relationship with neighboring Indigenous businesses and communities and our broader reputation. If we are unable to maintain a positive relationship with Indigenous communities near our operations, our progress and ability to develop and operate properties in line with our current business and operational strategies may be adversely impacted.

Inclusion and Diversity Targets

Our inclusion and diversity focus area includes a target of women in leadership roles of at least 30 percent by year-end 2030 as well as an aspiration for our Board to have at least 40 percent representation from women, Indigenous peoples, persons with disabilities and members of visible minorities among non-management directors. Efforts to meet and maintain such targets may increase the time and costs associated with appointing and replacing key personnel. Further, an inability to hire or promote qualified candidates or a failure or delay in achieving our targets may influence our reputation with our stakeholders, attract litigation and impact recruitment initiatives. There are also risks associated with the collection of certain personal data in furtherance of these targets.

Reputation Risk

We rely on our reputation to build and maintain positive relationships with investors and other stakeholders, to recruit and retain staff, and to be a credible, trusted company. Any actions we take that influence public or key stakeholder opinions have the potential to impact our reputation, which may adversely affect our share price, development plans and ability to continue operations. There is increasing opposition from climate change activist organizations and the public towards oil and gas operations. See “Transition Risks – Reputation and Public Perception of the Oil and Gas Sector” above.

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Other Risks

Dilutive Effect

We are authorized to issue, among other classes of shares, an unlimited number of common shares for consideration and on terms and conditions as established by our Board without the approval of our shareholders in certain instances. Any future issuances of Cenovus common shares or other securities exercisable or convertible into, or exchangeable for, Cenovus common shares may result in dilution to present and prospective Cenovus shareholders. The issuance of additional Cenovus common shares upon exercise, from time to time, of securities convertible into Cenovus common shares will have a further dilutive effect on the ownership interest of shareholders of Cenovus. Such issuances will have a dilutive effect on Cenovus's earnings per share, which could adversely affect the market price of Cenovus common shares and may adversely impact the value of our shareholders' investments.

It is also expected that, from time to time, we will grant additional equity awards to our employees and directors under our compensation plans. These additional equity awards will have a further dilutive effect on our earnings per share, which could also negatively affect the market price of Cenovus common shares and may adversely impact the value of our shareholders' investments.

Risks Relating to Acquisitions

We have completed, and may complete in the future, one or more acquisitions for various strategic reasons. Our ability to achieve the benefits of any acquisition will depend upon the actions of our counterparties; our ability, and the ability of our counterparties, to obtain the necessary shareholder, regulatory and third-party approvals, as applicable, and satisfy all conditions to closing; the risks inherent in the operation of the assets being acquired prior or subsequent to closing; the effectiveness of our diligence investigations; the physical condition of the assets upon closing; our ability to obtain indemnities and/or fund ongoing maintenance, repair and operation costs of the assets acquired; our ability to assess the integrity and reliability of the assets being acquired; our ability to successfully consolidate functions and integrate operations, procedures and personnel in a timely and efficient manner and to realize the anticipated growth opportunities and synergies from combining the acquired assets and operations with our existing assets and operations. The integration of acquired assets and operations requires the dedication of management effort, time and resources, which may divert management's focus and resources from other strategic opportunities and from operational matters during the process. The integration process may result in the disruption of ongoing business and customer relationships that may adversely affect our ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires the assessment of their characteristics, including, among other things, estimated recoverable reserves, future production and throughput, commodity prices, revenues, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain and, as such, the acquired properties may not produce as expected, may not have the anticipated reserves and may be subject to increased costs and liabilities. Although the acquired assets are reviewed prior to completion of an acquisition, such reviews are not capable of identifying all existing or potentially adverse conditions. This risk may be magnified where the acquired assets are in geographic areas where we have not historically operated. Further, we may not be able to obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition and we may be required to assume the risk of the physical condition of the properties that may not perform in accordance with its expectations or require repair or other expenditures, the scope of which may be uncertain, result in increased costs and affect our ability, and timeline, to realize the benefits of the acquisition.

Risks Relating to Dispositions

We have completed, and may complete in the future, one or more dispositions for various strategic reasons. Various factors could materially affect our ability to dispose of assets in the future, including stock exchange, regulatory, third-party and corporate approvals, counterparties' ability to fulfill their obligations under agreements to affect dispositions, commodity prices, the availability of purchasers willing to purchase certain assets at prices and on terms acceptable to us, associated asset retirement obligations, due diligence, favourable market conditions, and the assignability of joint venture, partnership or other arrangements. These factors may also reduce the proceeds or value to our business. We may also retain certain liabilities for or agree to indemnification obligations in a sale transaction. The magnitude of any such retained liabilities or indemnification obligations may be difficult to quantify at the time of the transaction and could ultimately be material. Further, certain third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after the sale of certain assets, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the purchaser of the assets fails to perform its obligations. Should any of the risk associated with dispositions materialize, it could have an adverse effect on our business, financial condition or reputation.

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Risks Related to Significant Shareholders of Cenovus

As of December 31, 2022, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F. Investments") owned 16.6 percent and 12.1 percent of our common shares, respectively. The sale into the market of Cenovus common shares held by either Hutchison or L.F. Investments, whether through open market trades on the TSX or NYSE, through privately arranged block trades or pursuant to prospectus offerings made in accordance with the respective registration rights agreement that each of Hutchison and L.F. Investments has entered into with Cenovus, or market perception regarding Hutchison’s or L.F. Investments’ intention to sell Cenovus common shares, could adversely affect market prices for our common shares. While Hutchison and L.F. Investments are each subject to certain voting covenants pursuant to the terms of a standstill agreement they each entered into with Cenovus, each of Hutchison and L.F. Investments may be able to impact certain matters requiring Cenovus shareholder approval.

Market for Cenovus Warrants

There can be no assurance that an active public market for Cenovus Warrants will be sustained. If such a market is sustained, the market price of the Cenovus Warrants may be adversely affected by a variety of factors relating to Cenovus's business, including, but not limited to, fluctuations in our operating and financial results, the results of any public announcements made by us and our failure to meet analysts' expectations. In addition, the market price of the Cenovus common shares will significantly affect the market price of the Cenovus Warrants. This may result in significant volatility in the market price of the Cenovus Warrants and may negatively impact the value of the Cenovus Warrants.

Contingent Payments Payable relating to Sunrise Acquisition

In connection with the Sunrise Acquisition, we agreed to make contingent payments to BP Canada under certain circumstances. The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the two-year period following the closing of the Sunrise Acquisition (August 31, 2022), and such payments are cumulatively capped at $600 million. This payment may be material in any given reporting period as the entire maximum payment could be reached in a single quarter and could have an adverse impact on our results of operations and financial condition.

Tax Laws

Income tax laws and regulations and other laws and government incentive programs may in the future be changed or interpreted in a manner that adversely affects us, our financial results and our shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s detriment or to the detriment of our shareholders. In addition, all of our tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and our shareholders.

The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration related to the Base Erosion and Profit Shifting (“BEPS”) project of the Organisation for Economic Co-operation and Development (“OECD”). Although the timing and methods of implementation vary, numerous countries including Canada have responded to the BEPS project by implementing, or proposing to implement, changes to tax laws and tax treaties at a rapid pace. These changes may increase our cost of tax compliance and affect our business, financial condition and results of operations in a manner that is difficult to quantify. We will continue to monitor and assess potential adverse impacts on our global tax situation as a result of the BEPS project.

In Canada, in the 2022 Fall Economic Statement released by the Department of Finance, a new tax on share buybacks by public corporations was proposed. Under the proposal, which would come into force on January 1, 2024, a two percent corporate-level tax would apply on the "net value" of all types of shares buybacks by public corporations in Canada. While there are few details available on the proposed tax, we will continue to monitor and assess any potential adverse impacts as more information becomes available.

A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business, prospects, financial condition, results of operations and cash flows, and in some cases our reputation, can be found in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and at cenovus.com.

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CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, as well as use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements.

Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.

Joint Arrangements

The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in the following jointly controlled entities:

•WRB Refining LP (“WRB”).

•BP-Husky Refining LLC (“Toledo”).

It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB and Toledo. As a result, the joint arrangements are classified as joint operations and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

Prior to August 31, 2022, Cenovus held a 50 percent interest in Sunrise, which was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls Sunrise, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, Sunrise was consolidated.

In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company considered the following:

•The original intention of the joint arrangements was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.

•The agreements require the partners to make contributions if funds are insufficient to meet the obligations or liabilities of the corporation and partnerships. The past development of Sunrise, and the past and future development of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.

•WRB has third-party debt facilities to cover short-term working capital requirements. Up until November 2022, Sunrise also had third-party debt facilities.

•Sunrise was operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants in accordance with the partnership agreement. WRB and Toledo have very similar structures modified to account for the operating environment of the refining business.

•Cenovus, Phillips 66 and BP, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangements do not have employees and, as such, are not capable of performing these roles.

•In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

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Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and impairment reversals.

Recoveries from Insurance Claims

The Company uses estimates and assumptions on the amount recorded for insurance proceeds that are reasonably certain to be received. Accordingly, actual results may differ from these estimated recoveries.

Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

The evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could change assumptions used to determine the recoverable amount of the Company’s PP&E and E&E assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects, may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built into our estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for energy.

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands, Conventional and Offshore segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Recoverable amounts for the Company’s manufacturing assets, crude-by-rail terminal and related ROU assets use assumptions such as throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Recoverable amounts for the Company’s real estate ROU assets use assumptions such as real estate market conditions which includes market vacancy rates and sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

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Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of liabilities and estimate the future value. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired, liabilities assumed and assets given up in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparable transactions and discounted cash flows. For the Company’s upstream assets, key assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves and resources for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.

Income Tax Provisions

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.

Changes in Accounting Policies

There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2022.

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business.

CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at December 31, 2022. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2022.

The effectiveness of our ICFR was audited as at December 31, 2022 by PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2022.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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ADVISORY

Oil and Gas Information

Barrels of Oil Equivalent – natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

Forward-looking Information

This document contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

This forward-looking information is identified by words such as “anticipate”, “believe”, “capacity”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”, “potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond, including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend; allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the Company’s targets for each of its five ESG focus areas; Free Funds Flow generation, allocation, pay out and growth through commodity pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow; reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near-term cash requirements and meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net Debt targets; disciplined capital allocation; ensuring sufficient liquidity through all stages of the economic cycle; strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments; managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost savings; cost structures and market optimization; interest expense; improving efficiencies to drive incremental capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing condensate costs associated with heavy oil transportation; maintaining the Company’s capital program and sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil differentials; partially mitigating the impact of exposure to various prices for commodities and associated price differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities (including WTI, utilized in condensate and price risk management for refining operations) and products, including associated price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment; initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending, drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital investment, including for: portfolio adjustments, the impact of inflation, maintaining safe and reliable operations, sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil therefrom; the return to the field of the floating, production, storage and offloading unit for the Terra Nova ALE project and the resumption of production; first gas production from the MAC and MDK fields; drilling development wells and construction of production facilities and production therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the impact of commodity differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and the effects thereof on Cenovus.

Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied.

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Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast oil and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits and anticipated cost synergies of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and throughput volumes and timing thereof; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change), Indigenous relations, interest rates, inflation, foreign exchange rates, competitive conditions and the supply and demand for crude oil and natural gas, NGLs, condensate and refined products; the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company’s share price and market capitalization over the long term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue and fund future investments, sustainability and development plans and dividends, including any increase thereto; production from the Company’s Conventional segment providing an economic hedge for the natural gas required as a fuel source at both the Company’s oil sands and refining operations; realization of expected capacity to store within the Company’s oil sands reservoirs barrels not yet produced, including that the Company will be able to time production and sales of our inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and future crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to global supply factors and heavy crude processing capacity; the ability of the Company’s refining capacity, dynamic storage, existing pipeline commitments, crude-by-rail loading capacity and financial hedge transactions to partially mitigate a portion of the Company’s WCS crude oil volumes against wider differentials; the Company’s ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company’s ability to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability to complete acquisitions and dispositions, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; alignment of realized WCS and WCS prices used to calculate the variable payment to BP Canada; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2023 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.

2023 guidance, as updated December 5, 2022, and available on cenovus.com, assumes: Brent prices of US$83.00 per barrel, WTI prices of US$77.00 per barrel; WCS of US$54.50 per barrel; Differential WTI-WCS of US$22.50 per barrel; AECO natural gas prices of $4.85 per thousand cubic feet; Chicago 3-2-1 crack spread of US$26.50 per barrel; and an exchange rate of $0.75 US$/C$.

The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the effect of the COVID-19 pandemic, including any variants thereof, on the Company’s business, including any related restrictions, containment, and treatment measures taken by varying levels of government in the jurisdictions in which the Company operates; the success of the Company’s COVID-19 workplace policies; the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and dispositions; the Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; the development and execution of implementing strategies to meet climate and GHG emissions targets and ambitions; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; foreign exchange risk, including related to agreements denominated in foreign currencies; the Company’s continued liquidity is sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential will remain largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and

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crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to recalculate the variable payment to BP Canada; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events resulting in operational interruptions, including at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics or pandemics, and catastrophic events, including, but not limited to, war, adverse sea conditions, extreme weather events, natural disasters, acts of activism, vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s business, including potential cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and the Company’s ability to attract and retain, critical and diverse talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets, commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors in this MD&A, and the risk factors described in other documents the Company files from time to time with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Company’s website at cenovus.com.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  74

Information on or connected to the Company’s website at cenovus.com does not form part of this MD&A unless expressly incorporated by reference herein.

ABBREVIATIONS AND DEFINITIONS

The following abbreviations and definitions have been used in this document:

Crude Oil		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
Mbbls/d	thousand barrels per day	MMcf	million cubic feet
MMbbls	million barrels	MMcf/d	million cubic feet per day
BOE	barrel of oil equivalent	Bcf	billion cubic feet
MBOE	thousand barrels of oil equivalent	MMBtu	million British thermal units
MBOE/d	thousand barrels of oil equivalent per day	GJ	gigajoule
MMBOE	million barrels of oil equivalent	AECO	Alberta Energy Company
WTI	West Texas Intermediate	NYMEX	New York Mercantile Exchange
WCS	Western Canadian Select	SAGD	steam-assisted gravity drainage
HSB	Husky Synthetic Blend
OPEC	Organization of Petroleum Exporting Countries
OPEC+	OPEC and a group of 10 non-OPEC members
FPSO	Floating production storage and offloading unit

Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets.

Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling for use at the owned or operated facility.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  75

SPECIFIED FINANCIAL MEASURES

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS including Operating Margin, Operating Margin for the Upstream or Downstream operations, Operating Margin by asset, Total Arrangement Integration Costs, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Gross Margin, Refining Margin, Unit Operating Expense, Per Unit DD&A and Netbacks (including the total netbacks per BOE).

These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation, if applicable, of each specified financial measure is presented in this Advisory and may also be presented in the Operating and Financial Results or Liquidity and Capital Resources sections of this MD&A.

Operating Margin

Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for the Upstream or Downstream segment are specified financial measures. These are used to provide a consistent measure of the cash generating performance of our operations and assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.

	Upstream			Downstream			Total
($ millions)	2022	2021 (1)	2020	2022	2021 (2)	2020	2022	2021 (1) (2)	2020
Revenues
Gross Sales	41,127	27,844	9,708	38,102	26,258	4,815	79,229	54,102	14,523
Less: Royalties	4,868	2,454	371	—	—	—	4,868	2,454	371
	36,259	25,390	9,337	38,102	26,258	4,815	74,361	51,648	14,152
Expenses
Purchased Product	6,833	4,059	1,530	32,501	23,111	4,429	39,334	27,170	5,959
Transportation and Blending	12,194	8,714	4,764	—	—	—	12,194	8,714	4,764
Operating	3,789	3,241	1,476	3,050	2,258	785	6,839	5,499	2,261
Realized (Gain) Loss on Risk Management	1,619	788	268	112	104	(21)	1,731	892	247
Operating Margin	11,824	8,588	1,299	2,439	785	(378)	14,263	9,373	921

	2022
	Upstream				Downstream				Total
	Three Months Ended				Three Months Ended				Three Months Ended
($ millions)	Q4	Q3	Q2	Q1 (1)	Q4	Q3 (2)	Q2 (2)	Q1 (2)	Q4	Q3 (2)	Q2 (2)	Q1 (1) (2)
Revenues
Gross Sales	8,307	10,238	11,685	10,897	8,380	10,887	10,719	8,116	16,687	21,125	22,404	19,013
Less: Royalties	875	1,226	1,582	1,185	—	—	—	—	875	1,226	1,582	1,185
	7,432	9,012	10,103	9,712	8,380	10,887	10,719	8,116	15,812	19,899	20,822	17,828
Expenses
Purchased Product	1,157	2,397	1,461	1,818	7,071	9,694	8,919	6,817	8,228	12,091	10,380	8,635
Transportation and Blending	2,962	2,800	3,238	3,194	—	—	—	—	2,962	2,800	3,238	3,194
Operating	955	915	1,010	909	759	780	866	645	1,714	1,695	1,876	1,554
Realized (Gain) Loss on Risk Management	134	51	563	871	(8)	(77)	87	110	126	(26)	650	981
Operating Margin	2,224	2,849	3,831	2,920	558	490	847	544	2,782	3,339	4,678	3,464

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

(2)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  76

	2021
	Upstream (1)				Downstream (2)				Total (1) (2)
	Three Months Ended				Three Months Ended				Three Months Ended
($ millions)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Revenues
Gross Sales (1)	8,237	7,354	6,128	6,125	8,010	7,422	6,226	4,600	16,247	14,776	12,354	10,725
Less: Royalties	815	733	533	373	—	—	—	—	815	733	533	373
	7,422	6,621	5,595	5,752	8,010	7,422	6,226	4,600	15,432	14,043	11,821	10,352
Expenses
Purchased Product (1)	1,198	1,074	717	1,070	7,223	6,600	5,410	3,878	8,421	7,674	6,127	4,948
Transportation and Blending (1)	2,599	2,137	2,006	1,972	—	—	—	—	2,599	2,137	2,006	1,972
Operating	865	800	791	785	689	537	515	517	1,554	1,337	1,306	1,302
Realized (Gain) Loss on Risk Management	202	168	188	230	56	17	10	21	258	185	198	251
Operating Margin	2,558	2,442	1,893	1,695	42	268	291	184	2,600	2,710	2,184	1,879

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

(2)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin.

Operating Margin by Asset

	Three Months Ended December 31, 2022			Year Ended December 31, 2022
($ millions)	Asia Pacific	Atlantic	Offshore (1)	Asia Pacific	Atlantic	Offshore (2)
Revenues
Gross Sales	359	86	445	1,442	578	2,020
Less: Royalties	20	1	21	80	(3)	77
	339	85	424	1,362	581	1,943
Expenses
Transportation and Blending	—	3	3	—	15	15
Operating	26	58	84	114	204	318
Operating Margin	313	24	337	1,248	362	1,610

(1)Found in Note 1 of the interim Consolidated Financial Statements.

(2)Found in Note 1 of the Consolidated Financial Statements.

	Three Months Ended December 31, 2021			Year Ended December 31, 2021
($ millions)	Asia Pacific	Atlantic	Offshore (1)	Asia Pacific	Atlantic	Offshore (2)
Revenues
Gross Sales	377	143	520	1,342	440	1,782
Less: Royalties	26	8	34	79	29	108
	351	135	486	1,263	411	1,674
Expenses
Transportation and Blending	—	5	5	—	15	15
Operating	29	44	73	103	136	239
Operating Margin	322	86	408	1,160	260	1,420

(1)Found in Note 1 of the interim Consolidated Financial Statements.

(2)Found in Note 1 of the Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  77

Total Arrangement Integration Costs

Total Arrangement Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the Arrangement, excluding share issuance costs.

	Year Ended December 31,
($ millions)	2022	2021
Integration Costs (1)	90	349
Capitalized Integration Costs (2)	5	53
Total Arrangement Integration Costs	95	402

(1)See Note 8 of the Consolidated Financial Statements.

(2)Included in capital expenditures on the Consolidated Statements of Cash Flows.

Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow

Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as cash from (used in) operating activities excluding settlement of decommissioning liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable and accrued revenues, inventories (excluding non-cash inventory write-downs and reversals), income tax receivable, accounts payable and accrued liabilities and income tax payable. Adjusted Funds Flow Per Share – Basic is defined as Adjusted Funds Flow divided by the basic weighted average number of shares. Adjusted Funds Flow Per Share – Diluted is defined as Adjusted Funds Flow divided by the diluted weighted average number of shares.

Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities excluding settlement of decommissioning liabilities and net change in non-cash working capital minus capital investment.

Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns and capital allocation framework. Excess Free Funds Flow is defined as Free Funds Flow minus base dividends paid on common shares, dividends paid on preferred shares, other uses of cash (including settlement of decommissioning liabilities and principal repayment of leases), and acquisition costs, plus proceeds from or payments related to divestitures. Excess Free Funds Flow was a new metric as of June 30, 2022.

	2022				2021
($ millions)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Cash From (Used in) Operating Activities	2,970	4,089	2,979	1,365	2,184	2,138	1,369	228
(Add) Deduct:
Settlement of Decommissioning Liabilities	(49)	(55)	(27)	(19)	(35)	(38)	(18)	(11)
Net Change in Non-Cash Working Capital	673	1,193	(92)	(1,199)	271	(166)	(430)	(902)
Adjusted Funds Flow	2,346	2,951	3,098	2,583	1,948	2,342	1,817	1,141
Capital Investment	1,274	866	822	746	835	647	534	547
Free Funds Flow	1,072	2,085	2,276	1,837	1,113	1,695	1,283	594
Add (Deduct):
Base Dividends Paid on Common Shares	(201)	(205)	(207)	(69)	(70)	(35)	(36)	(35)
Dividends Paid on Preferred Shares	—	(9)	(8)	(9)	(8)	(9)	(8)	(9)
Settlement of Decommissioning Liabilities	(49)	(55)	(27)	(19)	(35)	(38)	(18)	(11)
Principal Repayment of Leases	(74)	(78)	(75)	(75)	(78)	(70)	(77)	(75)
Acquisitions, Net of Cash Acquired	(7)	(389)	(1)	—	—	—	—	(7)
Proceeds From Divestitures	45	407	112	950	247	83	100	5
Payment on Divestiture of Assets	—	—	(50)	—	—	—	—	—
Excess Free Funds Flow	786	1,756	2,020	2,615	1,169	1,626	1,244	462

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  78

	Year Ended December 31,
($ millions)	2022	2021	2020
Cash From (Used in) Operating Activities	11,403	5,919	273
(Add) Deduct:
Settlement of Decommissioning Liabilities	(150)	(102)	(42)
Net Change in Non-Cash Working Capital	575	(1,227)	198
Adjusted Funds Flow	10,978	7,248	117
Capital Investment	3,708	2,563	841
Free Funds Flow	7,270	4,685	(724)

Gross Margin, Refining Margin and Unit Operating Expense

Gross Margin and Refining Margin are non-GAAP financial measures, or contain a non-GAAP financial measure, used to evaluate the performance of our downstream operations. We define Gross Margin as revenues less purchased product. We define Refining Margin as Gross Margin divided by barrels of crude oil throughput. Unit Operating Expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. We define Unit Operating Expense as operating expenses divided by barrels of crude oil throughput in our downstream operations.

Canadian Manufacturing

	Three Months Ended December 31, 2022
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Manufacturing (2)
Revenues	905	240	1,145	627	1,772
Purchased Product	574	170	744	580	1,324
Gross Margin	331	70	401	47	448
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Throughput (Mbbls/d)	68.4	25.9	94.3
Refining Margin ($/bbl)	52.60	29.36	46.21

	Three Months Ended September 30, 2022 (3)(4)
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Manufacturing (2)
Revenues	999	387	1,386	782	2,168
Purchased Product	747	286	1,033	714	1,747
Gross Margin	252	101	353	68	421
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Throughput (Mbbls/d)	71.3	27.2	98.5
Refining Margin ($/bbl)	38.33	40.33	38.88

(1)Includes ethanol operations, crude-by-rail operations and the commercial fuels business.

(2)These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.

(3)Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.

(4)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  79

	Three Months Ended June 30, 2022 (1)
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (2)	Total Canadian Manufacturing (3) (4)
Revenues	1,162	243	1,405	840	2,245
Purchased Product	1,012	210	1,222	760	1,982
Gross Margin	150	33	183	80	263
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Throughput (Mbbls/d)	64.6	16.3	80.9
Refining Margin ($/bbl)	25.54	22.22	24.87

	Three Months Ended March 31, 2022 (1)
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (2)	Total Canadian Manufacturing (3) (4)
Revenues	756	186	942	665	1,607
Purchased Product	585	143	728	605	1,333
Gross Margin	171	43	214	60	274
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Throughput (Mbbls/d)	70.7	27.4	98.1
Refining Margin ($/bbl)	26.98	17.33	24.28

	Year Ended December 31, 2022
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (2)	Total Canadian Manufacturing (3)
Revenues	3,822	1,056	4,878	2,914	7,792
Purchased Product	2,918	809	3,727	2,662	6,389
Gross Margin	904	247	1,151	252	1,403
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Throughput (Mbbls/d)	68.7	24.2	92.9
Refining Margin ($/bbl)	36.04	27.91	33.92

(1)Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.

(2)Includes ethanol operations, crude-by-rail operations and the commercial fuels business.

(3)These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.

(4)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  80

	Three Months Ended December 31, 2021 (1)
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (2)	Total Canadian Manufacturing (3) (4)
Revenues	1,044	205	1,249	607	1,856
Purchased Product	887	172	1,059	529	1,588
Gross Margin	157	33	190	78	268
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Throughput (Mbbls/d)	80.4	27.9	108.3
Refining Margin ($/bbl)	21.26	12.77	19.07

	Year Ended December 31, 2021 (1)
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (2)	Total Canadian Manufacturing (3) (4)
Revenues	3,245	816	4,061	2,154	6,215
Purchased Product	2,698	659	3,357	1,799	5,156
Gross Margin	547	157	704	355	1,059
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Throughput (Mbbls/d)	79.0	27.5	106.5
Refining Margin ($/bbl)	18.96	15.60	18.09

(1)Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.

(2)Includes ethanol operations, crude-by-rail operations and the commercial fuels business.

(3)These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.

(4)Prior period results have been re-presented.In September 2022, the Company divested the majority of the retail fuels business.The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  81

U.S. Manufacturing

	Three Months Ended December 31,
($ millions)	2022	2021
Revenues (1)	6,608	6,154
Purchased Product (1)	5,747	5,635
Gross Margin	861	519
Crude Oil Throughput (Mbbls/d)	379.2	361.6
Refining Margin ($/bbl)	24.70	15.63

(1)Found in Note 1 of the interim Consolidated Financial Statements.

	Year Ended December 31,
($ millions)	2022	2021	2020
Revenues (1)	30,310	20,043	4,733
Purchased Product (1)	26,112	17,955	4,429
Gross Margin	4,198	2,088	304
Crude Oil Throughput (Mbbls/d)	400.8	401.5	185.9
Refining Margin ($/bbl)	28.70	14.25	4.47

(1)Found in Note 1 of the Consolidated Financial Statements.

Per Unit DD&A

Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis. We define Per Unit DD&A as DD&A divided by sales volumes.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  82

Netback Reconciliations

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance and is also presented on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending and operating expenses, and netback per BOE is divided by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold and exclude risk management activities. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with crude oil to transport it to market.

The following tables provide a reconciliation of the items comprising Netbacks, and Netbacks per BOE to Operating Margin found in our interim Consolidated Financial Statements.

Total Production

Upstream Financial Results

		Adjustments					Basis of Netback Calculation
Three Months Ended December 31, 2022 ($ millions)	Total Upstream (1)	Condensate	Third-Party Sourced	Internal Consumption (2)	Equity Adjustment (3)	Other (4)	Total Upstream
Gross Sales	8,307	(2,415)	(1,063)	(349)	77	(123)	4,434
Royalties	875	—	—	—	27	(1)	901
Purchased Product	1,157	—	(1,063)	—	—	(94)	—
Transportation and Blending	2,962	(2,415)	—	—	—	(4)	543
Operating	955	—	—	(349)	15	(11)	610
Netback	2,358	—	—	—	35	(13)	2,380
Realized (Gain) Loss on Risk Management	134	—	—	—	—	—	134
Operating Margin	2,224	—	—	—	35	(13)	2,246

		Adjustments					Basis of Netback Calculation
Three Months Ended December 31, 2021 ($ millions)	Total Upstream (1)	Condensate	Third-Party Sourced	Internal Consumption (2)	Equity Adjustment (3)	Other (4)	Total Upstream
Gross Sales (5)	8,237	(2,201)	(1,079)	(241)	62	(146)	4,632
Royalties	815	—	—	—	29	—	844
Purchased Product (5)	1,198	—	(1,079)	—	—	(119)	—
Transportation and Blending	2,599	(2,201)	—	—	—	—	398
Operating	865	—	(8)	(241)	7	(3)	620
Netback	2,760	—	8	—	26	(24)	2,770
Realized (Gain) Loss on Risk Management	202	—	—	—	—	—	202
Operating Margin	2,558	—	8	—	26	(24)	2,568

(1)These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.

(2)Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.

(3)Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.

(4)Other includes construction, transportation and blending and third-party processing margin.

(5)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  83

		Adjustments					Basis of Netback Calculation
Year Ended December 31, 2022 ($ millions)	Total Upstream (1)	Condensate	Third-Party Sourced	Internal Consumption (2)	Equity Adjustment (3)	Other (4)	Total Upstream
Gross Sales	41,127	(10,307)	(6,524)	(1,170)	271	(429)	22,968
Royalties	4,868	—	—	—	116	(12)	4,972
Purchased Product	6,833	—	(6,524)	—	—	(309)	—
Transportation and Blending	12,194	(10,307)	—	—	—	(39)	1,848
Operating	3,789	—	—	(1,170)	36	(39)	2,616
Netback	13,443	—	—	—	119	(30)	13,532
Realized (Gain) Loss on Risk Management	1,619	—	(8)	—	—	—	1,611
Operating Margin	11,824	—	8	—	119	(30)	11,921

		Adjustments					Basis of Netback Calculation
Year Ended December 31, 2021 ($ millions)	Total Upstream (1)	Condensate	Third-Party Sourced	Internal Consumption (2)	Equity Adjustment (3)	Other (4)	Total Upstream
Gross Sales (5)	27,844	(7,095)	(3,761)	(710)	224	(390)	16,112
Royalties	2,454	—	—	—	52	—	2,506
Purchased Product (5)	4,059	—	(3,761)	—	—	(298)	—
Transportation and Blending	8,714	(7,095)	—	—	—	—	1,619
Operating	3,241	—	(8)	(710)	25	(36)	2,512
Netback	9,376	—	8	—	147	(56)	9,475
Realized (Gain) Loss on Risk Management	788	—	(2)	—	—	—	786
Operating Margin	8,588	—	10	—	147	(56)	8,689

		Adjustments					Basis of Netback Calculation
Year Ended December 31, 2020 ($ millions)	Total Upstream (1)	Condensate	Third-Party Sourced	Internal Consumption (2)	Equity Adjustment (3)	Other (4)	Total Upstream
Gross Sales (5)	9,708	(3,452)	(1,559)	—	(295)	(58)	4,344
Royalties	371	—	—	(1)	—	—	370
Purchased Product (5)	1,530	—	(1,559)	—	—	29	—
Transportation and Blending	4,764	(3,452)	—	1	—	—	1,313
Operating	1,476	—	—	—	(295)	(72)	1,109
Netback	1,567	—	—	—	—	(15)	1,552
Realized (Gain) Loss on Risk Management	268	—	—	—	—	—	268
Operating Margin	1,299	—	—	—	—	(15)	1,284

(1)These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.

(2)Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.

(3)Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.

(4)Other includes construction, transportation and blending and third-party processing margin.

(5)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  84

Oil Sands

	Basis of Netback Calculation
Three Months Ended December 31, 2022 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	1,282	1,453	222	745	3,702	4	3,706
Royalties	338	344	13	88	783	1	784
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	255	157	42	39	493	—	493
Operating	194	221	60	257	732	3	735
Netback	495	731	107	361	1,694	—	1,694
Realized (Gain) Loss on Risk Management							59
Operating Margin							1,635

	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2022 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	3,706		2,415	500	110	6,731
Royalties	784		—	—	—	784
Purchased Product	—		—	500	94	594
Transportation and Blending	493		2,415	—	14	2,922
Operating	735		—	—	(2)	733
Netback	1,694		—	—	4	1,698
Realized (Gain) Loss on Risk Management	59		—	—	—	59
Operating Margin	1,635		—	—	4	1,639

	Basis of Netback Calculation
Three Months Ended December 31, 2021 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	1,304	1,441	189	903	3,837	4	3,841
Royalties	280	345	7	102	734	—	734
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	166	140	28	42	376	—	376
Operating	184	194	39	230	647	6	653
Netback	674	762	115	529	2,080	(2)	2,078
Realized (Gain) Loss on Risk Management							202
Operating Margin							1,876

	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2021 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales (4)	3,841		2,201	537	138	6,717
Royalties	734		—	—	—	734
Purchased Product (4)	—		—	537	119	656
Transportation and Blending	376		2,201	—	—	2,577
Operating	653		—	—	5	658
Netback	2,078		—	—	14	2,092
Realized (Gain) Loss on Risk Management	202		—	—	—	202
Operating Margin	1,876		—	—	14	1,890

	Basis of Netback Calculation
Year Ended December 31, 2022 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	6,723	7,951	950	3,967	19,591	18	19,609
Royalties	1,783	2,244	59	390	4,476	6	4,482
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	814	588	135	149	1,686	—	1,686
Operating	870	898	193	960	2,921	20	2,941
Netback	3,256	4,221	563	2,468	10,508	(8)	10,500
Realized (Gain) Loss on Risk Management							1,527
Operating Margin							8,973

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.

(2)Other includes construction, transportation and blending margin.

(3)These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.

(4)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  85

	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2022 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	19,609		10,307	4,501	358	34,775
Royalties	4,482		—	—	11	4,493
Purchased Product	—		—	4,501	309	4,810
Transportation and Blending	1,686		10,307	—	43	12,036
Operating	2,941		—	—	(11)	2,930
Netback	10,500		—	—	6	10,506
Realized (Gain) Loss on Risk Management	1,527		—	—	—	1,527
Operating Margin	8,973		—	—	6	8,979

	Basis of Netback Calculation
Year Ended December 31, 2021 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	4,341	5,115	616	3,212	13,284	13	13,297
Royalties	767	1,078	20	330	2,195	1	2,196
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	686	526	111	207	1,530	—	1,530
Operating	701	700	157	858	2,416	21	2,437
Netback	2,187	2,811	328	1,817	7,143	(9)	7,134
Realized (Gain) Loss on Risk Management							786
Operating Margin							6,348

	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2021 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales (4)	13,297		7,095	2,106	329	22,827
Royalties	2,196		—	—	—	2,196
Purchased Product (4)	—		—	2,106	298	2,404
Transportation and Blending	1,530		7,095	—	—	8,625
Operating	2,437		—	—	14	2,451
Netback	7,134		—	—	17	7,151
Realized (Gain) Loss on Risk Management	786		—	—	—	786
Operating Margin	6,348		—	—	17	6,365

	Basis of Netback Calculation
Year Ended December 31, 2020 ($ millions)		Foster Creek	Christina Lake	Total Oil Sands
Gross Sales		1,859	2,194	4,053
Royalties		95	235	330
Purchased Product		—	—	—
Transportation and Blending		667	565	1,232
Operating		558	551	1,109
Netback		539	843	1,382
Realized (Gain) Loss on Risk Management				268
Operating Margin				1,114

	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2020 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Inventory Write-down (5)	Other (2)	Total Oil Sands (3)
Gross Sales (4)	4,053		3,452	1,290	—	9	8,804
Royalties	330		—	—	1	—	331
Purchased Product (4)	—		—	1,290	—	(28)	1,262
Transportation and Blending	1,232		3,452	—	(1)	—	4,683
Operating	1,109		—	—	—	47	1,156
Netback	1,382		—	—	—	(10)	1,372
Realized (Gain) Loss on Risk Management	268		—	—	—	—	268
Operating Margin	1,114		—	—	—	(10)	1,104

(1)Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.

(2)Other includes construction, transportation and blending margin.

(3)These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.

(4)Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details.

(5)Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  86

Conventional

	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2022 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	555	563	13	1,131
Royalties	69	—	1	70
Purchased Product	—	563	—	563
Transportation and Blending	47	—	(10)	37
Operating	135	—	3	138
Netback	304	—	19	323
Realized (Gain) Loss on Risk Management	75	—	—	75
Operating Margin	229	—	19	248

	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2021 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	450	542	8	1,000
Royalties	47	—	—	47
Purchased Product	—	542	—	542
Transportation and Blending	17	—	—	17
Operating	128	8	(2)	134
Netback	258	(8)	10	260
Realized (Gain) Loss on Risk Management	—	—	—	—
Operating Margin	258	(8)	10	260

	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2022 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	2,238	2,023	71	4,332
Royalties	297	—	1	298
Purchased Product	—	2,023	—	2,023
Transportation and Blending	147	—	(4)	143
Operating	520	—	21	541
Netback	1,274	—	53	1,327
Realized (Gain) Loss on Risk Management	84	8	—	92
Operating Margin	1,190	(8)	53	1,235

	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2021 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	1,519	1,655	61	3,235
Royalties	150	—	—	150
Purchased Product	—	1,655	—	1,655
Transportation and Blending	74	—	—	74
Operating	521	8	22	551
Netback	774	(8)	39	805
Realized (Gain) Loss on Risk Management	—	2	—	2
Operating Margin	774	(10)	39	803

	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2020 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	586	269	49	904
Royalties	40	—	—	40
Purchased Product	—	269	(1)	268
Transportation and Blending	81	—	—	81
Operating	295	—	25	320
Netback	170	—	25	195
Realized (Gain) Loss on Risk Management	—	—	—	—
Operating Margin	170	—	25	195

(1)Reflects Operating Margin from processing facilities.

(2)These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  87

Offshore

	Basis of Netback Calculation					Adjustments
Three Months Ended December 31, 2022 ($ millions)	China	Indonesia (1)	Asia Pacific	Atlantic	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	359	77	436	86	522	(77)	—	445
Royalties	20	27	47	1	48	(27)	—	21
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	—	—	—	3	3	—	—	3
Operating	24	17	41	48	89	(15)	10	84
Netback	315	33	348	34	382	(35)	(10)	337
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					382	(35)	(10)	337

	Basis of Netback Calculation					Adjustment
Three Months Ended December 31, 2021 ($ millions)	China	Indonesia (1)	Asia Pacific	Atlantic	Total Offshore	Equity Adjustment (1)	Total Offshore (3)
Gross Sales	377	62	439	143	582	(62)	520
Royalties	26	29	55	8	63	(29)	34
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	—	—	—	5	5	—	5
Operating	23	12	35	45	80	(7)	73
Netback	328	21	349	85	434	(26)	408
Realized (Gain) Loss on Risk Management					—	—	—
Operating Margin					434	(26)	408

	Basis of Netback Calculation					Adjustments
Year Ended December 31, 2022 ($ millions)	China	Indonesia (1)	Asia Pacific	Atlantic	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	1,442	271	1,713	578	2,291	(271)	—	2,020
Royalties	80	116	196	(3)	193	(116)	—	77
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	—	—	—	15	15	—	—	15
Operating	99	51	150	175	325	(36)	29	318
Netback	1,263	104	1,367	391	1,758	(119)	(29)	1,610
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					1,758	(119)	(29)	1,610

	Basis of Netback Calculation					Adjustment
Year Ended December 31, 2021 ($ millions)	China	Indonesia (1)	Asia Pacific	Atlantic	Total Offshore	Equity Adjustment (1)	Total Offshore (2)
Gross Sales	1,342	224	1,566	440	2,006	(224)	1,782
Royalties	79	52	131	29	160	(52)	108
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	—	—	—	15	15	—	15
Operating	94	33	127	137	264	(25)	239
Netback	1,169	139	1,308	259	1,567	(147)	1,420
Realized (Gain) Loss on Risk Management					—	—	—
Operating Margin					1,567	(147)	1,420

(1)Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.

(2)Relates to costs in the Atlantic.

(3)These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  88

Sales Volumes (1)

The following table provides the sales volumes used to calculate Netback:

	Three Months Ended December 31,		Year Ended December 31,
(MBOE/d)	2022	2021	2022	2021	2020
Oil Sands
Foster Creek	184.7	194.5	189.4	178.8	164.9
Christina Lake	246.5	239.1	247.5	232.7	221.7
Sunrise (2)	42.0	29.9	30.2	25.2	—
Other Oil Sands	118.5	141.2	118.7	143.2	—
Total Oil Sands (2)	591.7	604.7	585.8	579.9	386.6
Conventional	125.5	125.3	127.2	133.4	89.8
Sales before Internal Consumption	717.2	730.0	713.0	713.3	476.4
Less: Internal Consumption (3)	(93.4)	(88.8)	(86.6)	(86.0)	(55.9)
Sales after Internal Consumption	623.8	641.2	626.4	627.3	420.5
Offshore
Asia Pacific - China	47.1	52.7	48.2	50.8	—
Asia Pacific - Indonesia	12.8	9.8	10.5	9.5	—
Asia Pacific - Total	59.9	62.5	58.7	60.3	—
Atlantic	7.3	15.0	11.3	13.2	—
Total Offshore	67.2	77.5	70.0	73.5	—
Total Sales	691.0	718.7	696.4	700.8	420.5

(1)Presented on dry bitumen basis.

(2)Sunrise sales volumes have been re-presented to reflect a change in classification of marketing activities for the first and second quarters of 2021.

(3)Less natural gas volumes used for internal consumption by the Oil Sands segment.

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  89

Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures

Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands, Canadian Manufacturing, historical Retail and Corporate and Eliminations segments were revised.

During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows. Refer to the interim Consolidated Financial Statements for the periods ended June 30, 2022, for further details.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows. Refer to the Consolidated Financial Statements for further details.

The following tables reconcile the amounts previously reported in the interim Consolidated Statements of Earnings (Loss) for the respective period or the December 31, 2021 Consolidated Financial Statements, to the corresponding revised amounts:

	Three Months Ended March 31, 2022				Three Months Ended June 30, 2022				Three Months Ended September 30, 2022
($ millions)	Previously Reported	Revision	Revised		Previously Reported	Revision	Revised		Previously Reported	Revision	Revised
Oil Sands Segment
Purchased Product	1,483	(271)	1,212
Transportation and Blending	2,885	271	3,156
	4,368	—	4,368
Canadian Manufacturing Segment
Gross Sales	1,044	563	1,607		1,521	724	2,245		1,478	690	2,168
Purchased Product	806	529	1,335		1,294	686	1,980		1,095	655	1,750
Operating Expenses	124	27	151		180	31	211		134	38	172
Depreciation, Depletion and    Amortization	42	8	50		64	8	72		37	5	42
	72	(1)	71		(17)	(1)	(18)		212	(8)	204
Retail Segment
Gross Sales	694	(694)	—		849	(849)	—		881	(881)	—
Purchased Product	660	(660)	—		811	(811)	—		846	(846)	—
Operating Expenses	27	(27)	—		31	(31)	—		38	(38)	—
Depreciation, Depletion and    Amortization	8	(8)	—		8	(8)	—		5	(5)	—
	(1)	1	—		(1)	1	—		(8)	8	—
Corporate and Eliminations Segment
Gross Sales	(1,761)	131	(1,630)		(1,782)	125	(1,657)		(2,619)	191	(2,428)
Purchased Product	(1,497)	346	(1,151)		(1,111)	125	(986)		(2,267)	191	(2,076)
Transportation and Blending	(6)	(215)	(221)		(188)	—	(188)		(119)	—	(119)
	(258)	—	(258)	—	(483)	—	(483)	—	(233)	—	(233)
Consolidated
Gross Sales	17,383	—	17,383		20,747	—	20,747		18,697	—	18,697
Purchased Product	7,538	(56)	7,482		9,396	—	9,396		10,012	—	10,012
Transportation and Blending	2,919	56	2,975		3,048	—	3,048		2,684	—	2,684
Operating Expenses	1,287	—	1,287		1,481	—	1,481		1,439	—	1,439
Depreciation, Depletion and    Amortization	1,030	—	1,030		1,132	—	1,132		1,047	—	1,047
	4,609	—	4,609	—	5,690	—	5,690	—	3,515	—	3,515

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  90

	Three Months Ended March 31, 2021				Three Months Ended June 30, 2021				Three Months Ended September 30, 2021				Three Months Ended December 31, 2021				Year Ended December 31, 2021
($ millions)	Previously Reported	Revision	Revised		Previously Reported	Revision	Revised		Previously Reported	Revision	Revised		Previously Reported	Revision	Revised		Previously Reported	Revision	Revised
Oil Sands Segment
Purchased Product	861	(172)	689		634	(204)	430		825	(196)	629		868	(212)	656		3,188	(784)	2,404
Transportation and Blending	1,778	172	1,950		1,780	204	1,984		1,918	196	2,114		2,365	212	2,577		7,841	784	8,625
	2,639	—	2,639		2,414	—	2,414		2,743	—	2,743		3,233	—	3,233		11,029	—	11,029
Canadian Manufacturing Segment
Gross Sales	806	357	1,163		1,088	409	1,497		1,215	484	1,699		1,363	493	1,856		4,472	1,743	6,215
Purchased Product	631	327	958		807	374	1,181		986	443	1,429		1,128	460	1,588		3,552	1,604	5,156
Operating Expenses	93	19	112		92	29	121		99	25	124		104	25	129		388	98	486
Depreciation, Depletion and    Amortization	43	12	55		43	13	56		41	11	52		40	23	63		167	59	226
	39	(1)	38		146	(7)	139		89	5	94		91	(15)	76		365	(18)	347
Retail Segment
Gross Sales	447	(447)	—		501	(501)	—		592	(592)	—		618	(618)	—		2,158	(2,158)	—
Purchased Product	417	(417)	—		466	(466)	—		551	(551)	—		585	(585)	—		2,019	(2,019)	—
Operating Expenses	19	(19)	—		29	(29)	—		25	(25)	—		25	(25)	—		98	(98)	—
Depreciation, Depletion and    Amortization	12	(12)	—		13	(13)	—		11	(11)	—		23	(23)	—		59	(59)	—
	(1)	1	—		(7)	7	—		5	(5)	—		(15)	15	—		(18)	18	—
Corporate and Eliminations Segment
Gross Sales	(1,149)	90	(1,059)		(1,276)	92	(1,184)		(1,450)	108	(1,342)		(1,831)	125	(1,706)		(5,706)	415	(5,291)
Purchased Product	(973)	228	(745)		(1,110)	238	(872)		(1,244)	261	(983)		(1,561)	317	(1,244)		(4,888)	1,044	(3,844)
Transportation and Blending	(15)	(138)	(153)		(6)	(146)	(152)		(18)	(153)	(171)		(8)	(192)	(200)		(47)	(629)	(676)
	(161)	—	(161)	—	(160)	—	(160)	—	(188)	—	(188)	—	(262)	—	(262)	—	(771)	—	(771)
Consolidated
Gross Sales	9,666	—	9,666		11,170	—	11,170		13,434	—	13,434		14,541	—	14,541		48,811	—	48,811
Purchased Product	4,237	(34)	4,203		5,313	(58)	5,255		6,734	(43)	6,691		7,197	(20)	7,177		23,481	(155)	23,326
Transportation and Blending	1,785	34	1,819		1,796	58	1,854		1,923	43	1,966		2,379	20	2,399		7,883	155	8,038
Operating Expenses	1,134	—	1,134		1,144	—	1,144		1,150	—	1,150		1,288	—	1,288		4,716	—	4,716
Depreciation, Depletion and    Amortization	1,045	—	1,045		1,036	—	1,036		1,153	—	1,153		2,652	—	2,652		5,886	—	5,886
	1,465	—	1,465	—	1,881	—	1,881	—	2,474	—	2,474	—	1,025	—	1,025	—	6,845	—	6,845

Cenovus Energy Inc. – 2022 Management's Discussion and Analysis  91

EX-99.3

Exhibit 99.3

Cenovus Energy Inc.

Consolidated Financial Statements

For the Year Ended December 31, 2022

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2022

TABLE OF CONTENTS

REPORT OF MANAGEMENT	3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	4
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)	8
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	9
CONSOLIDATED BALANCE SHEETS	10
CONSOLIDATED STATEMENTS OF EQUITY	11
CONSOLIDATED STATEMENTS OF CASH FLOWS	12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	13
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES	13
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE	20
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	20
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY	30
5. ACQUISITIONS	33
6. GENERAL AND ADMINISTRATIVE	36
7. FINANCE COSTS	36
8. INTEGRATION AND TRANSACTION COSTS	36
9. FOREIGN EXCHANGE (GAIN) LOSS, NET	36
10. DIVESTITURES	37
11. IMPAIRMENT CHARGES AND REVERSALS	37
12. OTHER (INCOME) LOSS, NET	43
13. INCOME TAXES	43
14. PER SHARE AMOUNTS	46
15. CASH AND CASH EQUIVALENTS	47
16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES	47
17. INVENTORIES	47
18. ASSETS HELD FOR SALE	47
19. EXPLORATION AND EVALUATION ASSETS, NET	48
20. PROPERTY, PLANT AND EQUIPMENT, NET	49
21. RIGHT-OF-USE ASSETS, NET	50
22. JOINT ARRANGEMENTS	51
23. OTHER ASSETS	52
24. GOODWILL	52
25. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES	53
26. DEBT AND CAPITAL STRUCTURE	53
27. LEASE LIABILITIES	57
28. CONTINGENT PAYMENTS	58
29. DECOMMISSIONING LIABILITIES	59
30. OTHER LIABILITIES	60
31. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS	60
32. SHARE CAPITAL AND WARRANTS	64
33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	66
34. STOCK-BASED COMPENSATION PLANS	66
35. EMPLOYEE SALARIES AND BENEFIT EXPENSES	70
36. RELATED PARTY TRANSACTIONS	70
37. FINANCIAL INSTRUMENTS	70
38. RISK MANAGEMENT	73
39. SUPPLEMENTARY CASH FLOW INFORMATION	76
40. COMMITMENTS AND CONTINGENCIES	79

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 2

REPORT OF MANAGEMENT

Management’s Responsibility for the Consolidated Financial Statements

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Management’s best judgments.

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of five independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee met with Management and the independent auditors on at least a quarterly basis to review and recommend the approval of the interim Consolidated Financial Statements and Management’s Discussion and Analysis to the Board of Directors prior to their public release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors.

Management’s Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2022. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2022.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2022, as stated in their Report of Independent Registered Public Accounting Firm dated February 15, 2023. PricewaterhouseCoopers LLP has provided such opinions.

/s/ Alexander J. Pourbaix	/s/ Jeffrey R. Hart
Alexander J. Pourbaix	Jeffrey R. Hart
President & Chief Executive Officer	Executive Vice-President & Chief Financial Officer
Cenovus Energy Inc.	Cenovus Energy Inc.
February 15, 2023

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Cenovus Energy Inc.

Opinions on the Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. and its subsidiaries (together, the Company) as of December 31, 2022 and 2021, and the related consolidated statements of earnings (loss), comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the Consolidated Financial Statements). We also have audited the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's Management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Assessment of Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by Management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 4

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the Consolidated Financial Statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the Consolidated Financial Statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the Consolidated Financial Statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Valuation of an Oil Sands Property Related to the Acquisition of the Remaining 50 Percent Interest in the Sunrise Oil Sands Partnership

As described in Notes 3, 4, and 5 to the Consolidated Financial Statements, on August 31, 2022, the Company acquired the remaining 50 percent interest in the Sunrise Oil Sands Partnership (SOSP), a joint operation in the Oil Sands segment in an acquisition accounted for as a business combination using the acquisition method, which requires that assets acquired and liabilities assumed be measured at fair value on the acquisition date, with any excess of the purchase price over the estimated fair value of the net assets acquired recorded as goodwill. As the Company acquired control of SOSP in stages, Management remeasured the previously held interest in SOSP to fair value of $1.6 billion at the acquisition date and total consideration for the newly acquired 50 percent interest was $1.0 billion. The assets acquired included an oil sands property categorized as Property, Plant and Equipment (PP&E), which was valued at $3.2 billion on a 100 percent basis. Management estimated the fair value of the acquired oil sands property at the acquisition date using an after-tax discounted cash flow model. The fair value assessment required the use of significant estimates and judgments by Management including assumptions related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate. Management’s estimate of reserves for the acquired oil sands property were developed by Management’s specialists, including internal geology and engineering professionals, and independent qualified reserves evaluators.

The principal considerations for our determination that performing procedures relating to the valuation of the oil sands property related to the acquisition of the remaining 50 percent interest in SOSP is a critical audit matter are (i) the significant judgment by Management, including the use of Management’s specialists, as applicable, in developing the fair value of the acquired oil sands property; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in the discounted cash flow model used to value the acquired oil sands property related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimated fair value of the acquired oil sands property. These procedures also included, among others, testing Management’s process for determining the fair value of the acquired oil sands property, which included (i) evaluating the appropriateness of the method used by Management in making this estimate; (ii) testing the completeness and accuracy of underlying data used in Management’s determination of the fair value and (iii) evaluating the reasonableness of significant assumptions used by Management related to forward commodity prices, expected production volumes, estimated reserves and future development and operating expenditures for the acquired oil sands property. Evaluating the significant assumptions used by Management involved assessing whether the assumptions used were reasonable considering the current and past performance of the acquired oil sands property and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimated reserves used to determine the fair value of the acquired oil sands property. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the method and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 5

Evaluating the significant assumptions used by Management’s specialists also involved assessing whether the assumptions used were reasonable considering the current and past performance of the acquired oil sands property and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the fair value of the acquired oil sands property determined by Management, including the discount rate.

Assessment of Impairment/Impairment Reversal of PP&E for Each of the Cash Generating Units (CGUs) in the U.S. Manufacturing Segment (the U.S. Manufacturing CGUs)

As described in Notes 1, 3, 4, 11 and 20 to the Consolidated Financial Statements, Management assesses its CGUs for indicators of impairment/impairment reversal on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated Depreciation, Depletion and Amortization (DD&A) including net impairment losses, may exceed its recoverable amount or that a previously recorded impairment may have reversed. If indicators of impairment or impairment reversal exist, the recoverable amount of the CGU is estimated as the greater of value-in-use and fair value less costs of disposal (FVLCOD). In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the CGU in prior periods. As of December 31, 2022, the Company had $4.5 billion of PP&E assets net of accumulated DD&A including net impairment losses relating to its U.S. Manufacturing segment. Management identified indicators of impairment for the Superior and Toledo CGUs and performed impairment assessments for each of these CGUs as of December 31, 2022. The carrying amounts of these CGUs were determined to be greater than their recoverable amounts and an aggregate impairment charge of $1.5 billion was recorded as additional DD&A. Management also identified indicators of impairment reversal for the Wood River, Borger and Lima CGUs and performed impairment assessments for each CGU as of December 31, 2022. The recoverable amounts of these CGU’s were determined to be greater than their carrying amounts and an aggregate impairment reversal of $1.2 billion was recorded as a reduction to DD&A. Management determined the recoverable amounts of PP&E for the U.S. Manufacturing CGUs based on their FVLCOD using discounted after-tax cash flows models requiring the use of significant assumptions and judgments by Management related to throughput, forward crude oil prices, forward crack spreads, future operating costs, future capital expenditures and discount rates.

The principal considerations for our determination that performing procedures relating to the assessment of impairment/impairment reversal of PP&E for each of the CGUs in the U.S. Manufacturing segment is a critical audit matter are (i) the significant amount of judgment required by Management when developing the recoverable amounts of the U.S. Manufacturing CGUs; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in developing these estimates including throughput, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s determination of the recoverable amounts of the U.S. Manufacturing CGUs. These procedures also included, among others, testing Management’s process for determining the recoverable amounts of the U.S. Manufacturing CGUs, which included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in these models; and (iii) assessing the reasonability of the significant assumptions used by Management, including throughput, forward crude oil prices, forward crack spreads, future capital expenditures and future operating costs. Evaluating the assumptions used by Management involved assessing whether the assumptions used were reasonable considering the current and past performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the recoverable amounts of the U.S. Manufacturing CGUs, including the discount rates.

Impact of Reserves Estimates on PP&E, Net of the Oil Sands and Offshore Segments

As described in Notes 1, 3, 4, 11 and 20 to the Consolidated Financial Statements, Management assesses its CGUs for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated DD&A and net impairment losses, may exceed its recoverable amount. Management calculates depletion for Oil Sands PP&E using the unit-of-production method based on estimated proved reserves.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 6

For Offshore PP&E, Management calculates depletion using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves. Costs subject to depletion include estimated future development costs to be incurred in developing proved or proved plus probable reserves. As of December 31, 2022, the Company had $24.7 billion and $2.5 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company recognized $3.3 billion of DD&A expense and no impairment related to PP&E in the Oil Sands and Offshore segments in the year ended December 31, 2022. Management identified potential indicators of impairment for the Sunrise CGU as of December 31, 2022 and performed an impairment test.

Management determined the recoverable amount of the Sunrise CGU (the recoverable amount) based on its fair value less costs of disposal using a discounted after-tax cash flow model. The determination of the recoverable amount required the use of significant assumptions and judgments by Management related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate. Management’s estimates of reserves used for both the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore segments have been developed by Management’s specialists, specifically independent qualified reserves evaluators.

The principal considerations for our determination that performing procedures relating to the impact of reserves estimates on PP&E, net of the Oil Sands and Offshore segments is a critical audit matter are (i) the significant amount of judgment required by Management, including the use of Management’s specialists, when developing the estimates of reserves and the recoverable amount; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in developing these estimates related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimates of reserves, the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore segments. These procedures also included, among others, testing Management’s process for determining the recoverable amount and DD&A expense for the Oil Sands and Offshore Segments, which included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in Management’s determination of the recoverable amount; (iii) assessing the reasonability of the significant assumptions used by Management, when developing the estimates of reserves and the recoverable amount, related to forward commodity prices, expected production volumes, as well as future development and operating expenditures, and (iv) testing the unit-of-production rates used to calculate DD&A expense. The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimated reserves used in the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore segments. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and significant assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings. Evaluating the significant assumptions used by Management’s specialists related to forward commodity prices, expected production volumes, as well as future development and operating expenditures involved assessing whether the assumptions used were reasonable considering the current and past performance of the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the recoverable amount, including the discount rate used.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta, Canada

February 15, 2023

We have served as the Company’s auditor since 2008.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 7

CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)

For the years ended December 31,

($ millions, except per share amounts)

	Notes	2022	2021 (1)	2020
Revenues	1
Gross Sales		71,765	48,811	13,914
Less: Royalties		4,868	2,454	371
		66,897	46,357	13,543
Expenses	1
Purchased Product		33,801	23,326	5,681
Transportation and Blending		11,530	8,038	4,728
Operating		5,569	4,716	1,955
(Gain) Loss on Risk Management	37	1,636	995	308
Depreciation, Depletion and Amortization	11,20,21,23	4,679	5,886	3,464
Exploration Expense		101	18	91
(Income) Loss From Equity-Accounted Affiliates	22	(15)	(57)	—
General and Administrative	6	865	849	292
Finance Costs	7	820	1,082	536
Interest Income		(81)	(23)	(9)
Integration and Transaction Costs	8	106	349	29
Foreign Exchange (Gain) Loss, Net	9	343	(174)	(181)
Revaluation (Gains)	5	(549)	—	—
Re-measurement of Contingent Payments	28	162	575	(80)
(Gain) Loss on Divestiture of Assets	10	(269)	(229)	(81)
Other (Income) Loss, Net	12	(532)	(309)	40
Earnings (Loss) Before Income Tax		8,731	1,315	(3,230)
Income Tax Expense (Recovery)	13	2,281	728	(851)
Net Earnings (Loss)		6,450	587	(2,379)
Net Earnings (Loss) Per Common Share ($)	14
Basic		3.29	0.27	(1.94)
Diluted		3.20	0.27	(1.94)

(1)     See Note 3X for revisions to prior period results.

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 8

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the years ended December 31,

($ millions)

	Notes	2022	2021	2020
Net Earnings (Loss)		6,450	587	(2,379)
Other Comprehensive Income (Loss), Net of Tax	33
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment    Benefits	31	71	38	(8)
Change in the Fair Value of Equity Instruments at FVOCI (1)		2	—	—
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		713	(129)	(44)
Total Other Comprehensive Income (Loss), Net of Tax		786	(91)	(52)
Comprehensive Income (Loss)		7,236	496	(2,431)

(1)Fair value through other comprehensive income (loss) (“FVOCI”).

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 9

CONSOLIDATED BALANCE SHEETS

As at December 31,

($ millions)

	Notes	2022	2021
Assets
Current Assets
Cash and Cash Equivalents	15	4,524	2,873
Accounts Receivable and Accrued Revenues	16	3,473	3,870
Income Tax Receivable		121	22
Inventories	17	4,312	3,919
Assets Held for Sale	18	—	1,304
Total Current Assets		12,430	11,988
Restricted Cash	29	209	186
Exploration and Evaluation Assets, Net	1,19	685	720
Property, Plant and Equipment, Net	1,20	36,499	34,225
Right-of-Use Assets, Net	1,21	1,845	2,010
Income Tax Receivable		25	66
Investments in Equity-Accounted Affiliates	22	365	311
Other Assets	23	342	431
Deferred Income Taxes	13	546	694
Goodwill	24	2,923	3,473
Total Assets		55,869	54,104
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities	25	6,124	6,353
Short-Term Borrowings	26	115	79
Lease Liabilities	27	308	272
Contingent Payments	28	263	236
Income Tax Payable		1,211	179
Liabilities Related to Assets Held for Sale	18	—	186
Total Current Liabilities		8,021	7,305
Long-Term Debt	26	8,691	12,385
Lease Liabilities	27	2,528	2,685
Contingent Payments	28	156	—
Decommissioning Liabilities	29	3,559	3,906
Other Liabilities	30	1,042	929
Deferred Income Taxes	13	4,283	3,286
Total Liabilities		28,280	30,496
Shareholders’ Equity		27,576	23,596
Non-Controlling Interest		13	12
Total Liabilities and Equity		55,869	54,104
Commitments and Contingencies	40

See accompanying Notes to Consolidated Financial Statements.

[/s/ Keith A. MacPhail]	[/s/ Claude Mongeau]
Keith A. MacPhail	Claude Mongeau
Director	Director
Cenovus Energy Inc.	Cenovus Energy Inc.
February 15, 2023

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 10

CONSOLIDATED STATEMENTS OF EQUITY

($ millions)

	Shareholders' Equity
	Common Shares	Preferred Shares	Warrants	Paid in Surplus	Retained Earnings	AOCI (1)	Total	Non-Controlling Interest
	(Note 32)	(Note 32)	(Note 32)			(Note 33)
As at December 31, 2019	11,040	—	—	4,377	2,957	827	19,201	—
Net Earnings (Loss)	—	—	—	—	(2,379)	—	(2,379)	—
Other Comprehensive Income    (Loss), Net of Tax	—	—	—	—	—	(52)	(52)	—
Total Comprehensive Income (Loss)	—	—	—	—	(2,379)	(52)	(2,431)	—
Stock-Based Compensation    Expense	—	—	—	14	—	—	14	—
Base Dividends on Common Shares	—	—	—	—	(77)	—	(77)	—
As at December 31, 2020	11,040	—	—	4,391	501	775	16,707	—
Net Earnings (Loss)	—	—	—	—	587	—	587	—
Other Comprehensive Income    (Loss), Net of Tax	—	—	—	—	—	(91)	(91)	—
Total Comprehensive Income (Loss)	—	—	—	—	587	(91)	496	—
Common Shares Issued (Note 5)	6,111	—	—	—	—	—	6,111	—
Common Shares Issued Under     Stock Option Plans	7	—	—	(1)	—	—	6	—
Purchase of Common Shares Under    NCIBs (2) (Note 32)	(145)	—	—	(120)	—	—	(265)	—
Preferred Shares Issued (Note 5)	—	519	—	—	—	—	519	—
Warrants Issued (Note 5)	—	—	216	—	—	—	216	—
Warrants Exercised	3	—	(1)	—	—	—	2	—
Stock-Based Compensation    Expense	—	—	—	14	—	—	14	—
Base Dividends on Common Shares	—	—	—	—	(176)	—	(176)	—
Dividends on Preferred Shares	—	—	—	—	(34)	—	(34)	—
Non-Controlling Interest	—	—	—	—	—	—	—	12
As at December 31, 2021	17,016	519	215	4,284	878	684	23,596	12
Net Earnings (Loss)	—	—	—	—	6,450	—	6,450	—
Other Comprehensive Income    (Loss), Net of Tax	—	—	—	—	—	786	786	—
Total Comprehensive Income (Loss)	—	—	—	—	6,450	786	7,236	—
Common Shares Issued Under    Stock Option Plans	170	—	—	(32)	—	—	138	—
Purchase of Common Shares Under    NCIBs (2) (Note 32)	(959)	—	—	(1,571)	—	—	(2,530)	—
Warrants Exercised	93	—	(31)	—	—	—	62	—
Stock-Based Compensation    Expense	—	—	—	10	—	—	10	—
Base Dividends on Common Shares	—	—	—	—	(682)	—	(682)	—
Variable Dividends on Common    Shares	—	—	—	—	(219)	—	(219)	—
Dividends on Preferred Shares	—	—	—	—	(35)	—	(35)	—
Non-Controlling Interest	—	—	—	—	—	—	—	1
As at December 31, 2022	16,320	519	184	2,691	6,392	1,470	27,576	13

(1)    Accumulated other comprehensive income (loss) (“AOCI”).

(2)     Normal course issuer bids (“NCIBs”).

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 11

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,

($ millions)

	Notes	2022	2021	2020
Operating Activities
Net Earnings (Loss)		6,450	587	(2,379)
Depreciation, Depletion and Amortization	11,20,21,23	4,679	5,886	3,464
Inventory Write-Down (Reversal)		—	16	555
Realization of Inventory Write-Downs		—	(31)	(572)
Deferred Income Tax Expense (Recovery)	13	642	452	(838)
Unrealized (Gain) Loss on Risk Management	37	(126)	2	56
Unrealized Foreign Exchange (Gain) Loss	9	365	(312)	(131)
Realized Foreign Exchange (Gain) Loss on Non-Operating Items		146	171	(33)
Revaluation (Gains)	5	(549)	—	—
Re-measurement of Contingent Payments, Net of Cash Paid		(469)	400	(80)
(Gain) Loss on Divestiture of Assets	10	(269)	(229)	(81)
Unwinding of Discount on Decommissioning Liabilities	29	176	199	57
(Income) Loss From Equity-Accounted Affiliates	22	(15)	(57)	—
Distributions Received From Equity-Accounted Affiliates	22	65	137	—
Other		(117)	27	99
Settlement of Decommissioning Liabilities		(150)	(102)	(42)
Net Change in Non-Cash Working Capital	39	575	(1,227)	198
Cash From (Used in) Operating Activities		11,403	5,919	273
Investing Activities
Acquisitions, Net of Cash Acquired	5	(397)	735	—
Capital Investment	19,20	(3,708)	(2,563)	(859)
Proceeds From Divestitures	10	1,514	435	38
Payment on Divestiture of Assets	10	(50)	—	—
Net Cash Received on Assumption of Decommissioning Liabilities	5	—	75	—
Net Change in Investments and Other		(211)	17	(4)
Net Change in Non-Cash Working Capital	39	538	359	(38)
Cash From (Used in) Investing Activities		(2,314)	(942)	(863)
Net Cash Provided (Used) Before Financing Activities		9,089	4,977	(590)
Financing Activities	39
Net Issuance (Repayment) of Short-Term Borrowings		34	(77)	117
Issuance of Long-Term Debt		—	1,557	1,326
(Repayment) of Long-Term Debt		(4,149)	(2,870)	(112)
Net Issuance (Repayment) of Revolving Long-Term Debt		—	(350)	(220)
Principal Repayment of Leases	27	(302)	(300)	(197)
Common Shares Issued Under Stock Option Plans		138	6	—
Purchase of Common Shares Under NCIBs	32	(2,530)	(265)	—
Proceeds From Exercise of Warrants		62	2	—
Base Dividends Paid on Common Shares	14	(682)	(176)	(77)
Variable Dividends Paid on Common Shares	14	(219)	—	—
Dividends Paid on Preferred Shares		(26)	(34)	—
Other		(2)	—	—
Cash From (Used in) Financing Activities		(7,676)	(2,507)	837
Effect of Foreign Exchange on Cash and Cash Equivalents		238	25	(55)
Increase (Decrease) in Cash and Cash Equivalents		1,651	2,495	192
Cash and Cash Equivalents, Beginning of Year		2,873	378	186
Cash and Cash Equivalents, End of Year		4,524	2,873	378

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc., including its subsidiaries, (together “Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States (“U.S.”). On January 1, 2021, Cenovus and Husky Energy Inc. (“Husky”) closed a transaction to combine the two companies through a plan of arrangement (the “Arrangement”) (see Note 5C). The transaction included Husky's upstream assets, extensive transportation, storage and logistics and downstream infrastructure. Comparative figures include Cenovus's results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.

Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. The executive and registered office is located at 4100, 225 6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2.

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative periods have been re-presented to reflect this change (see Note 3X).

The Company operates through the following reportable segments:

Upstream Segments

•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

•Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.

•Offshore, includes offshore operations, exploration and development activities in China and the East Coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

•Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.

•U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima Refinery and Superior Refinery, the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66) and the jointly-owned Toledo Refinery (jointly owned with operator BP Products North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel and jet fuel.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Corporate and Eliminations

Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices.

A) Results of Operations – Segment and Operational Information

	Upstream
For the years ended December 31,	Oil Sands			Conventional			Offshore			Total
	2022	2021 (1)	2020	2022	2021	2020	2022	2021	2020	2022	2021 (1)	2020
Revenues
Gross Sales	34,775	22,827	8,804	4,332	3,235	904	2,020	1,782	—	41,127	27,844	9,708
Less: Royalties	4,493	2,196	331	298	150	40	77	108	—	4,868	2,454	371
	30,282	20,631	8,473	4,034	3,085	864	1,943	1,674	—	36,259	25,390	9,337
Expenses
Purchased Product	4,810	2,404	1,262	2,023	1,655	268	—	—	—	6,833	4,059	1,530
Transportation and    Blending	12,036	8,625	4,683	143	74	81	15	15	—	12,194	8,714	4,764
Operating	2,930	2,451	1,156	541	551	320	318	239	—	3,789	3,241	1,476
Realized (Gain) Loss on Risk    Management	1,527	786	268	92	2	—	—	—	—	1,619	788	268
Operating Margin	8,979	6,365	1,104	1,235	803	195	1,610	1,420	—	11,824	8,588	1,299
Unrealized (Gain) Loss on    Risk Management	(68)	18	57	13	1	—	—	—	—	(55)	19	57
Depreciation, Depletion and    Amortization	2,763	2,666	1,687	370	3	880	585	492	—	3,718	3,161	2,567
Exploration Expense	9	16	9	1	(3)	82	91	5	—	101	18	91
(Income) Loss From Equity-    Accounted Affiliates	8	(5)	—	—	—	—	(23)	(47)	—	(15)	(52)	—
Segment Income (Loss)	6,267	3,670	(649)	851	802	(767)	957	970	—	8,075	5,442	(1,416)

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

	Downstream
	Canadian Manufacturing			U.S. Manufacturing			Total
For the years ended December 31,	2022	2021 (1)	2020	2022	2021	2020	2022	2021 (1)	2020
Revenues
Gross Sales	7,792	6,215	82	30,310	20,043	4,733	38,102	26,258	4,815
Less: Royalties	—	—	—	—	—	—	—	—	—
	7,792	6,215	82	30,310	20,043	4,733	38,102	26,258	4,815
Expenses
Purchased Product	6,389	5,156	—	26,112	17,955	4,429	32,501	23,111	4,429
Transportation and Blending	—	—	—	—	—	—	—	—	—
Operating	704	486	37	2,346	1,772	748	3,050	2,258	785
Realized (Gain) Loss on Risk    Management	—	—	—	112	104	(21)	112	104	(21)
Operating Margin	699	573	45	1,740	212	(423)	2,439	785	(378)
Unrealized (Gain) Loss on Risk    Management	—	—	—	18	1	(1)	18	1	(1)
Depreciation, Depletion and    Amortization	208	226	8	640	2,381	728	848	2,607	736
Exploration Expense	—	—	—	—	—	—	—	—	—
(Income) Loss From Equity-Accounted     Affiliates	—	—	—	—	—		—	—	—
Segment Income (Loss)	491	347	37	1,082	(2,170)	(1,150)	1,573	(1,823)	(1,113)

(1)Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

	Corporate and Eliminations			Consolidated
For the years ended December 31,	2022	2021 (1) (2)	2020	2022	2021 (1) (2)	2020
Revenues
Gross Sales	(7,464)	(5,291)	(609)	71,765	48,811	13,914
Less: Royalties	—	—	—	4,868	2,454	371
	(7,464)	(5,291)	(609)	66,897	46,357	13,543
Expenses
Purchased Product	(5,533)	(3,844)	(278)	33,801	23,326	5,681
Transportation and Blending	(664)	(676)	(36)	11,530	8,038	4,728
Operating	(1,270)	(783)	(306)	5,569	4,716	1,955
Realized (Gain) Loss on Risk Management	31	101	5	1,762	993	252
Unrealized (Gain) Loss on Risk Management	(89)	(18)	—	(126)	2	56
Depreciation, Depletion and Amortization	113	118	161	4,679	5,886	3,464
Exploration Expense	—	—	—	101	18	91
(Income) Loss From Equity-Accounted Affiliates	—	(5)	—	(15)	(57)	—
Segment Income (Loss)	(52)	(184)	(155)	9,596	3,435	(2,684)
General and Administrative	865	849	292	865	849	292
Finance Costs	820	1,082	536	820	1,082	536
Interest Income	(81)	(23)	(9)	(81)	(23)	(9)
Integration and Transaction Costs	106	349	29	106	349	29
Foreign Exchange (Gain) Loss, Net	343	(174)	(181)	343	(174)	(181)
Revaluation (Gains)	(549)	—	—	(549)	—	—
Re-measurement of Contingent Payment	162	575	(80)	162	575	(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)	(81)	(269)	(229)	(81)
Other (Income) Loss, Net	(532)	(309)	40	(532)	(309)	40
	865	2,120	546	865	2,120	546
Earnings (Loss) Before Income Tax				8,731	1,315	(3,230)
Income Tax Expense (Recovery)				2,281	728	(851)
Net Earnings (Loss)				6,450	587	(2,379)

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).

(2)Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

B) Revenues by Product

For the years ended December 31,	2022	2021	2020
Upstream
Crude Oil (1)	29,834	19,877	8,017
NGLs (1)	2,346	1,983	727
Natural Gas	3,690	3,032	535
Other	389	498	58
Downstream
Canadian Manufacturing
Synthetic Crude Oil	2,360	1,951	—
Asphalt	620	477	—
Other Products and Services (2)	4,812	3,787	82
U.S. Manufacturing
Gasoline	14,116	10,111	2,352
Diesel and Distillate	11,453	6,429	1,569
Other Products	4,741	3,503	812
Corporate and Eliminations (2)	(7,464)	(5,291)	(609)
Consolidated	66,897	46,357	13,543

(1)Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.

(2)Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

C) Geographical Information

	Revenues (1)
For the years ended December 31,	2022	2021	2020
Canada	33,222	23,768	8,715
United States	32,313	21,326	4,828
China	1,362	1,263	—
Consolidated	66,897	46,357	13,543

(1)Revenues by country are classified based on where the operations are located.

	Non-Current Assets (1)
As at December 31,	2022	2021 (2)
Canada	35,194	33,981
United States	4,824	4,093
China	2,064	2,583
Indonesia	365	311
Consolidated	42,447	40,968

(1)Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill.

(2)Canada excludes assets held for sale of $1.3 billion that were divested in 2022.

Major Customers

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2022, Cenovus had two customers (2021 – two; 2020 – three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $16.1 billion and $9.1 billion, respectively (2021 – $8.5 billion and $6.8 billion; 2020 – $4.3 billion, $1.8 billion and $1.5 billion, respectively), and are reported across all of the Company’s operating segments.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
As at December 31,	2022	2021	2022	2021	2022	2021
Oil Sands	674	653	24,657	22,535	638	754
Conventional	6	6	2,020	2,174	2	2
Offshore	5	61	2,549	2,822	152	160
Canadian Manufacturing (1)	—	—	2,466	2,558	252	388
U.S. Manufacturing	—	—	4,482	3,745	329	252
Corporate and Eliminations	—	—	325	391	472	454
Consolidated	685	720	36,499	34,225	1,845	2,010

	Goodwill		Total Assets
As at December 31,	2022	2021	2022	2021 (2)
Oil Sands	2,923	3,473	32,248	31,070
Conventional	—	—	2,410	3,026
Offshore	—	—	3,339	3,597
Canadian Manufacturing (1)	—	—	3,172	3,884
U.S. Manufacturing (3)	—	—	8,324	7,509
Corporate and Eliminations (3)	—	—	6,376	5,018
Consolidated	2,923	3,473	55,869	54,104

(1)Prior period results have been re-presented. PP&E, ROU assets and total assets from the remaining commercial fuels business and the historic retail fuels business have been aggregated with the Canadian Manufacturing segment. 

(2)Total assets include assets held for sale $1.3 billion that were divested in 2022.

(3)Prior period results were re-presented to move income tax receivable and deferred income tax assets from the U.S. Manufacturing segment to the Corporate and Eliminations segment.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

E) Capital Expenditures (1)

For the years ended December 31,	2022	2021	2020
Capital Investment
Oil Sands	1,792	1,019	427
Conventional	344	222	78
Offshore
Asia Pacific	8	21	—
Atlantic	302	154	—
Total Upstream	2,446	1,416	505
Canadian Manufacturing (2)	117	68	33
U.S. Manufacturing	1,059	995	243
Total Downstream	1,176	1,063	276
Corporate and Eliminations	86	84	60
	3,708	2,563	841
Acquisitions (Note 5)
Oil Sands (3)	1,609	5,005	6
Conventional	12	551	12
Offshore (4)	—	3,129	—
Canadian Manufacturing (2)	—	2,973	—
U.S. Manufacturing	—	1,618	—
Corporate and Eliminations	—	156	—
	1,621	13,432	18
Total Capital Expenditures	5,329	15,995	859

(1)Includes expenditures on PP&E, E&E assets and capitalized interest.

(2)Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

(3)Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-existing interest in SOSP of $1.6 billion.

(4)Excludes capital expenditures related to the HCML joint venture, which are accounted for using the equity method.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements have been prepared in accordance with IFRS as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee.

These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Company’s accounting policies disclosed in Note 3.

These Consolidated Financial Statements were approved by the Board of Directors effective February 15, 2023.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A) Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s accounts reflect its share of the assets, liabilities, revenues and expenses from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s activities relate to joint ventures, which are accounted for using the equity method of accounting.

An associate is an entity for which the Company has significant influence over but does not control or jointly control the affiliate. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter to recognize the Company’s share of the affiliate’s profit or loss and other comprehensive income (“OCI”).

B) Foreign Currency Translation

Functional and Presentation Currency

The Company’s functional and presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in OCI as cumulative translation adjustments.

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests.

Transactions and Balances

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the reporting date. Any gains or losses are recorded in the Consolidated Statements of Earnings (Loss).

C) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Cenovus recognizes revenue from the following major products and services:

•Sale of crude oil, NGLs and natural gas.

•Sale of petroleum and refined products.

•Crude oil and natural gas processing services.

•Pipeline transportation, the blending of crude oil and the storage of crude oil, diluent and natural gas.

•Fee-for-service hydrocarbon transloading services.

•Construction services.

The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products, which is generally at a point in time. Performance obligations for crude oil and natural gas processing revenue, transportation services and transloading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Revenue associated with natural gas processing, transportation services and transloading services are generally based on fixed price contracts.

Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and revenue from cost-plus contracts are recognized as services are performed.

The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date, the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered or the deferral provision can no longer be extended.

Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with the exception of certain construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.

D) Purchased Product

The cost of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market are recorded as purchased product.

E) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of diluent used in blending, are recognized when the product is sold.

F) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.

Certain costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

G) Employee Benefit Plans

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component.

Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans, benefits are not funded before retirement.

Pension expense for the defined contribution pension is recorded as the benefits are earned.

The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows:

•Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs.

•Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

•Re-measurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Re-measurements are not reclassified to net earnings in subsequent periods.

Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded.

H) Government Grants

Government grants are recognized when there is reasonable assurance that the grant will be received and all conditions associated with the grant are met. If a grant is received, but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. Grants related to assets are recorded as a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the services have been performed.

I) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

J) Related Party Transactions

The Company enters into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value. Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.

K) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

L) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a maturity of three months or less.

Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within twelve months, it is classified as a non-current asset.

M) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

N) Exploration and Evaluation Assets

Certain costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. E&E assets are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired or the future economic value has decreased. E&E assets are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.

Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as depreciation, depletion and amortization (“DD&A”), is recognized on this production using a unit-of-production method based on estimated proved reserves determined using forward prices and costs and considering any estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an energy equivalent basis.

Non-producing assets classified as E&E are not depleted.

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

Any gains or losses from the divestiture of E&E assets are recognized in net earnings.

O) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated DD&A, and net of any impairment losses. Expenditures related to renewals or enhancements that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

Any gains or losses from the divestiture of PP&E are recognized in net earnings.

Crude Oil and Natural Gas Properties

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties and related infrastructure facilities, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations, natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to be incurred in developing those reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of either the asset received, or the asset given up, cannot be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and natural gas properties are depleted using a unit-of-production method.

Manufacturing Assets

The initial costs of refining and upgrading PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining and upgrading assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

•Land improvements and buildings: 15 to 40 years.

•Office improvements and buildings: 3 to 15 years.

•Refining equipment: 10 to 60 years.

The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate.

Processing, Transportation and Storage Assets, Commercial Fuels Business and Other

Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available for use by the Company.

The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

P) Impairment and Impairment Reversals of Non-Financial Assets

PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is estimated based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), costs to develop and the discount rate, and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Q) Leases

The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company has elected not to separate non-lease components.

As Lessee

Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments, costs to be incurred by the lessee in dismantling, removing and restoring the underlying asset, variable lease payments that are based on an index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating the lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with reasonably similar characteristics.

Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings over the lease term.

The lease liability is measured at amortized cost using the effective interest method. It is re-measured when there is a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the Company will exercise a purchase, extension or termination option that is within the control of the Company.

When the lease liability is re-measured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero.

The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date.

The ROU asset is depreciated on a straight-line basis, over the shorter of the estimated useful life of the asset or lease term, or using the unit-of-production method. The ROU asset may be adjusted for certain re-measurements of the lease liability and impairment losses.

Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating, transportation or general and administrative expense.

A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will re-measure the lease liability using the Company’s incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope.

As Lessor

As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments received under operating leases as income on a straight-line basis over the lease term as other income.

When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the sublease is classified as an operating lease.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

R) Intangible Assets

Intangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset. Impairment losses are recognized in the Consolidated Statements of Earnings(Loss) as DD&A.

S) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited to net earnings. Acquisition costs are expensed as incurred.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity in accordance with the terms of the agreement. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

T) Provisions

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings (Loss).

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, surface and subsea plant and equipment, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Onerous Contract Provisions

Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss).

Renewable Fuel Obligations

The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured as the expected market price of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the month purchased. RINs purchased on a secondary market are measured at cost. A net RIN position is presented in other assets and a net RVO position is included in other liabilities.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

U) Share Capital and Warrants

Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the Company’s option. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative.

Transaction costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s paid in surplus. Common shares are cancelled subsequent to being purchased.

Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are recorded as share capital.

V) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expenses, or recorded to PP&E or E&E assets when directly related to exploration or development activities.

Stock Options With Associated Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation over the vesting period, with a corresponding increase recorded as paid in surplus in shareholders’ equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Cenovus Replacement Stock Options

Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the stock option is recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation in the period they occur. Stock-based compensation is recorded to PP&E or E&E assets when it is directly related to exploration or development activities.

W) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets, net investment in finance leases, investments in the equity of companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, risk management liabilities and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously.

The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

•Level 1 inputs are quoted prices in active markets for identical assets and liabilities.

•Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly.

•Level 3 inputs are unobservable inputs for the asset or liability.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Classification and Measurement of Financial Assets

The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets:

•Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

•FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

•Fair Value through Profit or Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets.

On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis.

At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.

Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model.

A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership.

Impairment of Financial Assets

The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component.

Classification and Measurement of Financial Liabilities

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable.

Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.

A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is re-measured based on the new cash flows and a gain or loss is recorded in net earnings.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 28

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Derivatives

Derivative financial instruments are primarily used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

Derivative financial instruments are measured at FVTPL unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

X) Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures

Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands segment and Corporate and Eliminations segment was revised.

During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows.

The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the corresponding revised amounts:

Year Ended December 31, 2021

Oil Sands Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Purchased Product	3,188	(784)	—	2,404
Transportation and Blending	7,841	784	—	8,625
	11,029	—	—	11,029

Canadian Manufacturing	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	4,472	—	1,743	6,215
Purchased Product	3,552	—	1,604	5,156
Operating	388	—	98	486
Depreciation, Depletion and Amortization	167	—	59	226
	365	—	(18)	347

Retail	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	2,158	—	(2,158)	—
Purchased Product	2,019	—	(2,019)	—
Operating	98	—	(98)	—
Depreciation, Depletion and Amortization	59	—	(59)	—
	(18)	—	18	—

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 29

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Corporate and Eliminations Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	(5,706)	—	415	(5,291)
Purchased Product	(4,888)	629	415	(3,844)
Transportation and Blending	(47)	(629)	—	(676)
	(771)	—	—	(771)

Consolidated	Previously Reported	Revision	Segment Aggregation	Revised
Purchased Product	23,481	(155)	—	23,326
Transportation and Blending	7,883	155	—	8,038
	31,364	—	—	31,364

Y) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business.

4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

A) Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.

Joint Arrangements

The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in the following jointly controlled entities:

•WRB Refining LP (“WRB”).

•BP-Husky Refining LLC (“Toledo”).

It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB and Toledo. As a result, the joint arrangements are classified as joint operations and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with BP Canada Energy Group ULC (“BP Canada”) and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”). As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to August 31, 2022, Cenovus controls SOSP, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, SOSP was consolidated.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 30

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:

•The original intention of the joint arrangements was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.

•The agreements require the partners to make contributions if funds are insufficient to meet the obligations or liabilities of the corporation and partnerships. The past development of SOSP, and the past and future development of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.

•WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt facility until November 2022.

•SOSP was operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants in accordance with the partnership agreement. WRB and Toledo have very similar structures modified to account for the operating environment of the refining business.

•Cenovus, Phillips 66 and BP, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangements do not have employees and, as such, are not capable of performing these roles.

•In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and impairment reversals.

Recoveries from Insurance Claims

The Company uses estimates and assumptions on the amount recorded for insurance proceeds that are reasonably certain to be received. Accordingly, actual results may differ from these estimated recoveries.

B) Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

The evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could change assumptions used to determine the recoverable amount of the Company’s PP&E and E&E assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects, may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built into our estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for energy.

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 31

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands, Conventional and Offshore segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Recoverable amounts for the Company’s manufacturing assets, crude-by-rail terminal and related ROU assets use assumptions such as throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Recoverable amounts for the Company’s real estate ROU assets use assumptions such as real estate market conditions which includes market vacancy rates and sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of liabilities and estimate the future value. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired, liabilities assumed and assets given up in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparable transactions and discounted cash flows. For the Company’s upstream assets, key assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves and resources for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.

Income Tax Provisions

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 32

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

5. ACQUISITIONS

A) Sunrise Oil Sands Partnership

i) Summary of the Acquisition

On August 31, 2022, Cenovus closed the transaction with BP Canada to purchase the remaining 50 percent interest in SOSP, previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). The Sunrise Acquisition had an effective date of May 1, 2022. It provides Cenovus with full ownership and further enhances Cenovus’s core strength in the oil sands.

The Sunrise Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is recorded as goodwill.

ii) Identifiable Assets Acquired and Liabilities Acquired

The purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect items not initially identified, as well as new information obtained about the conditions that existed at the date of the Sunrise Acquisition. Changes to identifiable assets acquired and liabilities assumed includes increases of $26 million to both PP&E and decommissioning liabilities. The impact to DD&A and finance costs (including the unwinding of the discount on decommissioning liabilities) as a result of the measurement period adjustments was not material.

As at	August 31, 2022
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	9
Accounts Receivable and Accrued Revenues	164
Inventories	88
Property, Plant and Equipment	3,218
Accounts Payable and Accrued Liabilities	(313)
Income Tax Payable	(39)
Decommissioning Liabilities	(48)
Deferred Income Tax Liabilities	(486)
Total Identifiable Net Assets	2,593

The fair value and gross contractual amount of acquired accounts receivable and accrued revenues is $164 million, all of which was collected.

iii) Total Consideration

Total consideration for the Sunrise Acquisition consisted of $600 million in cash, before closing adjustments, and Cenovus’s 35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. Cenovus also agreed to make quarterly variable payments to BP Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a specified threshold. The maximum cumulative variable payment is $600 million. The following table summarizes the fair value of total consideration:

As at	August 31, 2022
Cash, Net of Closing Adjustments	394
Bay Du Nord	40
Variable Payment	600
Total Consideration	1,034

Non-monetary assets transferred as part of consideration must be re-measured at their acquisition-date fair value, with any gain or loss recognized in net earnings (loss). As a result, the Company re-measured its interest in Bay du Nord to its estimated fair value and recognized a non-cash revaluation gain of $40 million.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 33

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Cenovus agreed to make quarterly payments from SOSP to BP Canada for up to two years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel. The first quarterly period ended on November 30, 2022. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price in the quarter less $53.00 multiplied by $2.8 million, for any of the eight quarters in which the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the contract term is $600 million.

The variable payment is accounted for as a financial instrument. The fair value of $600 million on August 31, 2022, was estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS differential futures pricing. The variable payment will be re-measured at fair value with changes in fair value recognized in net earnings (loss) at each reporting date until the earlier of when the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed (see Note 28).

iv) Goodwill

As at	August 31, 2022
Total Purchase Consideration	1,034
Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership	1,559
Fair Value of Identifiable Net Assets	(2,593)
Goodwill	—

Current and deferred income tax liabilities were recognized in the purchase price allocation for the 50 percent interest acquired in SOSP. The deferred income tax liability arises from the difference between the fair value of the acquired assets and liabilities assumed, and their tax basis.

Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership

Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11; therefore, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The acquisition-date fair value of the previously held interest was estimated to be $1.6 billion. The net carrying value of the SOSP assets was $960 million, including previously recorded goodwill (see Note 24). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re-measurement of its existing interest in SOSP to fair value.

v) Revenue and Profit Contribution

The acquired business contributed revenues of $599 million and net earnings of $nil for the period from August 31, 2022, to December 31, 2022. If the closing of the Sunrise Acquisition had occurred on January 1, 2022, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2022, would have been $67.8 billion and $6.6 billion, respectively. These amounts have been calculated using results from the acquired business, adjusting them for:

•Additional DD&A that would have been charged assuming the fair value adjustments to PP&E had applied from January 1, 2022.

•Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2022.

•The consequential tax effects.

This pro forma information is not necessarily indicative of the results that would have been obtained if the Sunrise Acquisition had actually occurred on January 1, 2022.

B) BP-Husky Refining LLC

On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest in Toledo (the “Toledo Acquisition”). After closing the transaction, Cenovus will operate the Toledo Refinery. Total consideration for the transaction includes US$300 million in cash plus the value of inventory. The Toledo Acquisition will be accounted for using the acquisition method pursuant to IFRS 3. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The refinery remains shut down in a safe state. The acquisition is expected to close at the end of February 2023.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 34

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

C) Husky Energy Inc.

On January 1, 2021, Cenovus and Husky closed the Arrangement. The following table summarizes the details of the consideration and the recognized amounts of assets acquired and liabilities assumed at the date of the acquisition.

As at	January 1, 2021
Consideration
Common Shares	6,111
Preferred Shares	519
Share Purchase Warrants	216
Replacement Stock Options	9
Other	17
Non-Controlling Interest	11
Total Consideration and Non-Controlling Interest	6,883
Identifiable Assets Acquired and Liabilities Assumed
Cash	735
Restricted Cash	164
Accounts Receivable and Accrued Revenues	1,307
Inventories	1,133
Exploration and Evaluation Assets	45
Property, Plant and Equipment	13,296
Right-of-Use Assets	1,132
Long-Term Income Tax Receivable	66
Other Assets	230
Investment in Equity-Accounted Affiliates	363
Deferred Income Tax Assets, Net	1,062
Accounts Payable and Accrued Liabilities	(2,283)
Income Tax Payable	(94)
Short-Term Borrowings	(40)
Long-Term Debt	(6,602)
Lease Liabilities	(1,441)
Decommissioning Liabilities	(2,697)
Other Liabilities	(782)
Total Identifiable Net Assets	5,594
Goodwill	1,289

Goodwill of $1.3 billion was attributable to the Lloydminster thermal assets of $651 million; the Sunrise asset of $550 million; and the Tucker asset of $88 million, within the Oil Sands segment.

D) Terra Nova

On September 8, 2021, the Company acquired an additional working    interest of 21 percent of the Terra Nova field in Atlantic Canada. Cenovus’s working interest in the joint operation is now 34 percent. The total consideration paid was $3 million, net of closing adjustments, and the effective date of the transaction was April 1, 2021. The additional working interest acquired was accounted for as an asset acquisition. Cenovus acquired cash of $78 million and PP&E of $84 million, and assumed decommissioning liabilities of     $159 million.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 35

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

6. GENERAL AND ADMINISTRATIVE

For the years ended December 31,	2022	2021	2020
Salaries and Benefits	204	264	145
Administrative and Other	297	225	102
Stock-Based Compensation Expense (Recovery) (Note 34)	373	159	49
Other Incentive Benefits Expense (Recovery)	(9)	201	(4)
	865	849	292

7. FINANCE COSTS

For the years ended December 31,	2022	2021	2020
Interest Expense – Short-Term Borrowings and Long-Term Debt	478	557	392
Net Premium (Discount) on Redemption of Long-Term Debt (1)	(29)	121	(25)
Interest Expense – Lease Liabilities (Note 27)	163	171	87
Unwinding of Discount on Decommissioning Liabilities (Note 29)	176	199	57
Other	37	34	25
	825	1,082	536
Capitalized Interest	(5)	—	—
	820	1,082	536

(1)     Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.

8. INTEGRATION AND TRANSACTION COSTS

Arrangement integration costs of $90 million were recognized in net earnings (loss) for the year ended December 31, 2022 (2021 – $349 million; 2020 – $29 million).

Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022, associated with the Sunrise Acquisition and the pending Toledo Acquisition.

9. FOREIGN EXCHANGE (GAIN) LOSS, NET

For the years ended December 31,	2022	2021	2020
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	365	(230)	(194)
Other	—	(82)	63
Unrealized Foreign Exchange (Gain) Loss	365	(312)	(131)
Realized Foreign Exchange (Gain) Loss	(22)	138	(50)
	343	(174)	(181)

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 36

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

10. DIVESTITURES

A) 2022 Divestitures

On January 31, 2022, the Company closed the sale of its Tucker asset in its Oil Sands segment for net proceeds of $730 million and recorded a before-tax gain of $165 million (after-tax gain – $126 million).

On February 28, 2022, the Company closed the sale of its Wembley assets in its Conventional segment for net proceeds of $221 million and recorded a before-tax gain of $76 million (after-tax gain – $58 million).

In September 2021, the Company entered into an agreement with a partner in the White Rose project in the Atlantic region that would transfer 12.5 percent of Cenovus’s working interest in the White Rose field and the satellite extensions, subject to certain closing conditions. On May 31, 2022, the final closing conditions were satisfied, which included the approval of the West White Rose project restarting. Cenovus paid $50 million associated with transferring the Company’s working interest, resulting in a before-tax gain of $62 million (after-tax gain – $47 million).

On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. (“Headwater”) for proceeds of $110 million, with no gain or loss recognized as the investment was recorded at fair value prior to the sale.

On September 13, 2022, the Company closed the sales of 337 gas stations in the historic retail fuels business, located across Western Canada and Ontario, for net cash proceeds of $404 million and recorded a before-tax loss of $74 million (after-tax loss – $56 million).

B) 2021 Divestitures

Effective May 1, 2021, the Company closed the sale of its GORR in the Marten Hills area of Alberta relating to the Conventional segment. Cenovus received cash proceeds of $102 million and recorded a before-tax gain of $60 million (after-tax gain – $47 million).

The Company sold Conventional segment assets in the Kaybob area in July 2021 and assets in the East Clearwater area in August 2021 for combined gross proceeds of approximately $82 million. A before-tax gain of $17 million (after-tax gain – $13 million) was recorded on the dispositions.

In 2020, as part of the sale of the Marten Hills assets, the Company received 50 million common shares of Headwater. On October 14, 2021, the Company sold 50 million common shares of Headwater for gross proceeds of $228 million and recorded a before-tax gain of $116 million (after-tax gain – $99 million).

C) 2020 Divestitures

On December 2, 2020, the Company sold its Marten Hills assets in northern Alberta to Headwater for total consideration of $138 million, excluding the retained GORR. A before-tax gain of $79 million was recorded on the sale (after-tax gain – $65 million). Total consideration was $33 million in cash, 50 million common shares valued at $97 million and 15 million share purchase warrants valued at $8 million at the date of close.

11. IMPAIRMENT CHARGES AND REVERSALS

At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed the recoverable amount. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. Goodwill is tested for impairment at least annually. For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates.

A) Upstream Cash-Generating Units

i) 2022 Impairment Charges and Reversals

The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its carrying amount and no impairment was recorded. 

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 37

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment are approximated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include forward prices and costs, consistent with Cenovus’s IQREs, as well as costs to develop and the discount rates. Fair values for producing properties are calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2022. All reserves are evaluated as at December 31, 2022, by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2023	2024	2025	2026	2027	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	80.33	78.50	76.95	77.61	79.16	2.00	%
Western Canadian Select (C$/barrel)	76.54	77.75	77.55	80.07	81.89	2.00	%
Condensate at Edmonton (C$/barrel)	106.22	101.35	98.94	100.19	101.74	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	4.23	4.40	4.21	4.27	4.34	2.00	%

(1)      Assumes natural gas heating value of one million British thermal units per thousand cubic feet (“Mcf”).

Discount Rates

Discounted future cash flows are determined by applying a discount rate between 14 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

For the Sunrise CGU, a one percent increase in the discount rate would result in an impairment of $69 million and a five percent decrease in forward price estimates would result in an impairment of $226 million. A one percent increase in the discount rate or a five percent decrease in forward price estimates would not impact the result of the impairment tests performed on CGUs with associated goodwill.

ii) 2021 Impairment Charges and Reversals

As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. As at December 31, 2021, there were indicators of impairment reversals for the Company’s upstream CGUs due to an increase in forward commodity prices. An assessment was performed and indicated the recoverable amount was greater than the carrying value.

As at December 31, 2021, the recoverable amount of the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs was estimated to be $2.0 billion. In 2020, the Company recorded a total impairment charge of $555 million in the Conventional segment due to a decline in forward commodity prices and changes in future development plans. As at December 31, 2021, the Company reversed the full amount of impairment losses of $378 million, net of dispositions and the DD&A that would have been recorded had no impairment been recorded. The reversal was primarily due to improved forward commodity prices.

The following table summarizes impairment reversals recorded in 2021 and estimated recoverable amounts as at December 31, 2021, by CGU:

	Reversal of Impairment	Recoverable Amount
Clearwater	145	427
Elmworth-Wapiti	115	747
Kaybob-Edson	118	837

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 38

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves included forward prices and costs, consistent with Cenovus’s IQREs, costs to develop and the discount rates. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2021. All reserves were evaluated as at December 31, 2021, by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2021, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2022	2023	2024	2025	2026	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	72.83	68.78	66.76	68.09	69.45	2.00	%
Western Canadian Select (C$/barrel)	74.43	69.17	66.54	67.87	69.23	2.00	%
Edmonton C5+ (C$/barrel)	91.85	85.53	82.98	84.63	86.33	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	3.56	3.20	3.05	3.10	3.17	2.00	%

(1)      Assumes natural gas heating value of one million British thermal units per thousand cubic feet ("Mcf").

Discount Rates

Discounted future cash flows were determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the amount of impairment reversals recorded in the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs at December 31, 2021.

A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwill.

iii) 2020 Impairment Charges and Reversals

As at March 31, 2020, the Company recorded an impairment loss of $315 million in the Conventional CGU due to a decline in forward crude oil and natural gas prices. As at December 31, 2020, the Company recorded an additional impairment loss of $240 million in the Conventional CGU due to a change in future development plans.

The following table summarizes impairment losses recorded in 2020 and estimated recoverable amounts as at December 31, 2020, by CGU:

	Impairment	Recoverable Amount
Clearwater	260	160
Elmworth-Wapiti	120	259
Kaybob-Edson	175	384

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves included crude oil, NGLs and natural gas prices, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. All reserves were evaluated as at December 31, 2020, by the Company’s IQREs.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2021	2022	2023	2024	2025	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	47.17	50.17	53.17	54.97	56.07	2.00	%
Western Canadian Select (C$/barrel)	44.63	48.18	52.10	54.10	55.19	2.00	%
Edmonton C5+ (C$/barrel)	59.24	63.19	67.34	69.77	71.18	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	2.88	2.80	2.71	2.75	2.80	2.00	%

(1)      Assumes gas heating value of one million British thermal units per Mcf.

Discount Rates

Discounted future cash flows were determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated impairment amount used in the impairment testing completed as at December 31, 2020, for the following CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Clearwater	7	(7)	(68)	128
Elmworth-Wapiti	10	(10)	(71)	126
Kaybob-Edson	17	(19)	(71)	140

A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwill.

B) Downstream Cash-Generating Units

i) 2022 Impairment Charges and Reversals

As at December 31, 2022, the Company identified indicators of impairment for the Toledo CGU due to the pending acquisition of the remaining 50 percent from BP and a fire at the Toledo Refinery, and for the Superior CGU with the commissioning of the asset in preparation for restart. The total carrying amount of the Toledo and Superior CGUs was greater than the recoverable amount. An impairment charge of $1.5 billion was recorded as additional DD&A in the U.S. Manufacturing segment.

As at December 31, 2022, there were also indicators of impairment reversals for the Company’s Borger, Wood River and Lima CGUs due to an increase in forward crack spreads, resulting in higher margins for refined products. An assessment was performed that indicated the recoverable amount was greater than the carrying value of the associated CGUs. As at December 31, 2022, the Company reversed impairment charges of $1.2 billion, net of DD&A that would have been recorded had no impairment been recorded.

As at December 31, 2022, the aggregate recoverable amount of the U.S. Manufacturing CGUs was estimated to be $5.4 billion.

Key Assumptions

The recoverable amount (Level 3) of the U.S. Manufacturing CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 40

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Crude Oil and Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were:

(US$/barrel)	2023	2024	2025	2026	2027
West Texas Intermediate	80.33	78.50	76.95	77.61	79.16
Differential WTI-WTS	(0.56)	(0.56)	(0.56)	(0.56)	(0.56)
Differential WTI-WCS	(23.32)	(19.09)	(17.42)	(15.87)	(15.74)
Chicago 3-2-1 Crack Spreads (WTI)	29.37	24.10	22.12	21.70	21.67

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of between 15 percent to 18 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have on the net impairment amount recorded as at December 31, 2022, for the U.S. Manufacturing segment CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
U.S. Manufacturing	69	(65)	(268)	268

	Increase (Decrease) to Impairment Reversal Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
U.S. Manufacturing	(72)	14	168	(342)

ii) 2021 Impairment Charges and Reversals

As at December 31, 2021, lower forward pricing that would result in lower margins for refined products was identified as an indicator of impairment for the Borger, Wood River, Lima and Toledo CGUs. As at December 31, 2021, the total carrying amounts of the Borger, Wood River and Lima CGUs were greater than the recoverable amount of $2.5 billion. An impairment charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, there was no impairment of the Toledo CGU.

Key Assumptions

The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads were based on an average of third-party consultant forecasts.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Crude Oil and Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2021, the forward prices used to determine future cash flows were:

	2022 to 2023		2024 to 2026
(US$/barrel)	Low	High	Low	High
West Texas Intermediate	68.78	72.83	66.76	69.45
Differential WTI-WTS	—	0.01	(0.06)	(0.06)
Differential WTI-WCS	13.54	13.67	13.75	14.30
Chicago 3-2-1 Crack Spreads (WTI)	14.87	18.44	14.68	16.81

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2037.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent to 12 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have had on the calculated recoverable amounts used in the impairment testing completed as at December 31, 2021, for the following CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Borger, Wood River and Lima	251	(283)	(990)	996

iii) 2020 Impairment Charges and Reversals

As at September 30, 2020, the recovery in demand for refined products from the impact of the novel coronavirus lagged expectations and resulted in higher than anticipated inventory levels. These factors, along with low market crack spreads and crude oil processing runs for North American refineries, were identified as indicators of impairment for the Wood River and Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was greater than the recoverable amount and an impairment charge of $450 million was recorded as additional DD&A in the U.S. Manufacturing segment. The recoverable amount of the Borger CGU was estimated at $692 million. As at September 30, 2020, no impairment of the Wood River CGU was identified.

Key Assumptions

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs, terminal values and the discount rate. Forward crack spreads were based on third-party consultant average forecasts.

Crude Oil and Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were:

	2021 to 2022		2023 to 2025
(US$/barrel)	Low	High	Low	High
West Texas Intermediate	36.36	50.84	49.66	58.74
Differential WTI-WTS	0.37	1.73	1.21	1.81
Group 3 3-2-1 Crack Spreads (WTI)	11.56	13.23	11.79	16.58

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 42

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount used in the impairment testing completed as at September 30, 2020, for the following CGU:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Borger	89	(110)	(348)	342

12. OTHER INCOME (LOSS), NET

For the year ended December 31, 2022, the Company recorded insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region of $328 million (2021 – $120 million; 2020 – $nil).

For the year ended December 31, 2022, funding of $65 million (2021 – $42 million; 2020 – $nil) was received under the Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites.

13. INCOME TAXES

A) Income Tax Expense (Recovery)

For the years ended December 31,	2022	2021	2020
Current Tax
Canada	1,252	104	(14)
United States	104	—	1
Asia Pacific	262	171	—
Other International	21	1	—
Total Current Tax Expense (Recovery)	1,639	276	(13)
Deferred Tax Expense (Recovery)	642	452	(838)
	2,281	728	(851)

For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income.

In 2021, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The increase is due to Asia Pacific operations acquired in the Arrangement and higher earnings compared to 2020. In 2021, the Company recorded a $217 million deferred tax expense due to a limitation in the availability of certain U.S. tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate change associated with provincial allocations.

In 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU, impairments in the Conventional segment and current period operating losses that will be carried forward, excluding unrealized foreign exchange gains and losses on long-term debt. In 2020, the Government of Alberta accelerated the reduction in the provincial corporate tax rate from 12 percent to eight percent.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

For the years ended December 31,	2022		2021		2020
Earnings (Loss) From Operations Before Income Tax	8,731		1,315		(3,230)
Canadian Statutory Rate	23.7	%	23.7	%	24.0	%
Expected Income Tax Expense (Recovery) From Operations	2,069		312		(775)
Effect on Taxes Resulting From:
Statutory and Other Rate Differences	17		3		19
Non-Taxable Capital (Gains) Losses	84		63		(42)
Non-Recognition of Capital (Gains) Losses	84		27		(42)
Adjustments Arising From Prior Year Tax Filings	15		(5)		(8)
U.S. Tax Attribute Limitation	—		217		—
Impact of Rate Changes	—		106		(7)
Other	12		5		4
Total Tax Expense (Recovery) From Operations	2,281		728		(851)
Effective Tax Rate	26.1	%	55.4	%	26.3	%

B) Deferred Income Tax Assets and Liabilities

For the year ended December 31, 2022, deferred income tax liabilities of $486 million were recognized on the Sunrise Acquisition. The deferred income tax liability arises from the difference between the fair value of the assets acquired and the liabilities assumed, and their tax basis.

On January 1, 2021, as part of the Arrangement, the Company recorded net deferred tax assets of $1.1 billion. The net deferred tax assets consisted of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million related to U.S. operations, offset by a deferred tax liability of $444 million related to Asia Pacific activities. The Canadian deferred tax asset has been offset against the Canadian deferred tax liability.

The breakdown of deferred income tax liabilities and deferred income tax assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows:

For the years ended December 31,	2022	2021
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled Within Twelve Months	55	—
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months	4,460	4,046
	4,515	4,046
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months	(31)	(556)
Deferred Income Tax Assets to be Settled After More Than Twelve Months	(747)	(898)
	(778)	(1,454)
Net Deferred Income Tax Liability	3,737	2,592

The deferred income tax assets and liabilities to be settled within twelve months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year.

The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is:

Deferred Income Tax Liabilities	PP&E	Risk Management	Other	Total
As at December 31, 2020	4,124	—	22	4,146
Charged (Credited) to Earnings	(234)	—	75	(159)
Charged (Credited) to Husky Purchase Price Allocation	59	—	—	59
As at December 31, 2021	3,949	—	97	4,046
Charged (Credited) to Earnings	25	11	(53)	(17)
Charged (Credited) to Sunrise Purchase Price Allocation	486	—	—	486
As at December 31, 2022	4,460	11	44	4,515

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 44

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Deferred Income Tax Assets	Unused Tax Losses	Risk Management	Other	Total
As at December 31, 2020	(659)	(13)	(276)	(948)
Charged (Credited) to Earnings	668	1	(58)	611
Charged (Credited) to Husky Purchase Price Allocation	(656)	1	(466)	(1,121)
Charged (Credited) to Other Comprehensive Income	(8)	—	12	4
As at December 31, 2021	(655)	(11)	(788)	(1,454)
Charged (Credited) to Earnings	490	11	158	659
Charged (Credited) to Sunrise Purchase Price Allocation	—	—	—	—
Charged (Credited) to Other Comprehensive Income	9	—	8	17
As at December 31, 2022	(156)	—	(622)	(778)

Net Deferred Income Tax Liabilities	Total
As at December 31, 2020	3,198
Charged (Credited) to Earnings	452
Charged (Credited) to Husky Purchase Price Allocation	(1,062)
Charged (Credited) to Other Comprehensive Income	4
As at December 31, 2021	2,592
Charged (Credited) to Earnings	642
Charged (Credited) to Sunrise Purchase Price Allocation	486
Charged (Credited) to Other Comprehensive Income	17
As at December 31, 2022	3,737

The deferred income tax asset of $546 million (2021 – $694 million) represents net deductible temporary differences in the U.S. jurisdiction which has been fully recognized, as the probability of realization is expected due to forecasted taxable income. No deferred tax liability has been recognized as at December 31, 2022 and 2021 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future.

C) Tax Pools

The approximate amounts of tax pools available, including tax losses, are:

As at December 31,	2022	2021
Canada	8,505	11,167
United States	6,477	5,915
Asia Pacific	457	600
	15,439	17,682

As at December 31, 2022, the above tax pools included $115 million (December 31, 2021 – $1.5 billion) of Canadian federal non-capital losses and $468 million (December 31, 2021 – $775 million) of U.S. net operating losses. These losses expire no earlier than 2035.

As at December 31, 2022, the Company had Canadian net capital losses totaling $28 million (December 31, 2021 – $102 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $504 million (December 31, 2021 – $102 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

14. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Common Share – Basic and Diluted

For the years ended December 31,	2022	2021	2020
Net Earnings (Loss)	6,450	587	(2,379)
Effect of Cumulative Dividends on Preferred Shares	(35)	(34)	—
Net Earnings (Loss) – Basic and Diluted	6,415	553	(2,379)
Basic – Weighted Average Number of Shares	1,951.3	2,016.2	1,228.9
Dilutive Effect of Warrants	44.8	27.6	—
Dilutive Effect of Net Settlement Rights	10.0	1.3	—
Diluted – Weighted Average Number of Shares	2,006.1	2,045.1	1,228.9
Net Earnings (Loss) Per Common Share – Basic ($)	3.29	0.27	(1.94)
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)	3.20	0.27	(1.94)

(1)For the year ended December 31, 2022, net earnings of $52 million (2021 – $22 million; 2020 – $nil) and common shares of 1.6 million (2021 – 1.9 million; 2020 – nil) related to the assumed exercise of the Cenovus replacement stock options, were excluded from the calculation of dilutive net earnings (loss) per share. For further information on the Company’s stock-based compensation plans, see Note 34.

(2)For the year ended December 31, 2021 and December 31, 2020, NSRs of 18 million and 31 million, respectively, were excluded from the calculation of diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceeded the market price of Cenovus’s common shares.

B) Common Share Dividends

	2022		2021		2020
For the years ended December 31,	Per Share	Amount	Per Share	Amount	Per Share	Amount
Base Dividends	0.350	682	0.088	176	0.063	77
Variable Dividends	0.114	219	—	—	—	—
Total Common Share Dividends Declared and Paid	0.464	901	0.088	176	0.063	77

The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.

On February 15, 2023, the Company’s Board of Directors declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023.

C) Preferred Share Dividends

For the years ended December 31,	2022	2021
Series 1 First Preferred Shares	7	7
Series 2 First Preferred Shares	1	1
Series 3 First Preferred Shares	12	12
Series 5 First Preferred Shares	9	9
Series 7 First Preferred Shares	6	5
Total Preferred Share Dividends Declared	35	34

The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.

On January 3, 2023, the Company paid dividends on Cenovus’s preferred shares as declared on November 1, 2022.

On February 15, 2023, the Company’s Board of Directors declared first quarter dividends for Cenovus’s preferred shares, payable on March 31, 2023, in the amount of $9 million, to preferred shareholders of record as at March 15, 2023.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

15. CASH AND CASH EQUIVALENTS

As at December 31,	2022	2021
Cash	3,195	2,366
Short-Term Investments	1,329	507
	4,524	2,873

16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES

As at December 31,	2022	2021
Trade and Accruals	2,962	2,548
Prepaids and Deposits	402	486
Partner Advances	—	371
Joint Operations Receivables	51	225
Other (1)	58	240
	3,473	3,870

(1)As at December 31, 2022, includes insurance proceeds receivable of $nil related to the 2018 Superior Refinery incident (December 31, 2021 – $135 million).

17. INVENTORIES

As at December 31,	2022	2021
Product
Crude Oil	2,424	2,060
Diluent	366	515
Natural Gas and NGLs	50	33
Refined Products	1,169	1,043
Total Product	4,009	3,651
Parts and Supplies	303	268
	4,312	3,919

For the year ended December 31, 2022, approximately $49 billion of produced and purchased inventory was recorded as an expense (2021 – approximately $34 billion).

18. ASSETS HELD FOR SALE

The Company had the following assets held for sale as at December 31, 2021, that were sold in 2022 (see Note 10):

	PP&E	ROU Assets	Goodwill	Lease Liabilities	Decommissioning Liabilities
Retail Gas Stations	498	54	—	(58)	(86)
Tucker	505	—	88	—	(33)
Wembley	159	—	—	—	(9)
	1,162	54	88	(58)	(128)

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

19. EXPLORATION AND EVALUATION ASSETS, NET

	Total
As at December 31, 2020	623
Acquisitions (Note 5)	45
Additions	55
Write-downs	(9)
Change in Decommissioning Liabilities	6
As at December 31, 2021	720
Additions	37
Write-downs	(64)
Change in Decommissioning Liabilities	(12)
Exchange Rate Movements and Other (1)	4
As at December 31, 2022	685

(1)Immediately prior to the Sunrise Acquisition, Bay du Nord had a carrying value of $nil. The Company re-measured its interest in Bay du Nord to $40 million and recognized a revaluation gain of $40 million.

For the year ended December 31, 2022, $2 million and $62 million of previously capitalized E&E costs were written off as exploration expense in the Oil Sands segment and Offshore segment, respectively (2021 – $9 million in the Oil Sands segment), as the carrying value was not considered to be recoverable.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

20. PROPERTY, PLANT AND EQUIPMENT, NET

	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Manufacturing Assets	Other Assets (1)	Total
COST
As at December 31, 2020	29,867	218	5,671	1,290	37,046
Acquisitions (Note 5)	8,633	—	3,901	846	13,380
Additions	1,368	9	1,023	115	2,515
Change in Decommissioning Liabilities	(63)	1	40	24	2
Divestitures (Note 10)	(630)	—	—	—	(630)
Transfers to Assets Held for Sale (Note 18)	(754)	—	—	(522)	(1,276)
Exchange Rate Movements and Other	22	—	(140)	(18)	(136)
As at December 31, 2021	38,443	228	10,495	1,735	50,901
Acquisitions (Note 5) (2)	3,230	—	—	—	3,230
Additions	2,409	11	1,143	108	3,671
Change in Decommissioning Liabilities	(186)	(6)	(29)	(32)	(253)
Divestitures (Note 5) (2)	(557)	—	—	—	(557)
Exchange Rate Movements and Other	189	21	523	14	747
As at December 31, 2022	43,528	254	12,132	1,825	57,739
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2020	8,361	42	2,195	1,037	11,635
Depreciation, Depletion and Amortization	3,335	10	526	128	3,999
Impairment Charges (Note 11)	—	—	1,931	—	1,931
Impairment Reversals (Note 11)	(378)	—	—	—	(378)
Divestitures (Note 10)	(377)	—	—	—	(377)
Transfers to Assets Held for Sale (Note 18)	(90)	—	—	(24)	(114)
Exchange Rate Movements and Other	61	1	(80)	(2)	(20)
As at December 31, 2021	10,912	53	4,572	1,139	16,676
Depreciation, Depletion and Amortization (3)	3,461	37	466	103	4,067
Impairment Charges (Note 11)	—	—	1,499	—	1,499
Impairment Reversals (Note 11)	—	—	(1,233)	—	(1,233)
Divestitures (Note 5) (2)	(84)	—	—	—	(84)
Exchange Rate Movements and Other	13	16	243	43	315
As at December 31, 2022	14,302	106	5,547	1,285	21,240
CARRYING VALUE
As at December 31, 2020	21,506	176	3,476	253	25,411
As at December 31, 2021	27,531	175	5,923	596	34,225
As at December 31, 2022	29,226	148	6,585	540	36,499

(1)Includes assets within the commercial and retail fuels businesses, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2)In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million.

(3)DD&A includes asset write-downs of $26 million in the Offshore segment and $25 million in the Canadian Manufacturing segment.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Assets Under Construction

PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A:

As at December 31,	2022	2021
Development and Production	2,142	2,415
Downstream	137	943
	2,279	3,358

21. RIGHT-OF-USE ASSETS, NET

	Real Estate	Transportation and Storage Assets (1)	Manufacturing Assets	Other Assets (2)	Total
COST
As at December 31, 2020	495	977	15	15	1,502
Acquisitions (Note 5)	99	765	138	130	1,132
Additions	4	96	7	3	110
Modifications	1	20	1	—	22
Re-measurements	(2)	1	—	(3)	(4)
Transfers to Assets Held for Sale (Note 18)	—	—	—	(78)	(78)
Exchange Rate Movements and Other	(5)	(18)	—	(5)	(28)
As at December 31, 2021	592	1,841	161	62	2,656
Additions	—	22	1	2	25
Modifications	9	69	3	2	83
Re-measurements	1	3	2	1	7
Terminations	(1)	(6)	(2)	(1)	(10)
Exchange Rate Movements and Other	(2)	(89)	9	8	(74)
As at December 31, 2022	599	1,840	174	74	2,687
ACCUMULATED DEPRECIATION
As at December 31, 2020	58	293	5	7	363
Depreciation	38	239	23	23	323
Impairment Charges (Note 11)	—	5	5	1	11
Terminations	—	(3)	—	—	(3)
Transfers to Assets Held for Sale (Note 18)	—	—	—	(24)	(24)
Exchange Rate Movements and Other	(4)	(14)	—	(6)	(24)
As at December 31, 2021	92	520	33	1	646
Depreciation	36	226	21	14	297
Terminations	—	(6)	—	—	(6)
Exchange Rate Movements and Other	(1)	(95)	4	(3)	(95)
As at December 31, 2022	127	645	58	12	842
CARRYING VALUE
As at December 31, 2020	437	684	10	8	1,139
As at December 31, 2021	500	1,321	128	61	2,010
As at December 31, 2022	472	1,195	116	62	1,845

(1)Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.

(2)Includes assets within the commercial fuels business, fleet vehicles and other equipment.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

22. JOINT ARRANGEMENTS

A) Joint Operations

Cenovus has a number of joint operations in the Upstream segments. The Company also has the following joint operations held in separate entities in the U.S. Manufacturing segment.

BP-Husky Refining LLC

Cenovus holds a 50 percent interest in the Toledo Refinery with BP. BP is the operator of the refinery in Ohio and holds the remaining 50 percent interest. On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest. See Note 5 for further details.

WRB Refining LP

Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. Phillips 66 holds the remaining 50 percent interest and is the operator of the Wood River Refinery in Illinois and the Borger Refinery in Texas.

B) Joint Ventures

Husky-CNOOC Madura Ltd.

The Company holds a 40 percent interest in the jointly controlled entity, HCML, which is engaged in the exploration for and production of natural gas and NGLs in offshore Indonesia. The Company’s share of equity investment income (loss) related to the joint venture is included in the Consolidated Statements of Earnings (Loss) in the Offshore segment.

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations

For the years ended December 31,	2022	2021
Revenue	383	439
Expenses	350	395
Net Earnings (Loss)	33	44

Balance Sheet

As at December 31,	2022	2021
Current Assets (1)	247	167
Non-Current Assets	1,926	1,433
Current Liabilities	160	62
Non-Current Liabilities	1,293	896
Net Assets	720	642

(1)Includes cash and cash equivalents of $64 million (December 31, 2021 – $46 million).

For the year ended December 31, 2022, the Company’s share of income from the equity-accounted affiliate was $23 million (2021 – $47 million). As at December 31, 2022, the carrying amount of the Company’s share of net assets was $365 million (December 31, 2021 – $311 million). These amounts do not equal the 40 percent joint control of the revenues, expenses and net assets of HCML due to differences in the values attributed to the investment and accounting policies between the joint venture and the Company.

For the year ended December 31, 2022, the Company received $42 million of distributions from HCML (2021 – $100 million) and paid $54 million in contributions (2021 – $18 million).

Husky Midstream Limited Partnership

The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power Assets Holdings Ltd. holding a 49 percent interest and CK Infrastructure Holdings Ltd. holding a 16 percent interest in HMLP.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

For the year ended December 31, 2022, HMLP had net earnings of $190 million (2021 – $134 million). The Company’s share of (income) loss from the equity-accounted affiliate does not equal the 35 percent of the net earnings of HMLP due to the nature of the profit-sharing arrangement as defined in the partnership agreement. The Company’s share of earnings will fluctuate depending on certain income thresholds of HMLP. For the year ended December 31, 2022, the Company did not record its share of pre-tax loss relating to HMLP of $23 million (2021 – loss of $22 million). The carrying value was $nil at December 31, 2022 and December 31, 2021.

As at December 31, 2022, the Company had $28 million in cumulative unrecognized losses and OCI, net of tax (December 31, 2021 – $17 million). The Company records its share of equity investment income related to the joint venture only in excess of the cumulated unrecognized loss and is included in the Consolidated Statements of Earnings (Loss) in the Oil Sands segment.

For the year ended December 31, 2022, the Company received $23 million of distributions from HMLP (2021 – $37 million) and paid $31 million in contributions (2021 – $32 million) to HMLP. The net amount of the distributions received and contributions paid are recorded in earnings from equity-accounted affiliates.

23. OTHER ASSETS

As at December 31,	2022	2021
Intangible Assets (1)	19	78
Private Equity Investments (Note 37)	55	53
Other Equity Investments	—	77
Net Investment in Finance Leases	62	60
Long-Term Receivables and Prepaids	120	77
Precious Metals	86	85
Other	—	1
	342	431

(1)    For the twelve months ended December 31, 2022, $49 million of previously capitalized intangible asset costs were written off as DD&A in the Oil Sands segment as the carrying value was not considered to be recoverable.

In December 2021, all of the outstanding share purchase warrants received in the sale of the Company's Marten Hills assets to Headwater were exercised for a total cost of $30 million. At December 31, 2021, the fair value of the Headwater investment was $77 million, included in other equity investments above. The investment was carried at FVTPL.

On June 8, 2022, the Company sold its investment in Headwater for proceeds of $110 million.

24. GOODWILL

	2022	2021
Carrying Value, Beginning of Year	3,473	2,272
Goodwill Recognized (Note 5)	—	1,289
Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18)	(550)	(88)
Carrying Value, End of Year	2,923	3,473

The carrying amount of goodwill is allocated to the following CGUs:

As at December 31,	2022	2021
Primrose (Foster Creek)	1,171	1,171
Christina Lake	1,101	1,101
Lloydminster Thermal	651	651
Sunrise (Note 5)	—	550
	2,923	3,473

For the purposes of impairment testing, goodwill is allocated to the CGUs to which it relates. The assumptions used to test Cenovus's goodwill for impairment as at December 31, 2022, are consistent with those disclosed in Note 11. There was no impairment of goodwill as at December 31, 2022 (December 31, 2021 – $nil).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

25. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

As at December 31,	2022	2021
Accruals	3,412	2,722
Trade	2,331	2,554
Interest	80	128
Partner Advances	—	371
Employee Long-Term Incentives	162	317
Joint Operations Payable	66	28
Risk Management	39	116
Provisions for Onerous and Unfavourable Contracts	25	31
Other	9	86
	6,124	6,353

26. DEBT AND CAPITAL STRUCTURE

For the year ended December 31, 2022, the weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings was 4.7 percent (December 31, 2021 – 4.6 percent).

A) Short-Term Borrowings

As at December 31,	Notes	2022	2021
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	115	79
Total Debt Principal		115	79

i) Uncommitted Demand Facilities

As at December 31, 2022, and December 31, 2021, the Company had uncommitted demand facilities of $1.9 billion in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at December 31, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no direct borrowings.

As at December 31, 2021, SOSP had an uncommitted demand credit facility of $10 million (the Company’s proportionate share – $5 million). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility.

ii) WRB Uncommitted Demand Facilities

As at December 31, 2022, WRB had uncommitted demand facilities of US$450 million (the Company’s proportionate share –US$225 million), which may be used to cover short-term working capital requirements (December 31, 2021 – US$300 million (the Company’s proportionate share – US$150 million)). As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US$63 million (C$79 million)).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

B) Long-Term Debt

As at December 31,	Notes	2022	2021
Committed Credit Facility (1)	i	—	—
U.S. Dollar Denominated Unsecured Notes	ii	6,537	9,363
Canadian Dollar Unsecured Notes	ii	2,000	2,750
Total Debt Principal		8,537	12,113
Debt Premiums (Discounts), Net, and Transaction Costs		154	272
Long-Term Debt		8,691	12,385

(1)The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

i) Committed Credit Facility

At the closing of the Arrangement on January 1, 2021, the Company assumed Husky's committed credit facilities of $4.0 billion, with $350 million outstanding. In August 2021, $8.5 billion of committed facilities, which includes those assumed in the Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility.

On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to $5.5 billion and to extend the maturity dates by more than one year. The committed credit facility consists of a $1.8 billion tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at December 31, 2022, no amounts were drawn on the credit facility (December 31, 2021 – $nil).

ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes

For the year ended December 31, 2022, and December 31, 2021, Cenovus purchased outstanding principal amounts of the following unsecured notes:

	2022	2021
	US$ Principal	US$ Principal
U.S. Dollar Unsecured Notes
3.95% due April 15, 2022	—	500
3.00% due August 15, 2022	—	500
3.80% due September 15, 2023	115	335
4.00% due April 15, 2024	269	481
5.38% due July 15, 2025	533	334
4.25% due April 15, 2027	589	—
4.40% due April 15, 2029	510	—
6.75% due November 15, 2039	455	—
4.45% due September 15, 2042	58	—
5.20% due September 15, 2043	29	—
	2,558	2,150

	C$ Principal	C$ Principal
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025	750	—

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

The principal amounts of the Company’s outstanding unsecured notes are:

	2022		2021
As at December 31,	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Denominated Unsecured Notes
3.80% due September 15, 2023	—	—	115	146
4.00% due April 15, 2024	—	—	269	341
5.38% due July 15, 2025	133	181	666	844
4.25% due April 15, 2027	373	505	962	1,220
4.40% due April 15, 2029	240	324	750	951
2.65% due January 15, 2032	500	677	500	634
5.25% due June 15, 2037	583	790	583	739
6.80% due September 15, 2037	387	524	387	490
6.75% due November 15, 2039	935	1,267	1,390	1,763
4.45% due September 15, 2042	97	131	155	197
5.20% due September 15, 2043	29	39	58	73
5.40% due June 15, 2047	800	1,083	800	1,014
3.75% due February 15, 2052	750	1,016	750	951
	4,827	6,537	7,385	9,363
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025		—		750
3.60% due March 10, 2027		750		750
3.50% due February 7, 2028		1,250		1,250
		2,000		2,750
Total Unsecured Notes		8,537		12,113

At the closing of the Arrangement on January 1, 2021, the Company assumed Canadian dollar unsecured notes with a fair value of $2.9 billion (notional value – $2.8 billion) and U.S. dollar denominated notes with a fair value of $3.4 billion (notional value – US$2.4 billion or C$3.0 billion). The Company closed a public offering in the U.S. in September 2021, for US$1.25 billion of senior unsecured notes, consisting of US$500 million due on January 15, 2032, and US$750 million due on February 15, 2052.

As at December 31, 2022, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is well below this limit.

C) Mandatory Debt Payments

	U.S. Dollar Unsecured Notes		Canadian Dollar Unsecured Notes	Total
As at December 31, 2022	US$ Principal	C$ Principal Equivalent	C$ Principal	C$ Principal and Equivalent
2023	—	—	—	—
2024	—	—	—	—
2025	133	181	—	181
2026	—	—	—	—
2027	373	505	750	1,255
Thereafter	4,321	5,851	1,250	7,101
	4,827	6,537	2,000	8,537

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

D) Capital Structure

Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. Net Debt is used in managing the Company’s capital structure. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase the Company’s common shares or preferred shares for cancellation, issue new debt, or issue new shares.

Cenovus monitors its capital structure and financing requirements using, among other things, specified financial measures consisting of Total Debt, Net Debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Net Debt to Adjusted Funds Flow was a new metric as at March 31, 2022.

Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times and Net Debt at or below $4 billion over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices.

On October 7, 2021, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus will expire in November 2023. Offerings under the base shelf prospectus are subject to market conditions. As at December 31, 2022, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings.

Net Debt to Adjusted EBITDA

As at December 31,	2022	2021	2020
Short-Term Borrowings	115	79	121
Current Portion of Long-Term Debt	—	—	—
Long-Term Portion of Long-Term Debt	8,691	12,385	7,441
Total Debt	8,806	12,464	7,562
Less: Cash and Cash Equivalents	(4,524)	(2,873)	(378)
Net Debt	4,282	9,591	7,184
Net Earnings (Loss)	6,450	587	(2,379)
Add (Deduct):
Finance Costs	820	1,082	536
Interest Income	(81)	(23)	(9)
Income Tax Expense (Recovery)	2,281	728	(851)
Depreciation, Depletion and Amortization	4,679	5,886	3,464
E&E Asset Write-downs	64	18	91
(Income) Loss From Equity-Accounted Affiliates	(15)	(57)	—
Unrealized (Gain) Loss on Risk Management	(126)	2	56
Foreign Exchange (Gain) Loss, Net	343	(174)	(181)
Revaluation (Gains)	(549)	—	—
Re-measurement of Contingent Payments	162	575	(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)	(81)
Other (Income) Loss, Net	(532)	(309)	40
Adjusted EBITDA (1)	13,227	8,086	606
Net Debt to Adjusted EBITDA	0.3x	1.2x	11.9x

(1)Calculated on a trailing twelve-month basis.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Net Debt to Adjusted Funds Flow

As at December 31,	2022	2021	2020
Net Debt	4,282	9,591	7,184
Cash From (Used in) Operating Activities	11,403	5,919	273
(Add) Deduct:
Settlement of Decommissioning Liabilities	(150)	(102)	(42)
Net Change in Non-Cash Working Capital	575	(1,227)	198
Adjusted Funds Flow (1)	10,978	7,248	117
Net Debt to Adjusted Funds Flow	0.4x	1.3x	61.4x

(1)    Calculated on a trailing twelve-month basis.

Net Debt to Capitalization

As at December 31,	2022		2021		2020
Net Debt	4,282		9,591		7,184
Shareholders’ Equity	27,576		23,596		16,707
Capitalization	31,858		33,187		23,891
Net Debt to Capitalization	13	%	29	%	30	%

27. LEASE LIABILITIES

	2022	2021
Lease Liabilities, Beginning of Year	2,957	1,757
Acquisitions (Note 5)	—	1,441
Additions	25	110
Interest Expense (Note 7)	163	171
Lease Payments	(465)	(471)
Modifications	83	22
Re-measurements	7	(4)
Terminations	(5)	(1)
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	—	(10)
Exchange Rate Movements and Other	71	(58)
Lease Liabilities, End of Year	2,836	2,957
Less: Current Portion	308	272
Long-Term Portion	2,528	2,685

The Company has lease liabilities for contracts related to office space, transportation and storage assets, which includes barges, vessels, pipelines, caverns, railcars and storage tanks, commercial fuel assets and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions.

The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are leases with terms of twelve months or less.

The Company includes extension options in the calculation of lease liabilities when the Company has the right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company does not have any significant termination options and the residual amounts are not material.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

28. CONTINGENT PAYMENTS

A) Sunrise Oil Sands Partnership

In connection with the Sunrise Acquisition (see Note 5), Cenovus agreed to make quarterly variable payments from SOSP to BP Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the term of the contract is $600 million.

The variable payment will continue to be re-measured at fair value at each reporting date until the earlier of the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed, with changes in fair value recognized in net earnings (loss).

The first quarterly period ended on November 30, 2022. A payment of $92 million was made in January 2023.

	Total
As at December 31, 2021	—
Initial Recognition	600
Liabilities Settled or Payable	(92)
Re-measurement (1)	(89)
As at December 31, 2022	419
Less: Current Portion	263
Long-Term Portion	156

(1)     The variable payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).

B) FCCL Partnership

On May 17, 2022, the contingent payment obligation associated with the acquisition of a 50 percent interest in the FCCL Partnership (“FCCL”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) ended. The final payment of $177 million was made in July 2022 (as at December 31, 2021 – $160 million was payable). In connection with the acquisition in 2017 from ConocoPhillips, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years ending May 17, 2022, for quarters in which the average WCS crude oil price exceeded $52.00 per barrel during the quarter. The quarterly payment was $6 million for each dollar that the WCS price exceeded $52.00 per barrel.

	2022	2021
Contingent Payment, Beginning of Year	236	63
Re-measurement (1)	251	575
Liabilities Settled	(487)	(402)
Contingent Payment, End of Year	—	236

(1)     The contingent payment was carried at fair value. Changes in fair value were recorded in net earnings (loss).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

29. DECOMMISSIONING LIABILITIES

The decommissioning provision represents the present value of the expected future costs associated with the retirement of producing well sites, upstream processing facilities, surface and subsea plant and equipment, manufacturing facilities, the commercial fuels facilities and the crude-by-rail terminal.

The aggregate carrying amount of the obligation is:

	2022	2021
Decommissioning Liabilities, Beginning of Year	3,906	1,248
Liabilities Incurred	22	30
Liabilities Acquired (Note 5) (1)	48	2,856
Liabilities Settled	(215)	(144)
Liabilities Divested (Note 5) (1)	(89)	(140)
Change in Estimated Future Cash Flows	693	(472)
Change in Discount Rates	(980)	450
Unwinding of Discount on Decommissioning Liabilities (Note 7)	176	199
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	—	(128)
Exchange Rate Movements and Other	(2)	7
Decommissioning Liabilities, End of Year	3,559	3,906

(1)     In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million.

As at December 31, 2022, the undiscounted amount of estimated future cash flows required to settle the obligation is $14 billion (December 31, 2021 – $14 billion). Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $250 million to $300 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning liabilities over the estimated life of the reserves and an increase in cost estimates. These obligations have been discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2021 – 4.4 percent) and assumes an inflation rate of two percent (December 31, 2021 – two percent).

The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2022, the Company had $209 million in restricted cash (December 31, 2021 – $186 million).

Sensitivities

Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:

	Sensitivity	2022		2021
As at December 31,	Range	Increase	Decrease	Increase	Decrease
Credit-Adjusted Risk-Free Rate	± one percent	(319)	419	(623)	875
Inflation Rate	± one percent	419	(320)	873	(625)

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

30. OTHER LIABILITIES

As at December 31,	2022	2021
Pension and Other Post-Employment Benefit Plan	201	288
Provision for West White Rose Expansion Project (1)	204	259
Provisions for Onerous and Unfavourable Contracts	95	99
Employee Long-Term Incentives	245	74
Drilling Provisions	31	56
Deferred Revenue	45	41
Other (2)	221	112
	1,042	929

(1)     On May 31, 2022, the Company divested of 12.5 percent of its working interest in the White Rose field and satellite extensions reducing the provision by $47 million (see Note 10). Cenovus expects to draw down the provision by $58 million in the next twelve months.

(2)     As at December 31, 2022, other includes a net RVO of $101 million. Gross amounts of the RVO and RINs asset were $1.1 billion and $1.0 billion, respectively.

31. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS

The Company provides the majority of employees with a defined contribution pension plan. The Company also provides OPEB plans to retirees and sponsors defined benefit pension plans in Canada and the U.S. (together, the “DB Pension Plan”).

The DB Pension Plan provides pension benefits at retirement based on years of service and final average earnings. In Canada, future enrollment is limited to eligible employees who may elect to move from the defined contribution component to the defined benefit component for their future service. In the U.S., the defined benefit pension is closed to new members. The Company’s OPEB plans provides certain retired employees with health care and dental benefits.

The Company is required to file an actuarial valuation of its registered defined benefit pension with regulators on a periodic basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2021, and the next required actuarial valuation will be as at December 31, 2024. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2022 and the next required actuarial valuation will be as at January 1, 2023.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:

	Pension Benefits		OPEB
	2022	2021	2022	2021
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year	220	188	225	20
Plan Acquisition Upon the Arrangement (1)	—	41	—	224
Current Service Costs	16	16	8	9
Past Service Costs - Curtailment and Plan Amendments	—	(1)	—	(3)
Interest Costs (2)	7	6	7	6
Benefits Paid	(12)	(17)	(8)	(8)
Plan Participant Contributions	2	2	—	—
Re-measurements:
(Gains) Losses From Experience Adjustments	1	4	(2)	10
(Gains) Losses From Changes in Demographic Assumptions	—	(1)	—	(3)
(Gains) Losses From Changes in Financial Assumptions	(64)	(18)	(57)	(30)
Exchange Rate Movements and Other	2	—	1	—
Defined Benefit Obligation, End of Year	172	220	174	225
Plan Assets
Fair Value of Plan Assets, Beginning of Year	159	117	—	—
Plan Acquisition Upon the Arrangement (1)	—	32	—	—
Employer Contributions	16	9	8	3
Plan Participant Contributions	2	2	—	—
Benefits Paid	(10)	(13)	(8)	(3)
Interest Income (2)	4	3	—	—
Re-measurements:
Return on Plan Assets (Excluding Interest Income)	(26)	9	—	—
Exchange Rate Movements and Other	2	—	—	—
Fair Value of Plan Assets, End of Year	147	159	—	—
Pension and OPEB (Liability) (3)	(25)	(61)	(174)	(225)

(1)The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5.

(2)Based on the discount rate of the defined benefit obligation at the beginning of the year.

(3)Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities on the Consolidated Balance Sheets.

The weighted average duration of the defined benefit pension and OPEB obligations are 14 years and 14 years, respectively.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

B) Pension and OPEB Costs

	Pension Benefits			OPEB
As at December 31,	2022	2021	2020	2022	2021	2020
Defined Benefit Plan Cost
Current Service Costs	16	16	13	8	9	1
Past Service Costs - Curtailments and Plan    Amendments	—	(1)	—	—	(3)	—
Net Interest Costs	3	3	3	7	6	—
Re-measurements:
Return on Plan Assets (Excluding    Interest Income)	26	(9)	(5)	—	—	—
(Gains) Losses From Experience    Adjustments	1	4	1	(2)	10	(2)
(Gains) Losses From Changes in    Demographic Assumptions	—	(1)	—	—	(3)	—
(Gains) Losses From Changes in Financial    Assumptions	(64)	(18)	15	(57)	(30)	1
Defined Benefit Plan Cost (Recovery)	(18)	(6)	27	(44)	(11)	—
Defined Contribution Plan Cost (1)	72	68	22	—	—	—
Total Plan Cost	54	62	49	(44)	(11)	—

(1)    Includes defined contribution and U.S. 401(k) plans.

C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the DB Pension Plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.

The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced as necessary. The Canadian defined benefit pension plan and U.S. defined benefit pension plan are managed independently of each other and, accordingly, the target asset allocation is reflective of their different liability profiles.

2022 Target Allocation (percent)	Canadian Plan	U.S. Plan
Equity Funds	25% - 75%	21% - 51%
Fixed Income Funds	20% - 50%	55% - 74%
Real Estate Funds	—% - 15%	—	%
Listed Infrastructure Funds	—% - 10%	—	%
Emerging Market Debt Funds	—% - 10%	—	%
Cash and Cash Equivalents	—% - 10%	—	%

The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

The fair value of the DB Pension Plan assets is:

As at December 31,	2022	2021
Equity Funds	68	77
Fixed Income Funds	50	54
Real Estate Funds	9	9
Listed Infrastructure Funds	7	8
Emerging Market Debt Funds	5	8
Cash and Cash Equivalents	7	2
Non-Invested Assets	1	1
Total Fair Value of DB Pension Plan Assets	147	159

Fair value of the cash and cash equivalents, equity, fixed income and listed infrastructure assets are based on the trading price of the underlying funds (Level 1). The fair value of the real estate funds reflects the appraisal valuation for each property investment (Level 2). The fair value of the non-invested assets is the discounted value of the expected future payments (Level 3).

The DB Pension Plan does not hold any direct investment in Cenovus common shares or preferred shares.

D) Funding

The DB Pension Plan is funded in accordance with applicable pension legislation. Contributions are made to trust funds administered by independent trustees. The Company’s contributions to the DB Pension Plan are based on the most recent actuarial valuations, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors.

Employees participating in the Canadian defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. In the year ended December 31, 2023, the Company expects to contribute $10 million for the DB Pension Plan.

The OPEB plans are funded on an as required basis. In the year ended December 31, 2023, the Company expects to contribute $10 million for the OPEB plans.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:

	Pension Benefits						OPEB
For the years ended December 31,	2022		2021		2020		2022		2021		2020
Discount Rate	5.12	%	2.95	%	2.50	%	5.13	%	2.98	%	2.50	%
Future Salary Growth Rate	4.05	%	4.03	%	3.97	%	N/A		4.94	%	4.94	%
Average Longevity (years)	88.4		88.3		88.3		88.4		88.3		88.2
Health Care Cost Trend Rate	N/A		N/A		N/A		5.24	%	5.64	%	6.00	%

Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Sensitivities

Of the most significant actuarial assumptions, a change in discount rates and health care costs have the largest potential impact on the obligations for the DB Pension Plan and OPEB plans, with sensitivity to change as follows:

	2022		2021
As at December 31,	Increase	Decrease	Increase	Decrease
One Percent Change:
Discount Rate	(43)	51	(59)	76
Future Salary Growth Rate	3	(3)	4	(4)
Health Care Cost Trend Rate	19	(17)	26	(20)
One Year Change in Assumed Life Expectancy	10	(10)	4	(4)

The sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, the changes in some assumptions may be correlated. The same methodologies have been used to calculate the sensitivity of the DB Pension Plan obligation to significant actuarial assumptions as have been applied when calculating the liability for the DB Pension Plan recorded on the Consolidated Balance Sheets.

32. SHARE CAPITAL AND WARRANTS

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject to the Company’s articles.

B) Issued and Outstanding – Common Shares

	2022		2021
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	2,001,211	17,016	1,228,870	11,040
Issued Under the Arrangement, Net of Issuance Costs (Note 5)	—	—	788,518	6,111
Issued Upon Exercise of Warrants	9,399	93	314	3
Issued Under Stock Option Plans	11,069	170	535	7
Purchase of Common Shares under NCIBs	(112,489)	(959)	(17,026)	(145)
Outstanding, End of Year	1,909,190	16,320	2,001,211	17,016

As at December 31, 2022, there were 43 million (December 31, 2021 – 30 million) common shares available for future issuance under the stock option plan.

C) Normal Course Issuer Bid

On November 4, 2021, the TSX accepted the Company’s implementation of an NCIB to purchase up to 146.5 million common shares between November 9, 2021, and November 8, 2022. On November 7, 2022, the Company received approval from the TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period from November 9, 2022, to November 8, 2023.

For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares (December 31, 2021 – 17 million) through the NCIBs. The shares were purchased at a volume weighted average price of $22.49 per common share (December 31, 2021 – $15.56) for a total of $2.5 billion (December 31, 2021 – $265 million). Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value.

From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

D) Issued and Outstanding – Preferred Shares

For the year ended December 31, 2022, there were no preferred shares issued. As at December 31, 2022, there were 36 million preferred shares outstanding (December 31, 2021 – 36 million), with a carrying value of $519 million (December 31, 2021 – $519 million).

As at December 31, 2022	Dividend Reset Date	Dividend Rate		Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	%	10,740
Series 2 First Preferred Shares (1)	Quarterly	5.86	%	1,260
Series 3 First Preferred Shares	December 31, 2024	4.69	%	10,000
Series 5 First Preferred Shares	March 31, 2025	4.59	%	8,000
Series 7 First Preferred Shares	June 30, 2025	3.94	%	6,000

(1)The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June 30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 – 1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023.

Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such option to convert their shares into the other series.

Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1), 3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6) and 3.52 percent (series 8).

Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Second Preferred Shares

There were no second preferred shares outstanding as at December 31, 2022 (December 31, 2021 – nil).

E) Issued and Outstanding – Warrants

	2022		2021
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	65,119	215	—	—
Issued Under the Arrangement (Note 5)	—	—	65,433	216
Exercised	(9,399)	(31)	(314)	(1)
Outstanding, End of Year	55,720	184	65,119	215

The exercise price of the Cenovus warrants is $6.54 per share.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

F) Paid in Surplus

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as Ovintiv Inc. ("Ovintiv")) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 34 and the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIBs.

	Retained Earnings Prior to Ovintiv Split	Stock-Based Compensation	Common Shares	Total
As at December 31, 2020	4,086	305	—	4,391
Stock-Based Compensation Expense	—	14	—	14
Purchase of Common Shares Under NCIBs	—	—	(120)	(120)
Common Shares Issued on Exercise of Stock Options	—	(1)	—	(1)
As at December 31, 2021	4,086	318	(120)	4,284
Stock-Based Compensation Expense	—	10	—	10
Purchase of Common Shares Under NCIBs	—	—	(1,571)	(1,571)
Common Shares Issued on Exercise of Stock Options	—	(32)	—	(32)
As at December 31, 2022	4,086	296	(1,691)	2,691

33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Pension and Other Post-Retirement Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
As at December 31, 2020	(10)	27	758	775
Other Comprehensive Income (Loss), Before Tax	47	—	(129)	(82)
Income Tax (Expense) Recovery	(9)	—	—	(9)
As at December 31, 2021	28	27	629	684
Other Comprehensive Income (Loss), Before Tax	96	2	713	811
Income Tax (Expense) Recovery	(25)	—	—	(25)
As at December 31, 2022	99	29	1,342	1,470

34. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Options

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market value for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.

Options issued by the Company have associated NSRs. The NSRs, in lieu of exercising the option, gives the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the excess of the market price received from the sale of the common shares over the exercise price of the option.

The NSRs vest and expire under the same terms and conditions as the underlying options.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Stock Options With Associated Net Settlement Rights

The weighted average unit fair value of NSRs granted during the year ended December 31, 2022, was $19.94 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	1.84	%
Expected Dividend Yield	0.72	%
Expected Volatility (1)	24.72	%
Expected Life (years)	5.75

(1)Expected volatility has been based on historical share volatility of the Company.

The following tables summarize information related to the NSRs:

	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
For the year ended December 31, 2022	(thousands)	($)
Outstanding, Beginning of Year	27,233	13.06
Granted	2,031	19.94
Exercised	(11,599)	12.77
Forfeited	(258)	9.75
Expired	(3,058)	22.25
Outstanding, End of Year	14,349	12.38

	Outstanding			Exercisable
As at December 31, 2022	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
Range of Exercise Price ($)	(thousands)	(Years)	($)	(thousands)	($)
5.00 to 9.99	5,234	4.88	8.76	1,474	8.94
10.00 to 14.99	6,229	3.80	12.01	4,280	12.13
15.00 to 19.99	2,834	4.26	19.71	919	19.36
20.00 to 24.99	52	6.69	22.37	—	—
	14,349	4.30	12.38	6,673	12.42

Cenovus Replacement Stock Options

For the year ended December 31, 2022, 6,042 thousand Cenovus replacement stock options, with a weighted average exercise price of $16.57, were exercised and net settled for cash and 103 thousand Cenovus replacement stock options were exercised with a weighted average exercise price of $14.98 and settled for 81 thousand common shares.

The Company recorded a liability of $42 million as at December 31, 2022, (December 31, 2021 – $30 million) in the Consolidated Balance Sheets for Cenovus Replacement Stock Options based on the fair value at year end using the Black-Scholes-Merton valuation model.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

The following tables summarize the information related to the Cenovus replacement stock options:

	Number of Cenovus Replacement Stock Options	Weighted Average Exercise Price
For the year ended December 31, 2022	(thousands)	($)
Outstanding, Beginning of Year	12,256	15.21
Exercised	(6,145)	16.12
Forfeited	(186)	15.85
Expired	(2,458)	20.59
Outstanding, End of Year	3,467	9.99

	Outstanding			Exercisable
As at December 31, 2022	Number of Cenovus Replacement Stock Options	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Cenovus Replacement Stock Options	Weighted Average Exercise Price
Range of Exercise Price ($)	(thousands)	(Years)	($)	(thousands)	($)
3.00 to 4.99	2,065	1.63	3.54	742	3.54
5.00 to 9.99	124	1.36	6.06	59	6.06
10.00 to 14.99	14	0.47	12.88	14	12.88
15.00 to 19.99	594	1.04	18.35	594	18.35
20.00 to 24.99	524	0.20	21.77	524	21.77
25.00 to 29.99	146	0.58	27.88	146	27.88
	3,467	1.25	9.99	2,079	14.21

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are time-vested whole-share units that entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible to vest is determined by a multiplier that ranges from zero percent to 200 percent and is based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

The Company has recorded a liability of $216 million as at December 31, 2022, (December 31, 2021 – $61 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. PSUs are paid out upon vesting and, as a result, the intrinsic value was $nil as at December 31, 2022.

The following table summarizes the information related to the PSUs held by Cenovus employees:

	Number of Performance Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	7,163
Granted	3,226
Vested and Paid Out	(1,413)
Cancelled	(465)
Units in Lieu of Dividends	167
Outstanding, End of Year	8,678

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

C) Restricted Share Units

Cenovus granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs generally vest over three years.

The Company recorded a liability of $109 million as at December 31, 2022 (December 31, 2021 – $53 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2022.

The following table summarizes the information related to the RSUs held by Cenovus employees:

	Number of Restricted Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	6,025
Granted	3,161
Vested and Paid Out	(2,230)
Cancelled	(430)
Units in Lieu of Dividends	129
Outstanding, End of Year	6,655

D) Deferred Share Units

Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25, 50, 75 or 100 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

The Company recorded a liability of $40 million as at December 31, 2022 (December 31, 2021 – $20 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

	Number of Deferred Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	1,256
Granted to Directors	161
Granted	316
Units in Lieu of Dividends	30
Redeemed	(257)
Outstanding, End of Year	1,506

E) Total Stock-Based Compensation

For the years ended December 31,	2022	2021	2020
Stock Options With Associated Net Settlement Rights	15	14	11
Cenovus Replacement Stock Options	53	26	—
Performance Share Units	183	56	19
Restricted Share Units	100	48	23
Deferred Share Units	22	15	(4)
Stock-Based Compensation Expense (Recovery)	373	159	49
Stock-Based Compensation Costs Capitalized	—	8	16
Total Stock-Based Compensation	373	167	65

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

35. EMPLOYEE SALARIES AND BENEFIT EXPENSES

For the years ended December 31,	2022	2021	2020
Salaries, Bonuses and Other Short-Term Employee Benefits	1,246	1,327	605
Post-Employment Benefits	92	89	33
Stock-Based Compensation (Note 34)	373	159	49
Other Incentive Benefits (Recovery)	(9)	201	(4)
Termination Benefits	27	180	9
	1,729	1,956	692

Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock options, PSUs, RSUs and DSUs.

36. RELATED PARTY TRANSACTIONS

A) Key Management Compensation

Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is:

For the years ended December 31,	2022	2021	2020
Salaries, Director Fees and Other Short-Term Benefits	40	69	21
Post-Employment Benefits	4	4	3
Stock-Based Compensation	140	72	15
Other Incentive Benefits	—	4	1
Termination Benefits	3	3	6
	187	152	46

Post-employment benefits represent the present value of future pension benefits earned during the year.

B) Other Related Party Transactions

Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 22). As the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs.

The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or on a cost recovery basis with certain restrictions. For the year ended December 31, 2022, the Company charged HMLP $188 million, for construction costs and management services (2021 – $243 million).

The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the year ended December 31, 2022, the Company incurred costs of $263 million, for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million).

37. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, net investment in finance leases, risk management assets and liabilities, investments in the equity of companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and other liabilities. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of restricted cash, net investment in finance leases and long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Long-term debt is carried at amortized cost. The estimated fair value of long-term borrowings has been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2022, the carrying value of Cenovus’s long-term debt was $8.7 billion and the fair value was $7.8 billion (December 31, 2021 carrying value – $12.4 billion, fair value – $13.7 billion).

The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available.

The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:

	2022	2021
Fair Value, Beginning of Year	53	52
Acquisition (Note 5)	—	1
Changes in Fair Value (1)	2	—
Fair Value, End of Year	55	53

(1)     Changes in fair value are recorded in OCI.

Equity investments classified as FVTPL comprise equity investments in public companies. These assets were carried at fair value on the Consolidated Balance Sheets in other assets. Fair value was determined based on quoted prices in active markets (Level 1).

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures, as well as renewable power contracts, power and foreign exchange swaps. The Company may also enter into swaps, forwards, and options to manage commodity and foreign exchange exposures, as well as interest rate swaps.

Crude oil, natural gas, condensate, refined product contracts and power swaps are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange rate contracts, and interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2), respectively. The fair value of cross currency interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2).

The fair value of renewable power contracts are calculated using internal valuation models that incorporate broker pricing for relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair value of renewable power contracts are calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have experience in fair value techniques.

Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets (for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings within (gain) loss on risk management.

Summary of Risk Management Positions

	2022			2021
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	2	40	(38)	46	116	(70)
Power Swap Contracts	1	7	(6)	—	—	—
Renewable Power Contracts	90	—	90	—	—	—
Foreign Exchange Rate Contracts	—	—	—	2	—	2
	93	47	46	48	116	(68)

Level 2 prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Level 3 prices are sourced from partially observable data used in internal valuations.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

As at December 31,	2022	2021
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(44)	(68)
Level 3 – Prices Sourced From Partially Observable Data	90	—
	46	(68)

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities from January 1 to December 31:

	2022	2021
Fair Value of Contracts, Beginning of Year	(68)	(53)
Acquisition (Note 5)	—	(14)
Change in Fair Value of Contracts in Place at Beginning of Year	(5)	—
Change in Fair Value of Contracts Entered Into During the Year	(1,641)	(995)
Fair Value of Contracts Realized During the Year	1,762	993
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	(2)	1
Fair Value of Contracts, End of Year	46	(68)

Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same.

	2022			2021
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	153	107	46	263	331	(68)
Amount Offset	(60)	(60)	—	(215)	(215)	—
Net Amount	93	47	46	48	116	(68)

The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.

Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. As at December 31, 2022, $211 million was pledged as cash collateral (December 31, 2021 – $114 million).

C) Fair Value of Contingent Payments

The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing discounted using a credit-adjusted risk-free rate. Fair value of the variable payment has been calculated by Cenovus’s internal valuation team, which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million applying a credit-adjusted risk-free rate of 5.2 percent. The maximum cumulative variable payment is $600 million.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

As at December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is $72.79 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 44.2 percent and 7.6 percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

As at December 31, 2022	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $10.00 per barrel	(68)	157
WTI Option Volatility	± ten percent	(1)	4
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility	± five percent	—	—

The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $5.00 per barrel	(45)	45

The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in the Canadian-U.S. dollar foreign exchange rate options would result in nominal unrealized gains (losses) to earnings before income tax.

D) Earnings Impact of (Gains) Losses From Risk Management Positions

For the years ended December 31,	2022	2021	2020
Realized (Gain) Loss	1,762	993	252
Unrealized (Gain) Loss (1)	(126)	2	56
(Gain) Loss on Risk Management	1,636	995	308

(1)     All WTI positions related to crude oil sales price risk management were closed by June 30, 2022. In the three months ended June 30, 2022, Cenovus recorded a realized net loss related to these positions of $467 million.

Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

38. RISK MANAGEMENT

Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates, commodity power prices as well as credit risk and liquidity risk.

To manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus, the Company may periodically enter into financial positions as a part of ongoing operations to market the Company’s production and physical inventory positions of crude oil, natural gas, condensate, refined products, and power consumption. The Company may also enter into arrangements to manage exposure to future carbon compliance costs or to offset select carbon emissions.

The Company entered into risk management positions to help capture incremental margin expected to be received in future periods at the time products will be sold and to mitigate overall exposure to fluctuations in commodity prices related to inventories and physical sales. Mitigation of commodity price volatility may utilize financial positions to protect future cash flows. To manage exposure to interest rate volatility, the Company periodically enters into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs, power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts.

As at December 31, 2022, the fair value of risk management positions was a net asset of $46 million and consisted of crude oil, natural gas, condensate, refined products, power and foreign exchange rate instruments. As at December 31, 2022, there were foreign exchange contracts with a notional value of US$168 million outstanding (December 31, 2021 – US$144 million) and no interest rate contracts or cross currency interest rate swap contracts (December 31, 2021 – $nil) outstanding.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Net Fair Value of Risk Management Positions

As at December 31, 2022	Notional Volumes (1)(2)	Terms (3)	Weighted Average Price (1) (2)	Fair Value Asset (Liability)
Futures Contracts Related to Blending (4)
WTI Fixed – Sell	3.2 MMbbls	January 2023 - June 2024	US$80.35/bbl	1
WTI Fixed – Buy	2.3 MMbbls	February 2023 - June 2024	US$79.93/bbl	—
Power Swap Contacts				(6)
Renewable Power Contracts				90
Other Financial Positions (5)				(39)
Total Fair Value				46

(1)    Million barrels (“MMbbls”). Barrel (“bbl”).

(2)    Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3)    Contract terms represent various individual contracts with different terms, and range from one month to eighteen months.

(4)    Condensate related futures contract positions consist of WTI contracts to help manage condensate price exposure.

(5)    Other financial positions consist of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, natural gas basis contracts and the Company’s U.S. manufacturing and marketing activities.

A) Commodity Price, Foreign Exchange and Interest Rate Risk

i) Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.

The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.

The Company has used crude oil, natural gas and refined product swaps, futures, basis price risk management contracts and, if entered into, forwards, options, as well as condensate futures and swaps. These derivative instruments are used to partially mitigate exposure to the commodity price risk on its crude oil sales and to protect both near-term and future cash flows. Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials and to manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus. In addition, the Company has entered into risk management positions to help mitigate the risk to incremental margin expected to be received in future periods at the time products will be sold. The Company has used commodity futures and swaps, as well as differential price risk management contracts to partially mitigate its exposure to the commodity price risk on its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate its natural gas commodity price risk.

ii) Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.

Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada (see Note 9). As at December 31, 2022, Cenovus had US$4.8 billion in U.S. dollar debt (December 31, 2021 – US$7.4 billion).

iii) Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. To manage exposure to interest rate volatility, the Company periodically enters into interest rate swap contracts. As at December 31, 2022, Cenovus had no interest rate swap contracts outstanding (December 31, 2021 – $nil). To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2022, Cenovus had no cross currency interest rate swap contracts outstanding (December 31, 2021 – $nil).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

iv) Commodity Price, Foreign Exchange and Interest Rate Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at December 31, 2022	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	1	(1)
WCS and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	13	(13)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(1)	1
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
Natural Gas Basis Price	± US$0.50/MCF Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/Megawatt Hour Applied to Power Hedges	113	(113)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	14	(17)

(1)    Excludes WCS (Hardisty) differential.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00/bbl Applied to WTI, Condensate and Related Hedges	(225)	225
WCS and Condensate Differential Price	± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production	4	(4)
Refined Products Commodity Price	± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	11	(12)

In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

As at December 31,	2022	2021
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate	246	372
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate	(246)	(372)

Management believes the fluctuations identified in the table above are a reasonable measure of volatility.

As at December 31, 2022, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $1 million (December 31, 2021 – $1 million). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates.

B) Credit Risk

Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee and the Board of Directors, which is designed to ensure that its credit exposures are within an acceptable risk level. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.

Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within its credit policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, net investment in finance leases, risk management assets and long-term receivables is the total carrying value.

As at December 31, 2022, approximately 85 percent (December 31, 2021 – 94 percent) of the Company’s accruals, receivables related to Cenovus’s joint arrangements, trade receivables and net investment in finance leases were with investment grade counterparties, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss on these accounts was 0.4 percent as at December 31, 2022 (December 31, 2021 – 0.1 percent).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

C) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt, and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 26, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at the bottom of the commodity price cycle to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn capacity on its committed credit facility and uncommitted demand facilities as well as availability under its base shelf prospectus. As at December 31, 2022, the Company’s sources of capital included:

•$4.5 billion in cash and cash equivalents.

•$5.5 billion available on its committed credit facility.

•$1.4 billion available on its uncommitted demand facilities, of which $1.0 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit.

•US$140 million (C$190 million) on the Company’s proportionate share of the uncommitted demand facilities from WRB.

•US$4.7 billion unused capacity under its base shelf prospectus, availability of which is dependent on market conditions.

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2022	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,124	—	—	—	6,124
Short-Term Borrowings (1)	115	—	—	—	115
Long-Term Debt (1)	401	983	2,014	11,196	14,594
Contingent Payments	271	167	—	—	438
Lease Liabilities (1)	426	746	596	2,889	4,657
As at December 31, 2021	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,353	—	—	—	6,353
Short-Term Borrowings (1)	79	—	—	—	79
Long-Term Debt (1)	561	1,608	2,603	14,892	19,664
Contingent Payments	238	—	—	—	238
Lease Liabilities (1)	453	794	634	3,192	5,073

(1)     Principal and interest, including current portion if applicable.

39. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital

As at December 31,	2022	2021
Total Current Assets	12,430	11,988
Total Current Liabilities	8,021	7,305
Working Capital	4,409	4,683

As at December 31, 2022, adjusted working capital was $4.7 billion (December 31, 2021 – $3.8 billion), excluding assets held for sale of $nil (December 31, 2021 – $1.3 billion), the current portion of the contingent payments of $263 million (December 31, 2021 – $236 million) and liabilities related to assets held for sale of $nil (December 31, 2021 – $186 million).

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

Changes in non-cash working capital is as follows:

For the years ended December 31,	2022	2021	2020
Accounts Receivable and Accrued Revenues	838	(953)	77
Income Tax Receivable	(58)	(1)	(12)
Inventories	(143)	(1,646)	450
Accounts Payable and Accrued Liabilities	(524)	1,645	(338)
Income Tax Payable	1,000	87	(17)
Total Change in Non-Cash Working Capital	1,113	(868)	160
Net Change in Non-Cash Working Capital – Operating Activities	575	(1,227)	198
Net Change in Non-Cash Working Capital – Investing Activities	538	359	(38)
Total Change in Non-Cash Working Capital	1,113	(868)	160

For the years ended December 31,	2022	2021	2020
Interest Paid	647	811	381
Interest Received	78	24	5
Income Taxes Paid	723	209	18

B) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2019	—	—	6,699	1,916
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	117	—	—
(Repayment) of Revolving Long-Term Debt	—	—	(220)	—
Issuance of Long-Term Debt	—	—	1,326	—
(Repayment) of Long-Term Debt	—	—	(112)	—
Principal Repayment of Leases	—	—	—	(197)
Base Dividends Paid on Common Shares	(77)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	(25)	—
Finance Costs	—	—	5	—
Lease Additions	—	—	—	49
Lease Modifications	—	—	—	(2)
Lease Re-measurements	—	—	—	(2)
Lease Terminations	—	—	—	(1)
Base Dividends Declared on Common Shares	77	—	—	—
Exchange Rate Movements and Other	—	4	(232)	(6)
As at December 31, 2020	—	121	7,441	1,757

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

	Dividends Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2020	—	121	7,441	1,757
Acquisition (Note 5)	—	40	6,602	1,441
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	(77)	—	—
(Repayment) of Revolving Long-Term Debt	—	—	(350)	—
Issuance of Long-Term Debt	—	—	1,557	—
(Repayment) of Long-Term Debt	—	—	(2,870)	—
Principal Repayment of Leases	—	—	—	(300)
Base Dividends Paid on Common Shares	(176)	—	—	—
Dividends Paid on Preferred Shares	(34)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	121	—
Finance Costs	—	—	(59)	—
Lease Additions	—	—	—	110
Lease Modifications	—	—	—	22
Lease Re-measurements	—	—	—	(4)
Lease Termination	—	—	—	(1)
Transfers to Liabilities Related to Assets Held for Sale	—	—	—	(58)
Base Dividends Declared on Common Shares	176	—	—	—
Dividends Declared on Preferred Shares	34	—	—	—
Exchange Rate Movements and Other	—	(5)	(57)	(10)
As at December 31, 2021	—	79	12,385	2,957
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	34	—	—
(Repayment) of Long-Term Debt	—	—	(4,149)	—
Principal Repayment of Leases	—	—	—	(302)
Base Dividends Paid on Common Shares	(682)	—	—	—
Variable Dividends Paid on Common Shares	(219)	—	—	—
Dividends Paid on Preferred Shares	(26)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	(29)	—
Finance Costs	—	—	(28)	—
Lease Additions	—	—	—	25
Lease Modifications	—	—	—	83
Lease Re-measurements	—	—	—	7
Lease Terminations	—	—	—	(5)
Base Dividends Declared on Common Shares	682	—	—	—
Variable Dividends Declared on Common Shares	219	—	—	—
Dividends Declared on Preferred Shares	35	—	—	—
Exchange Rate Movements and Other	—	2	512	71
As at December 31, 2022	9	115	8,691	2,836

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2022

40. COMMITMENTS AND CONTINGENCIES

A) Commitments

Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities less than one year are excluded from the table below. Future payments for the Company’s commitments are below:

As at December 31, 2022	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	1,747	2,011	1,542	1,416	1,360	13,005	21,081
Product Purchases	1,626	1,509	922	922	922	3,457	9,358
Real Estate (2)	48	50	50	50	54	604	856
Obligation to Fund Equity-Accounted Affiliate (3)	92	105	96	96	91	143	623
Other Long-Term Commitments (4)	381	90	75	74	65	395	1,080
Total Payments	3,894	3,765	2,685	2,558	2,492	17,604	32,998

As at December 31, 2021	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	1,677	1,958	1,853	1,488	1,350	13,244	21,570
Product Purchases (5)	1,684	1,682	1,593	731	731	4,204	10,625
Real Estate (2)	44	43	52	54	57	658	908
Obligation to Fund Equity-Accounted Affiliate (3)	68	85	99	90	90	210	642
Other Long-Term Commitments (4)	436	83	72	63	81	366	1,101
Total Payments	3,909	3,851	3,669	2,426	2,309	18,682	34,846

(1)    Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the commencement of the contract.

(2)    Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(3)    Relates to funding obligations for HCML.

(4)    Includes Cenovus’s proportionate share of the commitments related to WRB, Toledo and the Offshore segment.

(5)    Previously included in transportation and storage.

As at December 31, 2022, the Company had commitments with HMLP that include $2.2 billion related to long-term transportation and storage commitments (December 31, 2021 – $2.6 billion).

There were also outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) issued as security for financial and performance conditions under certain contracts.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

Cenovus Energy Inc. – 2022 Consolidated Financial Statements 79

EX-99.4

Exhibit 99.4

Cenovus Energy Inc.

Supplementary Information – Oil and Gas Activities (unaudited)

For the Year Ended December 31, 2022

(Canadian Dollars)

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES TOPIC 932 “EXTRACTIVE ACTIVITIES – OIL AND GAS” (unaudited)

The following select disclosures of Cenovus Energy Inc.’s (“Cenovus” or the “Company”) reserves and other oil and gas information have been prepared in accordance with United States (“U.S.”) Financial Accounting Standards Board (“FASB”) Topic 932, “Extractive Activities – Oil and Gas” and the U.S. disclosure requirements of the Securities and Exchange Commission (“SEC”).

All amounts pertaining to Cenovus’s audited Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Unless otherwise noted, all dollars are in millions of Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

RESERVES DATA

The SEC Modernization of Oil and Gas Reporting final rules require that proved after royalty reserves be estimated using existing economic conditions (constant pricing). Cenovus’s results have been calculated using the average of the first-day-of-the-month prices for the prior twelve-month period. This same twelve-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves (“SMOG”). Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause Cenovus’s share of future production from its reserves to be materially different from that presented.

The reserves disclosed are effective December 31, 2022, and were prepared by the independent, qualified reserves evaluators (“IQREs”) McDaniel & Associates Consultants Ltd. and GLJ Ltd. There are significant differences between reserves evaluated under the SEC requirements and those presented in the Company’s Annual Information Form filed under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). NI 51-101 requires disclosure of before royalties reserves and the associated values using forecasted prices and costs.

The reserves presented in this supplemental information are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the Company’s control. In general, estimates of economically recoverable bitumen, crude oil, natural gas liquids and natural gas reserves and the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, including but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to environmental regulations, royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities, all of which may vary considerably from actual results.

All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable bitumen, crude oil, natural gas liquids and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Cenovus’s actual production, sales, royalty payments, taxes and development and operating expenditures with respect to its reserves may vary from current estimates and such variances may be material. Actual reserves may be greater than or less than the estimates disclosed. For a full discussion of Cenovus’s material risk factors refer to “Risk Management and Risk Factors” in the Company’s annual 2022 Management’s Discussion and Analysis included in the annual report on Form 40-F of which this document forms a part.

Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production rates. Canadian reserves, as presented on a net basis, assume royalty rates in existence at the time the estimates were made.

The reserves data contained herein is dated February 14, 2023, with an effective date of December 31, 2022.

Cenovus Energy Inc. 2 Supplementary Information – Oil and Gas Activities (unaudited)

OIL AND GAS RESERVES INFORMATION

In Canada, Cenovus's bitumen, crude oil, natural gas liquids and natural gas reserves are located in the provinces of Alberta, British Columbia, Saskatchewan and offshore Newfoundland and Labrador. Cenovus's international natural gas liquids and natural gas reserves are located offshore China and Indonesia.

Net Proved Reserves (Cenovus Share After Royalties) (1)(2)
Average Fiscal-Year Prices

	Bitumen		Crude Oil		Natural Gas Liquids		Natural Gas		Total
		(MMbbls) (3)		(MMbbls) (3)		(MMbbls) (3)		(Bcf) (3)		(MMBOE) (3)
Canada
2021
Beginning of year		4,270		4		31		692		4,420
Technical revisions and improved recovery		84		1		2		93		103
Revisions due to price		(589)		3		9		256		(535)
Total revisions to prior estimates		(505)		4		11		349		(432)
Extensions and discoveries		14		10		4		121		48
Purchase of reserves in place		795		69		22		611		988
Sale of reserves in place		—		(1)		(2)		(25)		(7)
Production		(165)		(14)		(8)		(216)		(223)
End of year		4,409		72		58		1,532		4,794
Developed		813		49		50		1,280		1,125
Undeveloped		3,596		23		8		252		3,669
Total		4,409		72		58		1,532		4,794
2022
Beginning of year		4,409		72		58		1,532		4,794
Technical revisions and improved recovery		79		(3)		2		42		85
Revisions due to price		(469)		7		—		14		(460)
Total revisions to prior estimates		(390)		4		2		56		(375)
Extensions and discoveries		21		5		3		178		58
Purchase of reserves in place		237		—		—		2		238
Sale of reserves in place		(102)		(1)		(2)		(30)		(110)
Production		(154)		(12)		(6)		(200)		(206)
End of year		4,021		68		55		1,538		4,399
Developed		792		62		45		1,208		1,100
Undeveloped		3,229		6		10		330		3,299
Total		4,021		68		55		1,538		4,399

Cenovus Energy Inc. 3 Supplementary Information – Oil and Gas Activities (unaudited)

	Bitumen		Crude Oil		Natural Gas Liquids		Natural Gas		Total
		(MMbbls) (3)		(MMbbls) (3)		(MMbbls) (3)		(Bcf) (3)		(MMBOE) (3)
China
2021
Beginning of year		—		—		—		—		—
Purchase of reserves in place		—		—		19		466		97
Production		—		—		(3)		(84)		(17)
End of year		—		—		16		382		80
Developed		—		—		16		382		80
Undeveloped		—		—		—		—		—
Total		—		—		16		382		80
2022
Beginning of year		—		—		16		382		80
Technical revisions and improved recovery		—		—		(1)		11		1
Total revisions to prior estimates		—		—		(1)		11		1
Production		—		—		(4)		(79)		(17)
End of year		—		—		11		314		64
Developed		—		—		11		314		64
Undeveloped		—		—		—		—		—
Total		—		—		11		314		64
Total Consolidated Entities
2021
Beginning of year		4,270		4		31		692		4,420
Technical revisions and improved recovery		84		1		2		93		103
Revisions due to price		(589)		3		9		256		(535)
Total revisions to prior estimates		(505)		4		11		349		(432)
Extensions and discoveries		14		10		4		121		48
Purchase of reserves in place		795		69		41		1,077		1,085
Sale of reserves in place		—		(1)		(2)		(25)		(7)
Production		(165)		(14)		(11)		(300)		(240)
End of year		4,409		72		74		1,914		4,874
Developed		813		49		66		1,662		1,205
Undeveloped		3,596		23		8		252		3,669
Total		4,409		72		74		1,914		4,874
2022
Beginning of year		4,409		72		74		1,914		4,874
Technical revisions and improved recovery		79		(3)		1		53		86
Revisions due to price		(469)		7		—		14		(460)
Total revisions to prior estimates		(390)		4		1		67		(374)
Extensions and discoveries		21		5		3		178		58
Purchase of reserves in place		237		—		—		2		238
Sale of reserves in place		(102)		(1)		(2)		(30)		(110)
Production		(154)		(12)		(10)		(279)		(223)
End of year		4,021		68		66		1,852		4,463
Developed		792		62		56		1,522		1,164
Undeveloped		3,229		6		10		330		3,299
Total		4,021		68		66		1,852		4,463

Cenovus Energy Inc. 4 Supplementary Information – Oil and Gas Activities (unaudited)

	Bitumen		Crude Oil		Natural Gas Liquids		Natural Gas		Total
		(MMbbls) (3)		(MMbbls) (3)		(MMbbls) (3)		(Bcf) (3)		(MMBOE) (3)
Indonesia (4)
2021
Beginning of year		—		—		—		—		—
Purchase of reserves in place		—		—		3		161		30
Production		—		—		(1)		(12)		(3)
End of year		—		—		2		149		27
Developed		—		—		2		79		15
Undeveloped		—		—		—		70		12
Total		—		—		2		149		27
2022
Beginning of year		—		—		2		149		27
Technical revisions and improved recovery		—		—		1		(7)		—
Revisions due to price		—		—		—		(8)		(2)
Total revisions to prior estimates		—		—		1		(15)		(2)
Production		—		—		(1)		(10)		(2)
End of year		—		—		2		124		23
Developed		—		—		2		124		23
Undeveloped		—		—		—		—		—
Total		—		—		2		124		23

(1)Definitions:

(a) “Net” reserves are the remaining reserves attributable to Cenovus, after deduction of estimated royalties and including royalty interests.

(b) “Proved” oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, i.e., prices and costs as of the date the estimate is made.

(c) “Developed” oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared to the cost of a new well.

(d) “Undeveloped” reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)Estimates of total net proved bitumen, crude oil, natural gas liquids, or natural gas reserves are not filed by Cenovus with any U.S. federal authority or agency other than the SEC.

(3)“Million barrels” is abbreviated as MMbbls, “billion cubic feet” is abbreviated as Bcf, and “million barrels of oil equivalent” is abbreviated as MMBOE.

(4)Amounts represent Cenovus's 40 percent working interest in the Husky-CNOOC Madura Ltd. ("HCML") joint venture. Financial results related to HCML are accounted for under the equity method of accounting for consolidated financial statement purposes.

Changes to Reserves

The explanation of significant year-over-year changes in the Company’s net proved reserves for the years ended December 31, 2022, and December 31, 2021, is set forth below.

Year ended December 31, 2022

The changes to the Company's net proved reserves of bitumen in 2022 are explained as follows:

•Technical revisions and improved recovery: Improved recovery performance at Sunrise and Lloydminster thermal resulted in an increase in net proved reserves of 36 million barrels. Increased forecast capital and operating costs resulted in reductions to royalties payable for the Oil Sands segment, which resulted in an increase in net proved reserves of 43 million barrels.

•Revisions due to price: Increased bitumen prices resulted in higher royalties payable for the Oil Sands segment, which resulted in a decrease in net proved reserves.

•Extensions and discoveries: A regulatory approval at Lloydminster thermal increased net proved reserves.

•Purchase of reserves in place: The acquisition of the remaining 50 percent interest in Sunrise increased net proved reserves.

•Sale of reserves in place: The Tucker asset sale decreased net proved reserves.

Cenovus Energy Inc. 5 Supplementary Information – Oil and Gas Activities (unaudited)

The changes to the Company's net proved reserves of crude oil, natural gas liquids and natural gas in 2022 are explained as follows:

•Technical revisions and improved recovery: Within the Conventional segment, improved recovery performance partially offset by updates to the development plan increased net proved reserves.

•Revisions due to price: Within the Conventional segment and Lloydminster conventional heavy oil, changes to product pricing increased net proved reserves.

•Extensions and discoveries: Conventional segment and Lloydminster conventional heavy oil current year development and updates to the development plan increased net proved reserves.

•Sale of reserves in place: The transfer of a 12.5 percent working interest in the White Rose field and satellite extensions and the Wembley asset sale decreased net proved reserves.

Year ended December 31, 2021

The changes to the Company's net proved bitumen reserves in 2021 are explained as follows:

•Technical revisions and improved recovery: Improved recovery performance at Christina Lake resulted in an increase in net proved reserves.

•Revisions due to price: Increased bitumen prices resulted in higher royalties payable for Christina Lake and Foster Creek, which resulted in a decrease in net proved reserves.

•Extensions and discoveries: A development approval at Lloydminster thermal increased net proved reserves.

•Purchase of reserves in place: The acquisition of Husky Energy Inc. on January 1, 2021 (the “Arrangement”), increased net proved reserves.

The changes to the Company's net proved reserves of crude oil, natural gas liquids and natural gas in 2021 are explained as follows:

•Technical revisions and improved recovery: Within the Conventional segment, technical revisions partially offset by updates to the development plan increased net proved reserves of 26 million barrels. Increased forecast capital and operating costs resulted in reductions to royalties payable for the Oil Sands segment, which resulted in an increase in net proved reserves of 58 million barrels.

•Revisions due to price: Changes to product pricing increased net proved reserves.

•Extensions and discoveries: Conventional segment development and the Terra Nova restructuring (the sanction of the asset life extension project accounted for seven million barrels of crude oil) increased net proved reserves.

•Purchase of reserves in place: The Arrangement and the acquisition of an additional 21 percent working interest in Terra Nova accounted for 12 million barrels of crude oil increased net proved reserves.

•Sale of reserves in place: The Company completed several minor dispositions in its Conventional segment, decreasing its net proved reserves.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN

In calculating SMOG, the average of the first-day-of-the-month prices for the prior twelve-month period and cost assumptions were applied to Cenovus’s annual future production from net proved reserves to determine cash inflows. Future production and development costs do not include any cost inflation and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The discount was computed by application of a 10 percent discount factor to the future net cash flows. The calculation of SMOG is based upon the discounted future net cash flows prepared by IQREs in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements such as price risk management activities, in existence at year end and to account for asset retirement obligations and future income taxes.

Cenovus cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of Cenovus’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil, natural gas liquids and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates. The computation also excludes values contributed by Cenovus’s enhancement of the netback price from market optimization activities.

Cenovus Energy Inc. 6 Supplementary Information – Oil and Gas Activities (unaudited)

Computation of the SMOG was based on the following average of the first-day-of-the-month benchmark prices for the twelve-month period before the end of the year. Natural gas prices for China and Indonesia reserves are based on various gas sales agreements.

	Crude Oil and Natural Gas Liquids										Natural Gas
		Brent Crude Oil	WTI (1) Cushing Oklahoma		WCS (2)		Edmonton MSW (3)		Edmonton C5+		Henry Hub Louisiana		AECO (4)
		(US$/bbl)	(US$/bbl)		(C$/bbl)		(C$/bbl)		(C$/bbl)		(US$/MMBtu)		(C$/MMBtu)
2022		101.24		93.67		96.99		118.70		119.73		6.36		5.65
2021		69.23		66.56		66.43		78.40		84.23		3.60		3.26

(1)WTI is an abbreviation for West Texas Intermediate.

(2)WCS is an abbreviation for Western Canadian Select at Hardisty.

(3)MSW is an abbreviation for Mixed Sweet Blend.

(4)AECO is an abbreviation for Alberta Energy Company.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	Year Ended December 31, 2022
($ millions)	Canada		China		Total Consolidated Entities	Indonesia
Future cash inflows		338,151		5,298	343,449		1,516
Less future:
Production costs		93,888		711	94,599		861
Development costs		34,596		40	34,636		—
Asset retirement obligation payments (1)		6,850		107	6,957		36
Income taxes		46,420		1,008	47,428		247
Future net cash flows		156,397		3,432	159,829		372
Less 10 percent annual discount for estimated timing of     cash flow		100,553		829	101,382		95
Discounted future net cash flow		55,844		2,603	58,447		277

	Year Ended December 31, 2021
($ millions)	Canada		China		Total Consolidated Entities	Indonesia
Future cash inflows		242,995		5,459	248,454		1,603
Less future:
Production costs		70,102		1,232	71,334		988
Development costs		30,918		—	30,918		41
Asset retirement obligation payments (1)		6,761		122	6,883		39
Income taxes		29,945		528	30,473		230
Future net cash flows		105,269		3,577	108,846		305
Less 10 percent annual discount for estimated timing of     cash flow		68,681		916	69,597		101
Discounted future net cash flow		36,588		2,661	39,249		204

(1)Includes future abandonment and reclamation costs associated with existing and future wells having attributed reserves, non-reserves wells and gathering systems, batteries, plants and processing facilities.

Cenovus Energy Inc. 7 Supplementary Information – Oil and Gas Activities (unaudited)

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	Year Ended December 31, 2022
($ millions)	Canada		China			Total Consolidated Entities	Indonesia
Balance, beginning of year		36,588		2,661		39,249	204
Changes resulting from:
Sales of oil and gas produced during the period, net of     operating costs (1)		(10,575)		(1,263)		(11,838)	(119)
Extensions, discoveries and improved recovery, net of     related cost		7,735		—		7,735	231
Purchases of proved reserves in place		3,194		—	3,194		—
Sales of proved reserves in place		(2,155)		—		(2,155)	—
Net change in prices and production costs (1)		30,271		1,362		31,633	(51)
Revisions to quantity estimates		(3,017)		40		(2,977)	(24)
Accretion of discount		4,056		213		4,269	34
Previously estimated development costs incurred, net    of change in future development costs		(1,979)		(27)		(2,006)	39
Other		(1,557)		(14)		(1,571)	(13)
Net change in income taxes		(6,717)		(369)		(7,086)	(24)
Balance, end of year		55,844		2,603		58,447	277

	Year Ended December 31, 2021
($ millions)	Canada		China		Total Consolidated Entities	Indonesia
Balance, beginning of year		9,734		—	9,734	—
Changes resulting from:
Sales of oil and gas produced during the period, net of     operating costs (1)		(7,457)		(1,167)	(8,624)	(147)
Extensions, discoveries and improved recovery, net of     related cost		465		—	465	—
Purchases of proved reserves in place		9,488		3,828	13,316	351
Sales of proved reserves in place		(66)		—	(66)	—
Net change in prices and production costs (1)		32,688		—	32,688	—
Revisions to quantity estimates		(55)		—	(55)	—
Accretion of discount		1,165		—	1,165	—
Previously estimated development costs incurred, net    of change in future development costs		(2,754)		—	(2,754)	—
Other		872		—	872	—
Net change in income taxes		(7,492)		—	(7,492)	—
Balance, end of year		36,588		2,661	39,249	204

(1)On January 1, 2019, Cenovus adopted IFRS 16, “Leases” (“IFRS 16”), which prescribes a different accounting treatment for operating leases than U.S. Generally Accepted Accounting Principles (“US GAAP”). Under US GAAP, the amortization of a right-of-use asset and interest expense related to an operating lease are recorded by nature of the expense on the income statement (production costs). Under IFRS 16, amortization of a right-of-use asset and interest expense are classified as depreciation expense and finance costs, respectively. As a result, changes in SMOG due to the amortization of right-of-use assets and interest payments have been included by Cenovus in “Net change in prices and production costs”.

Cenovus Energy Inc. 8 Supplementary Information – Oil and Gas Activities (unaudited)

OTHER FINANCIAL INFORMATION

Results of Operations

	Year Ended December 31, 2022
($ millions)	Canada		China		Total Consolidated Entities	Indonesia (1)
Oil and gas sales, net of royalties, transportation and blending and realized risk management		14,250		1,362	15,612		155
Less:
Operating costs and accretion of asset retirement     obligations		3,836		111	3,947		37
Depreciation, depletion and amortization		3,172		546	3,718		64
Exploration expense		24		77	101		—
Operating income		7,218		628	7,846		54
Income taxes		1,711		157	1,868		22
Results of operations		5,507		471	5,978		32

	Year Ended December 31, 2021
($ millions)	Canada		China		Total Consolidated Entities	Indonesia (1)
Oil and gas sales, net of royalties, transportation and blending and realized risk management		10,596		1,261	11,857	172
Less:
Operating costs and accretion of asset retirement     obligations		3,312		105	3,417	26
Depreciation, depletion and amortization		2,681		479	3,160	62
Exploration expense		10		7	17	1
Operating income		4,593		670	5,263	83
Income taxes		1,089		168	1,257	33
Results of operations		3,504		502	4,006	50

(1) Financial results related to HCML are accounted for under the equity method of accounting for consolidated financial statement purposes.

Cenovus Energy Inc. 9 Supplementary Information – Oil and Gas Activities (unaudited)

Capitalized Costs

	Year Ended December 31, 2022
($ millions)	Canada		China		Total Consolidated Entities	Indonesia (1)
Proved oil and gas properties		40,425		3,103	43,528		432
Unproved oil and gas properties (2)		680		5	685		—
Total capital cost		41,105		3,108	44,213		432
Accumulated depreciation, depletion and amortization		13,251		1,051	14,302		114
Net capitalized costs		27,854		2,057	29,911		318

	Year Ended December 31, 2021
($ millions)	Canada		China		Total Consolidated Entities	Indonesia (1)
Proved oil and gas properties		35,987		2,456	38,443		260
Unproved oil and gas properties (2)		660		60	720		—
Total capital cost		36,647		2,516	39,163		260
Accumulated depreciation, depletion and amortization		10,581		421	11,002		22
Net capitalized costs		26,066		2,095	28,161		238

(1) Capital expenditures related to HCML are accounted for under the equity method of accounting for consolidated financial statement purposes.

(2) Unproved oil and gas properties include exploration and evaluation assets for which no proved reserves have been recognized.

Costs Incurred

	Year Ended December 31, 2022
($ millions)	Canada		China		Total Consolidated Entities		Indonesia (1)
Acquisitions
Unproved (2)		—		—		—		—
Proved (3) (4)		1,621		—		1,621		—
Total acquisitions		1,621		—		1,621		—
Exploration costs		34		3		37		—
Development costs		2,404		4		2,408		74
Total costs incurred		4,059		7		4,066		74

	Year Ended December 31, 2021
($ millions)	Canada		China		Total Consolidated Entities		Indonesia (1)
Acquisitions
Unproved (2)		—		45		45		—
Proved (3) (4)		5,640		3,000		8,640		—
Total acquisitions		5,640		3,045		8,685		—
Exploration costs		39		16		55		—
Development costs		1,356		5		1,361		8
Total costs incurred		7,035		3,066		10,101		8

(1)Capital expenditures related to HCML are accounted for under the equity method of accounting for consolidated financial statement purposes.

(2)An unproved property is a property to which no proved or probable reserves have been specifically attributed.

(3)A proved property is a property to which proved and probable reserves have been specifically attributed.

(4)Asset retirement costs are included in the year of acquisition.

Cenovus Energy Inc. 10 Supplementary Information – Oil and Gas Activities (unaudited)

EX-99.5

Exhibit 99.5

Certification of Chief Executive Officer

Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

I, Alex J. Pourbaix, certify that:

1.	I have reviewed this annual report on Form 40-F of Cenovus Energy Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

DATED: February 16, 2023

/s/ Alex J. Pourbaix

Alex J. Pourbaix

President & Chief Executive Officer

(Principal Executive Officer)

EX-99.6

Exhibit 99.6

    Certification of Chief Financial Officer    

Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

I, Jeffrey R. Hart, certify that:

1.	I have reviewed this annual report on Form 40-F of Cenovus Energy Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

DATED: February 16, 2023

/s/ Jeffrey R. Hart

Jeffrey R. Hart

Executive Vice-President &

Chief Financial Officer

(Principal Financial Officer)

EX-99.7

Exhibit 99.7

Certification Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes Oxley Act of 2002

In connection with the annual report of Cenovus Energy Inc. (the “Company”) on Form 40−F for the year ended December 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Alex J. Pourbaix, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

DATED: February 16, 2023

/s/ Alex J. Pourbaix

Alex J. Pourbaix

President & Chief Executive Officer

EX-99.8

Exhibit 99.8

Certification Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the annual report of Cenovus Energy Inc. (the “Company”) on Form 40−F for the year ended December 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey R. Hart, Executive Vice-President & Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

DATED: February 16, 2023

/s/ Jeffrey R. Hart

Jeffrey R. Hart

Executive Vice-President &

Chief Financial Officer

EX-99.9

Exhibit 99.9

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in this Annual Report on Form 40-F for the year ended December 31, 2022 of Cenovus Energy Inc. of our report dated February 15, 2023, relating to the consolidated financial statements, and the effectiveness of internal control over financial reporting, which appears in the Exhibit 99.3 to this Annual Report on Form 40-F.

We also consent to the incorporation by reference in the Registration Statements on Form F-10
(File No. 333-259814), Form S-8 (File Nos. 333-163397 and 333-251886) and Form F-3D
(File No. 333-202165) of Cenovus Energy Inc. of our report dated February 15, 2023 referred to above. We also consent to the reference to us under the heading “Interests of Experts”, which appears in the Annual Information Form included in Exhibit 99.1 to this Annual Report on Form 40-F, which is incorporated by reference in such Registration Statements.

/s/PricewaterhouseCoopersLLP

Chartered Professional Accountants

Calgary, Alberta, Canada

February 15, 2023

PricewaterhouseCoopers LLP

111-5th Avenue SW, Suite 3100, Calgary, Alberta, Canada T2P 5L3

T: +1 403 509 7500, F: +1 403 781 1825, www.pwc.com/ca

“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.

EX-99.10

Exhibit 99.10

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the use of and reference to our name and report evaluating a portion of Cenovus Energy Inc.’s oil and gas reserves data, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2022, estimated using forecast prices and costs, and the information derived from our report, as described or incorporated by reference in Cenovus Energy Inc.’s annual report on Form 40-F for the year ended December 31, 2022 and Cenovus Energy Inc.’s registration statements on Form F-10 (File No. 333-259814), Form S-8 (File Nos. 333-163397 and 333-251886) and Form F-3D (File No. 333-202165) filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.

McDANIEL & ASSOCIATES CONSULTANTS LTD.

/s/ Michael J. Verney        

Michael J. Verney, P. Eng.

Executive Vice President

Calgary, Alberta

February 16, 2023

2000, Eighth Avenue Place, East Tower, 525 – 8 Avenue SW, Calgary AB T2P 1G1 Tel: (403) 262-5506 www.mcdan.com

EX-99.11

Exhibit 99.11

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the use of and reference to our name and report evaluating a portion of Cenovus Energy Inc.’s oil and gas reserves data, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2022, estimated using forecast prices and costs, and the information derived from our report, as described or incorporated by reference in Cenovus Energy Inc.’s annual report on Form 40-F for the year ended December 31, 2022 and Cenovus Energy Inc.’s registration statements on Form F-10 (File No. 333-259814), Form S-8 (File Nos. 333-163397 and 333-251886) and Form F-3D (File No. 333-202165) filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.

        Yours truly,

        GLJ LTD.

        /s/ Jodi L. Anhorm

        Jodi L. Anhorn, P. Eng.

        President and Chief Executive Officer

Calgary, Alberta

February 16, 2023

1920, 401 – 9th Ave SW Calgary, AB, Canada T2P 3C5 I teI 403-266-9500 I gIjpc.com

XML

Cover	12 Months Ended
	Dec. 31, 2022 shares
Document Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Entity File Number	1-34513
Entity Registrant Name	CENOVUS ENERGY INC.
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	4100, 225 – 6 Avenue S.W.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Country	CA
Entity Address, Postal Zip Code	T2P 1N2
City Area Code	403
Local Phone Number	766-200
Title of 12(b) Security	Common shares, no par value (together with associated common share purchase rights)
Trading Symbol	CVE
Security Exchange Name	NYSE
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	1,909,190,359
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Central Index Key	0001475260
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false
Auditor Firm ID	271
Warrants
Document Information [Line Items]
Title of 12(b) Security	Warrants (each warrant entitles the holder to purchase one common share at an exercise price of C$6.54 per share)
Trading Symbol	CVE WS
Security Exchange Name	NYSE
Business Contact
Document Information [Line Items]
Entity Address, Address Line One	28 Liberty Street
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10005
City Area Code	212
Local Phone Number	894-8940
Contact Personnel Name	CT Corporation System

XML

Audit Information	12 Months Ended
	Dec. 31, 2022
Auditor [Line Items]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Calgary, Alberta, Canada
Auditor Firm ID	271

XML

Consolidated Statements of Earnings (Loss) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Revenues
Gross Sales	$ 71,765	$ 48,811	[1]	$ 13,914	[1]
Less: Royalties	4,868	2,454	[1]	371	[1]
Revenues	66,897	46,357	[1]	13,543	[1]
Expenses
Purchased Product	33,801	23,326	[1]	5,681	[1]
Transportation and Blending	11,530	8,038	[1]	4,728	[1]
Operating	5,569	4,716	[1]	1,955	[1]
(Gain) Loss on Risk Management	1,636	995	[1]	308	[1]
Depreciation, Depletion and Amortization	4,679	5,886	[1]	3,464	[1]
Exploration Expense	101	18	[1]	91	[1]
(Income) Loss From Equity-Accounted Affiliates	(15)	(57)		0
General and Administrative	865	849	[1]	292	[1]
Finance Costs	820	1,082	[1]	536	[1]
Interest Income	(81)	(23)	[1]	(9)	[1]
Integration and Transaction Costs	106	349	[1]	29	[1]
Foreign Exchange (Gain) Loss, Net	343	(174)	[1]	(181)	[1]
Revaluation (Gains)	(549)	0		0
Re-measurement of Contingent Payments	162	575	[1]	(80)	[1]
(Gain) Loss on Divestiture of Assets	(269)	(229)	[1]	(81)	[1]
Other (Income) Loss, Net	(532)	(309)	[1]	40	[1]
Earnings (Loss) Before Income Tax	8,731	1,315	[1]	(3,230)	[1]
Income Tax Expense (Recovery)	2,281	728	[1]	(851)	[1]
Net Earnings (Loss)	$ 6,450	$ 587	[1]	$ (2,379)	[1]
Net Earnings (Loss) Per Common Share ($)
Net Earnings (Loss) Per Share — Basic (CAD per share)	$ 3.29	$ 0.27	[1]	$ (1.94)	[1]
Net Earnings (Loss) Per Share — Diluted (CAD per share)	$ 3.20	$ 0.27	[1]	$ (1.94)	[1]

[1] See Note 3X for revisions to prior period results.

XML

Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Statement of comprehensive income [abstract]
Net Earnings (Loss)		$ 6,450	$ 587	[1]	$ (2,379)	[1]
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits		71	38		(8)
Change in the fair value of equity instruments at FVOCI	[2]	2	0		0
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		713	(129)		(44)
Total Other Comprehensive Income (Loss), Net of Tax		786	(91)		(52)
Comprehensive Income (Loss)		$ 7,236	$ 496		$ (2,431)

[1] See Note 3X for revisions to prior period results.

[2] Fair value through other comprehensive income (loss) (“FVOCI”).

XML

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current Assets
Cash and Cash Equivalents	$ 4,524	$ 2,873
Accounts Receivable and Accrued Revenues	3,473	3,870
Income Tax Receivable	121	22
Inventories	4,312	3,919
Assets Held for Sale	0	1,304
Total Current Assets	12,430	11,988
Restricted Cash	209	186
Exploration and Evaluation Assets, Net	685	720
Property, Plant and Equipment, Net	36,499	34,225
Right-of-Use Assets, Net	1,845	2,010
Income Tax Receivable	25	66
Investments in Equity-Accounted Affiliates	365	311
Other Assets	342	431
Deferred Income Taxes	546	694
Goodwill	2,923	3,473
Total Assets	55,869	54,104
Current Liabilities
Accounts Payable and Accrued Liabilities	6,124	6,353
Short-Term Borrowings	115	79
Lease Liabilities	308	272
Contingent Payments	263	236
Income Tax Payable	1,211	179
Liabilities Related to Assets Held for Sale	0	186
Total Current Liabilities	8,021	7,305
Long-Term Debt	8,691	12,385
Lease Liabilities	2,528	2,685
Contingent Payments	156	0
Decommissioning Liabilities	3,559	3,906
Other Liabilities	1,042	929
Deferred Income Taxes	4,283	3,286
Total Liabilities	28,280	30,496
Shareholders’ Equity	27,576	23,596
Non-Controlling Interest	13	12
Total Liabilities and Equity	$ 55,869	$ 54,104

XML

Consolidated Statements of Equity - CAD ($) $ in Millions		Total		Common shares	Preference shares	Common Share Warrants	Common Shares	Common Shares Common shares	Preferred Shares	Preferred Shares Preference shares	Warrants	Warrants Common Share Warrants	Paid in Surplus	Retained Earnings	Retained Earnings Common shares	Retained Earnings Preference shares	AOCI	[1]	Non-Controlling Interest
Beginning balance at Dec. 31, 2019		$ 19,201					$ 11,040						$ 4,377	$ 2,957			$ 827
Net Earnings (Loss)		(2,379)	[2]											(2,379)
Other Comprehensive Income (Loss), Net of Tax		(52)															(52)
Comprehensive Income (Loss)		(2,431)												(2,379)			(52)
Stock-Based Compensation Expense		14											14
Dividends paid				$ (77)											$ (77)
Variable dividends paid on common shares				0
Ending balance at Dec. 31, 2020		16,707					11,040						4,391	501			775		$ 0
Net Earnings (Loss)		587	[2]											587
Other Comprehensive Income (Loss), Net of Tax		(91)															(91)
Comprehensive Income (Loss)		496												587			(91)
Stock-Based Compensation Expense		14											14
Dividends paid				(176)	$ (34)										(176)	$ (34)
Variable dividends paid on common shares				0
Equity Issued				6,111	519	$ 216		$ 6,111		$ 519		$ 216
Common shares issued under stock option plans (in shares)								(7)
Common Shares Issued Under Stock Option Plans		(6)											1
Purchase of Common Shares Under NCIBs	[3]	(265)						$ (145)					(120)
Warrants Exercised		2					3				$ (1)
Non-Controlling Interest																			12
Ending balance at Dec. 31, 2021		23,596					17,016		$ 519		215		4,284	878			684		12
Net Earnings (Loss)		6,450												6,450
Other Comprehensive Income (Loss), Net of Tax		786															786
Comprehensive Income (Loss)		7,236												6,450			786
Stock-Based Compensation Expense		10											10
Dividends paid				(682)	$ (35)										(682)	$ (35)
Variable dividends paid on common shares				$ (219)											$ (219)
Common shares issued under stock option plans (in shares)								(170)
Common Shares Issued Under Stock Option Plans		(138)											32
Purchase of Common Shares Under NCIBs	[3]	(2,530)						$ (959)					(1,571)
Warrants Exercised		62					93				(31)
Non-Controlling Interest																			1
Ending balance at Dec. 31, 2022		$ 27,576					$ 16,320		$ 519		$ 184		$ 2,691	$ 6,392			$ 1,470		$ 13

[1] Accumulated other comprehensive income (loss) (“AOCI”).

[2] See Note 3X for revisions to prior period results.

[3] Normal course issuer bids (“NCIBs”).

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Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Operating Activities
Net Earnings (Loss)	$ 6,450	$ 587	[1]	$ (2,379)	[1]
Depreciation, Depletion and Amortization	4,679	5,886		3,464
Inventories	0	16		555
Realization of Inventory Write-Downs	0	(31)		(572)
Deferred Income Tax Expense (Recovery)	642	452		(838)
Unrealized (Gain) Loss on Risk Management	(126)	2		56
Unrealized Foreign Exchange (Gain) Loss	365	(312)		(131)
Realized Foreign Exchange (Gain) Loss on Non-Operating Items	146	171		(33)
Revaluation (Gains)	(549)	0		0
Re-measurement of Contingent Payments, Net of Cash Paid	(469)	400		(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)		(81)
Unwinding of Discount on Decommissioning Liabilities	176	199		57
(Income) Loss From Equity-Accounted Affiliates	(15)	(57)		0
Distributions Received From Equity-Accounted Affiliates	65	137		0
Other	(117)	27		99
Settlement of Decommissioning Liabilities	(150)	(102)		(42)
Net Change in Non-Cash Working Capital	575	(1,227)		198
Cash From (Used in) Operating Activities	11,403	5,919		273
Investing Activities
Acquisitions, Net of Cash Acquired	(397)	735		0
Capital Investment	(3,708)	(2,563)		(859)
Proceeds From Divestitures	1,514	435		38
Payment on Divestiture of Assets	(50)	0		0
Net Cash Received on Assumption of Decommissioning Liabilities	0	75		0
Net Change in Investments and Other	(211)	17		(4)
Net Change in Non-Cash Working Capital	538	359		(38)
Cash From (Used in) Investing Activities	(2,314)	(942)		(863)
Net Cash Provided (Used) Before Financing Activities	9,089	4,977		(590)
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings	34	(77)		117
Issuance of Long-Term Debt	0	1,557		1,326
(Repayment) of Long-Term Debt	(4,149)	(2,870)		(112)
Net Issuance (Repayment) of Revolving Long-Term Debt	0	(350)		(220)
Principal Repayment of Leases	(302)	(300)		(197)
Common Shares Issued Under Stock Option Plans	138	6		0
Purchase of Common Shares Under NCIBs	(2,530)	(265)		0
Proceeds From Exercise of Warrants	62	2		0
Other inflows (outflows) of cash	(2)	0		0
Cash From (Used in) Financing Activities	(7,676)	(2,507)		837
Effect of Foreign Exchange on Cash and Cash Equivalents	238	25		(55)
Increase (Decrease) in Cash and Cash Equivalents	1,651	2,495		192
Cash and Cash Equivalents, Beginning of Year	2,873	378		186
Cash and Cash Equivalents, End of Year	4,524	2,873		378
Common shares
Financing Activities
Dividends paid	(682)	(176)		(77)
Variable Dividends Paid on Common Shares	(219)	0		0
Preference shares
Financing Activities
Dividends paid	$ (26)	$ (34)		$ 0

[1] See Note 3X for revisions to prior period results.

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Basis of Preparation and Statement of Compliance

12 Months Ended

Dec. 31, 2022

Basis Of Preparation And Statement Of Compliance [Abstract]

Basis of Preparation and Statement of Compliance

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements have been prepared in accordance with IFRS as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee.

These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Company’s accounting policies disclosed in Note 3.

These Consolidated Financial Statements were approved by the Board of Directors effective February 15, 2023.

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Description of Business and Segmented Disclosures

12 Months Ended

Dec. 31, 2022

Disclosure Of Reportable Segments [Abstract]

DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc., including its subsidiaries, (together “Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States (“U.S.”). On January 1, 2021, Cenovus and Husky Energy Inc. (“Husky”) closed a transaction to combine the two companies through a plan of arrangement (the “Arrangement”) (see Note 5C). The transaction included Husky's upstream assets, extensive transportation, storage and logistics and downstream infrastructure. Comparative figures include Cenovus's results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.

Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. The executive and registered office is located at 4100, 225 6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2.

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative periods have been re-presented to reflect this change (see Note 3X).

The Company operates through the following reportable segments:

Upstream Segments

•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

•Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.

•Offshore, includes offshore operations, exploration and development activities in China and the East Coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

•Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.

•U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima Refinery and Superior Refinery, the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66) and the jointly-owned Toledo Refinery (jointly owned with operator BP Products North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel and jet fuel.

Corporate and Eliminations

Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices.

A) Results of Operations – Segment and Operational Information

	Upstream
For the years ended December 31,	Oil Sands			Conventional			Offshore			Total
	2022	2021 (1)	2020	2022	2021	2020	2022	2021	2020	2022	2021 (1)	2020
Revenues
Gross Sales	34,775	22,827	8,804	4,332	3,235	904	2,020	1,782	—	41,127	27,844	9,708
Less: Royalties	4,493	2,196	331	298	150	40	77	108	—	4,868	2,454	371
	30,282	20,631	8,473	4,034	3,085	864	1,943	1,674	—	36,259	25,390	9,337
Expenses
Purchased Product	4,810	2,404	1,262	2,023	1,655	268	—	—	—	6,833	4,059	1,530
Transportation and    Blending	12,036	8,625	4,683	143	74	81	15	15	—	12,194	8,714	4,764
Operating	2,930	2,451	1,156	541	551	320	318	239	—	3,789	3,241	1,476
Realized (Gain) Loss on Risk    Management	1,527	786	268	92	2	—	—	—	—	1,619	788	268
Operating Margin	8,979	6,365	1,104	1,235	803	195	1,610	1,420	—	11,824	8,588	1,299
Unrealized (Gain) Loss on    Risk Management	(68)	18	57	13	1	—	—	—	—	(55)	19	57
Depreciation, Depletion and    Amortization	2,763	2,666	1,687	370	3	880	585	492	—	3,718	3,161	2,567
Exploration Expense	9	16	9	1	(3)	82	91	5	—	101	18	91
(Income) Loss From Equity-    Accounted Affiliates	8	(5)	—	—	—	—	(23)	(47)	—	(15)	(52)	—
Segment Income (Loss)	6,267	3,670	(649)	851	802	(767)	957	970	—	8,075	5,442	(1,416)

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).

	Downstream
	Canadian Manufacturing			U.S. Manufacturing			Total
For the years ended December 31,	2022	2021 (1)	2020	2022	2021	2020	2022	2021 (1)	2020
Revenues
Gross Sales	7,792	6,215	82	30,310	20,043	4,733	38,102	26,258	4,815
Less: Royalties	—	—	—	—	—	—	—	—	—
	7,792	6,215	82	30,310	20,043	4,733	38,102	26,258	4,815
Expenses
Purchased Product	6,389	5,156	—	26,112	17,955	4,429	32,501	23,111	4,429
Transportation and Blending	—	—	—	—	—	—	—	—	—
Operating	704	486	37	2,346	1,772	748	3,050	2,258	785
Realized (Gain) Loss on Risk    Management	—	—	—	112	104	(21)	112	104	(21)
Operating Margin	699	573	45	1,740	212	(423)	2,439	785	(378)
Unrealized (Gain) Loss on Risk    Management	—	—	—	18	1	(1)	18	1	(1)
Depreciation, Depletion and    Amortization	208	226	8	640	2,381	728	848	2,607	736
Exploration Expense	—	—	—	—	—	—	—	—	—
(Income) Loss From Equity-Accounted     Affiliates	—	—	—	—	—		—	—	—
Segment Income (Loss)	491	347	37	1,082	(2,170)	(1,150)	1,573	(1,823)	(1,113)

(1)Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

	Corporate and Eliminations			Consolidated
For the years ended December 31,	2022	2021 (1) (2)	2020	2022	2021 (1) (2)	2020
Revenues
Gross Sales	(7,464)	(5,291)	(609)	71,765	48,811	13,914
Less: Royalties	—	—	—	4,868	2,454	371
	(7,464)	(5,291)	(609)	66,897	46,357	13,543
Expenses
Purchased Product	(5,533)	(3,844)	(278)	33,801	23,326	5,681
Transportation and Blending	(664)	(676)	(36)	11,530	8,038	4,728
Operating	(1,270)	(783)	(306)	5,569	4,716	1,955
Realized (Gain) Loss on Risk Management	31	101	5	1,762	993	252
Unrealized (Gain) Loss on Risk Management	(89)	(18)	—	(126)	2	56
Depreciation, Depletion and Amortization	113	118	161	4,679	5,886	3,464
Exploration Expense	—	—	—	101	18	91
(Income) Loss From Equity-Accounted Affiliates	—	(5)	—	(15)	(57)	—
Segment Income (Loss)	(52)	(184)	(155)	9,596	3,435	(2,684)
General and Administrative	865	849	292	865	849	292
Finance Costs	820	1,082	536	820	1,082	536
Interest Income	(81)	(23)	(9)	(81)	(23)	(9)
Integration and Transaction Costs	106	349	29	106	349	29
Foreign Exchange (Gain) Loss, Net	343	(174)	(181)	343	(174)	(181)
Revaluation (Gains)	(549)	—	—	(549)	—	—
Re-measurement of Contingent Payment	162	575	(80)	162	575	(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)	(81)	(269)	(229)	(81)
Other (Income) Loss, Net	(532)	(309)	40	(532)	(309)	40
	865	2,120	546	865	2,120	546
Earnings (Loss) Before Income Tax				8,731	1,315	(3,230)
Income Tax Expense (Recovery)				2,281	728	(851)
Net Earnings (Loss)				6,450	587	(2,379)

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).

(2)Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

B) Revenues by Product

For the years ended December 31,	2022	2021	2020
Upstream
Crude Oil (1)	29,834	19,877	8,017
NGLs (1)	2,346	1,983	727
Natural Gas	3,690	3,032	535
Other	389	498	58
Downstream
Canadian Manufacturing
Synthetic Crude Oil	2,360	1,951	—
Asphalt	620	477	—
Other Products and Services (2)	4,812	3,787	82
U.S. Manufacturing
Gasoline	14,116	10,111	2,352
Diesel and Distillate	11,453	6,429	1,569
Other Products	4,741	3,503	812
Corporate and Eliminations (2)	(7,464)	(5,291)	(609)
Consolidated	66,897	46,357	13,543

(1)Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.

(2)Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

C) Geographical Information

	Revenues (1)
For the years ended December 31,	2022	2021	2020
Canada	33,222	23,768	8,715
United States	32,313	21,326	4,828
China	1,362	1,263	—
Consolidated	66,897	46,357	13,543

(1)Revenues by country are classified based on where the operations are located.

	Non-Current Assets (1)
As at December 31,	2022	2021 (2)
Canada	35,194	33,981
United States	4,824	4,093
China	2,064	2,583
Indonesia	365	311
Consolidated	42,447	40,968

(1)Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill.

(2)Canada excludes assets held for sale of $1.3 billion that were divested in 2022.

Major Customers

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2022, Cenovus had two customers (2021 – two; 2020 – three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $16.1 billion and $9.1 billion, respectively (2021 – $8.5 billion and $6.8 billion; 2020 – $4.3 billion, $1.8 billion and $1.5 billion, respectively), and are reported across all of the Company’s operating segments.

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
As at December 31,	2022	2021	2022	2021	2022	2021
Oil Sands	674	653	24,657	22,535	638	754
Conventional	6	6	2,020	2,174	2	2
Offshore	5	61	2,549	2,822	152	160
Canadian Manufacturing (1)	—	—	2,466	2,558	252	388
U.S. Manufacturing	—	—	4,482	3,745	329	252
Corporate and Eliminations	—	—	325	391	472	454
Consolidated	685	720	36,499	34,225	1,845	2,010

	Goodwill		Total Assets
As at December 31,	2022	2021	2022	2021 (2)
Oil Sands	2,923	3,473	32,248	31,070
Conventional	—	—	2,410	3,026
Offshore	—	—	3,339	3,597
Canadian Manufacturing (1)	—	—	3,172	3,884
U.S. Manufacturing (3)	—	—	8,324	7,509
Corporate and Eliminations (3)	—	—	6,376	5,018
Consolidated	2,923	3,473	55,869	54,104

(1)Prior period results have been re-presented. PP&E, ROU assets and total assets from the remaining commercial fuels business and the historic retail fuels business have been aggregated with the Canadian Manufacturing segment. 

(2)Total assets include assets held for sale $1.3 billion that were divested in 2022.

(3)Prior period results were re-presented to move income tax receivable and deferred income tax assets from the U.S. Manufacturing segment to the Corporate and Eliminations segment.

E) Capital Expenditures (1)

For the years ended December 31,	2022	2021	2020
Capital Investment
Oil Sands	1,792	1,019	427
Conventional	344	222	78
Offshore
Asia Pacific	8	21	—
Atlantic	302	154	—
Total Upstream	2,446	1,416	505
Canadian Manufacturing (2)	117	68	33
U.S. Manufacturing	1,059	995	243
Total Downstream	1,176	1,063	276
Corporate and Eliminations	86	84	60
	3,708	2,563	841
Acquisitions (Note 5)
Oil Sands (3)	1,609	5,005	6
Conventional	12	551	12
Offshore (4)	—	3,129	—
Canadian Manufacturing (2)	—	2,973	—
U.S. Manufacturing	—	1,618	—
Corporate and Eliminations	—	156	—
	1,621	13,432	18
Total Capital Expenditures	5,329	15,995	859

(1)Includes expenditures on PP&E, E&E assets and capitalized interest.

(2)Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

(3)Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-existing interest in SOSP of $1.6 billion.

(4)Excludes capital expenditures related to the HCML joint venture, which are accounted for using the equity method.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Disclosure Of Summary Of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A) Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s accounts reflect its share of the assets, liabilities, revenues and expenses from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s activities relate to joint ventures, which are accounted for using the equity method of accounting.

An associate is an entity for which the Company has significant influence over but does not control or jointly control the affiliate. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter to recognize the Company’s share of the affiliate’s profit or loss and other comprehensive income (“OCI”).

B) Foreign Currency Translation

Functional and Presentation Currency

The Company’s functional and presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in OCI as cumulative translation adjustments.

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests.

Transactions and Balances

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the reporting date. Any gains or losses are recorded in the Consolidated Statements of Earnings (Loss).

C) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided.

Cenovus recognizes revenue from the following major products and services:

•Sale of crude oil, NGLs and natural gas.

•Sale of petroleum and refined products.

•Crude oil and natural gas processing services.

•Pipeline transportation, the blending of crude oil and the storage of crude oil, diluent and natural gas.

•Fee-for-service hydrocarbon transloading services.

•Construction services.

The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products, which is generally at a point in time. Performance obligations for crude oil and natural gas processing revenue, transportation services and transloading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Revenue associated with natural gas processing, transportation services and transloading services are generally based on fixed price contracts.

Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and revenue from cost-plus contracts are recognized as services are performed.

The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date, the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered or the deferral provision can no longer be extended.

Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with the exception of certain construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.Purchased ProductThe cost of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market are recorded as purchased product.

E) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of diluent used in blending, are recognized when the product is sold.

F) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.

Certain costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

G) Employee Benefit Plans

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component.

Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans, benefits are not funded before retirement.

Pension expense for the defined contribution pension is recorded as the benefits are earned.

The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans.

Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows:

•Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs.

•Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

•Re-measurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Re-measurements are not reclassified to net earnings in subsequent periods.

Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded.

H) Government Grants

Government grants are recognized when there is reasonable assurance that the grant will be received and all conditions associated with the grant are met. If a grant is received, but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. Grants related to assets are recorded as a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the services have been performed.

I) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

J) Related Party Transactions

The Company enters into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value. Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.

K) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

L) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a maturity of three months or less.

Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within twelve months, it is classified as a non-current asset.

M) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

N) Exploration and Evaluation Assets

Certain costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. E&E assets are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired or the future economic value has decreased. E&E assets are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.

Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as depreciation, depletion and amortization (“DD&A”), is recognized on this production using a unit-of-production method based on estimated proved reserves determined using forward prices and costs and considering any estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an energy equivalent basis.

Non-producing assets classified as E&E are not depleted.

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

Any gains or losses from the divestiture of E&E assets are recognized in net earnings.

O) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated DD&A, and net of any impairment losses. Expenditures related to renewals or enhancements that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

Any gains or losses from the divestiture of PP&E are recognized in net earnings.

Crude Oil and Natural Gas Properties

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties and related infrastructure facilities, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations, natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to be incurred in developing those reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of either the asset received, or the asset given up, cannot be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and natural gas properties are depleted using a unit-of-production method.

Manufacturing Assets

The initial costs of refining and upgrading PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining and upgrading assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

•Land improvements and buildings: 15 to 40 years.

•Office improvements and buildings: 3 to 15 years.

•Refining equipment: 10 to 60 years.

The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate.

Processing, Transportation and Storage Assets, Commercial Fuels Business and Other

Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available for use by the Company.

The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

P) Impairment and Impairment Reversals of Non-Financial Assets

PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is estimated based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), costs to develop and the discount rate, and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.

Q) Leases

The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company has elected not to separate non-lease components.

As Lessee

Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments, costs to be incurred by the lessee in dismantling, removing and restoring the underlying asset, variable lease payments that are based on an index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating the lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with reasonably similar characteristics.

Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings over the lease term.

The lease liability is measured at amortized cost using the effective interest method. It is re-measured when there is a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the Company will exercise a purchase, extension or termination option that is within the control of the Company.

When the lease liability is re-measured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero.

The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date.

The ROU asset is depreciated on a straight-line basis, over the shorter of the estimated useful life of the asset or lease term, or using the unit-of-production method. The ROU asset may be adjusted for certain re-measurements of the lease liability and impairment losses.

Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating, transportation or general and administrative expense.

A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will re-measure the lease liability using the Company’s incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope.

As Lessor

As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments received under operating leases as income on a straight-line basis over the lease term as other income.

When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the sublease is classified as an operating lease.

Intangible AssetsIntangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset. Impairment losses are recognized in the Consolidated Statements of Earnings(Loss) as DD&A.

S) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited to net earnings. Acquisition costs are expensed as incurred.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity in accordance with the terms of the agreement. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

Provisions

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings (Loss).

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, surface and subsea plant and equipment, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Onerous Contract Provisions

Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss).

Renewable Fuel Obligations

The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured as the expected market price of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the month purchased. RINs purchased on a secondary market are measured at cost. A net RIN position is presented in other assets and a net RVO position is included in other liabilities.

U) Share Capital and Warrants

Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the Company’s option. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative.

Transaction costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s paid in surplus. Common shares are cancelled subsequent to being purchased.

Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are recorded as share capital.

V) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expenses, or recorded to PP&E or E&E assets when directly related to exploration or development activities.

Stock Options With Associated Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation over the vesting period, with a corresponding increase recorded as paid in surplus in shareholders’ equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Cenovus Replacement Stock Options

Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the stock option is recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation in the period they occur. Stock-based compensation is recorded to PP&E or E&E assets when it is directly related to exploration or development activities.

W) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets, net investment in finance leases, investments in the equity of companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, risk management liabilities and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously.

The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

•Level 1 inputs are quoted prices in active markets for identical assets and liabilities.

•Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly.

•Level 3 inputs are unobservable inputs for the asset or liability.

Classification and Measurement of Financial Assets

The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets:

•Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

•FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

•Fair Value through Profit or Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets.

On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis.

At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.

Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model.

A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership.

Impairment of Financial Assets

The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component.

Classification and Measurement of Financial Liabilities

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable.

Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.

A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is re-measured based on the new cash flows and a gain or loss is recorded in net earnings.

Derivatives

Derivative financial instruments are primarily used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

Derivative financial instruments are measured at FVTPL unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

X) Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures

Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands segment and Corporate and Eliminations segment was revised.

During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows.

The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the corresponding revised amounts:

Year Ended December 31, 2021

Oil Sands Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Purchased Product	3,188	(784)	—	2,404
Transportation and Blending	7,841	784	—	8,625
	11,029	—	—	11,029

Canadian Manufacturing	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	4,472	—	1,743	6,215
Purchased Product	3,552	—	1,604	5,156
Operating	388	—	98	486
Depreciation, Depletion and Amortization	167	—	59	226
	365	—	(18)	347

Retail	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	2,158	—	(2,158)	—
Purchased Product	2,019	—	(2,019)	—
Operating	98	—	(98)	—
Depreciation, Depletion and Amortization	59	—	(59)	—
	(18)	—	18	—

Corporate and Eliminations Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	(5,706)	—	415	(5,291)
Purchased Product	(4,888)	629	415	(3,844)
Transportation and Blending	(47)	(629)	—	(676)
	(771)	—	—	(771)

Consolidated	Previously Reported	Revision	Segment Aggregation	Revised
Purchased Product	23,481	(155)	—	23,326
Transportation and Blending	7,883	155	—	8,038
	31,364	—	—	31,364

Y) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business.

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Critical Accounting Judgments and Key Sources of Estimation Uncertainty

12 Months Ended

Dec. 31, 2022

Disclosure Of Accounting Judgements And Estimates [Abstract]

Critical Accounting Judgments and Key Sources of Estimation Uncertainty

4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

A) Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.

Joint Arrangements

The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in the following jointly controlled entities:

•WRB Refining LP (“WRB”).

•BP-Husky Refining LLC (“Toledo”).

It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB and Toledo. As a result, the joint arrangements are classified as joint operations and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with BP Canada Energy Group ULC (“BP Canada”) and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”). As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to August 31, 2022, Cenovus controls SOSP, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, SOSP was consolidated.

In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:

•The original intention of the joint arrangements was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.

•The agreements require the partners to make contributions if funds are insufficient to meet the obligations or liabilities of the corporation and partnerships. The past development of SOSP, and the past and future development of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.

•WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt facility until November 2022.

•SOSP was operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants in accordance with the partnership agreement. WRB and Toledo have very similar structures modified to account for the operating environment of the refining business.

•Cenovus, Phillips 66 and BP, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangements do not have employees and, as such, are not capable of performing these roles.

•In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and impairment reversals.

Recoveries from Insurance Claims

The Company uses estimates and assumptions on the amount recorded for insurance proceeds that are reasonably certain to be received. Accordingly, actual results may differ from these estimated recoveries.

B) Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

The evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could change assumptions used to determine the recoverable amount of the Company’s PP&E and E&E assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects, may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built into our estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for energy.

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands, Conventional and Offshore segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Recoverable amounts for the Company’s manufacturing assets, crude-by-rail terminal and related ROU assets use assumptions such as throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Recoverable amounts for the Company’s real estate ROU assets use assumptions such as real estate market conditions which includes market vacancy rates and sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of liabilities and estimate the future value. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired, liabilities assumed and assets given up in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparable transactions and discounted cash flows. For the Company’s upstream assets, key assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves and resources for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.

Income Tax Provisions

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.

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Acquisitions

12 Months Ended

Dec. 31, 2022

Business Combinations [Abstract]

Acquisitions

5. ACQUISITIONS

A) Sunrise Oil Sands Partnership

i) Summary of the Acquisition

On August 31, 2022, Cenovus closed the transaction with BP Canada to purchase the remaining 50 percent interest in SOSP, previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). The Sunrise Acquisition had an effective date of May 1, 2022. It provides Cenovus with full ownership and further enhances Cenovus’s core strength in the oil sands.

The Sunrise Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is recorded as goodwill.

ii) Identifiable Assets Acquired and Liabilities Acquired

The purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect items not initially identified, as well as new information obtained about the conditions that existed at the date of the Sunrise Acquisition. Changes to identifiable assets acquired and liabilities assumed includes increases of $26 million to both PP&E and decommissioning liabilities. The impact to DD&A and finance costs (including the unwinding of the discount on decommissioning liabilities) as a result of the measurement period adjustments was not material.

As at	August 31, 2022
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	9
Accounts Receivable and Accrued Revenues	164
Inventories	88
Property, Plant and Equipment	3,218
Accounts Payable and Accrued Liabilities	(313)
Income Tax Payable	(39)
Decommissioning Liabilities	(48)
Deferred Income Tax Liabilities	(486)
Total Identifiable Net Assets	2,593

The fair value and gross contractual amount of acquired accounts receivable and accrued revenues is $164 million, all of which was collected.

iii) Total Consideration

Total consideration for the Sunrise Acquisition consisted of $600 million in cash, before closing adjustments, and Cenovus’s 35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. Cenovus also agreed to make quarterly variable payments to BP Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a specified threshold. The maximum cumulative variable payment is $600 million. The following table summarizes the fair value of total consideration:

As at	August 31, 2022
Cash, Net of Closing Adjustments	394
Bay Du Nord	40
Variable Payment	600
Total Consideration	1,034

Non-monetary assets transferred as part of consideration must be re-measured at their acquisition-date fair value, with any gain or loss recognized in net earnings (loss). As a result, the Company re-measured its interest in Bay du Nord to its estimated fair value and recognized a non-cash revaluation gain of $40 million.

Cenovus agreed to make quarterly payments from SOSP to BP Canada for up to two years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel. The first quarterly period ended on November 30, 2022. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price in the quarter less $53.00 multiplied by $2.8 million, for any of the eight quarters in which the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the contract term is $600 million.

The variable payment is accounted for as a financial instrument. The fair value of $600 million on August 31, 2022, was estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS differential futures pricing. The variable payment will be re-measured at fair value with changes in fair value recognized in net earnings (loss) at each reporting date until the earlier of when the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed (see Note 28).

iv) Goodwill

As at	August 31, 2022
Total Purchase Consideration	1,034
Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership	1,559
Fair Value of Identifiable Net Assets	(2,593)
Goodwill	—

Current and deferred income tax liabilities were recognized in the purchase price allocation for the 50 percent interest acquired in SOSP. The deferred income tax liability arises from the difference between the fair value of the acquired assets and liabilities assumed, and their tax basis.

Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership

Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11; therefore, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The acquisition-date fair value of the previously held interest was estimated to be $1.6 billion. The net carrying value of the SOSP assets was $960 million, including previously recorded goodwill (see Note 24). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re-measurement of its existing interest in SOSP to fair value.

v) Revenue and Profit Contribution

The acquired business contributed revenues of $599 million and net earnings of $nil for the period from August 31, 2022, to December 31, 2022. If the closing of the Sunrise Acquisition had occurred on January 1, 2022, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2022, would have been $67.8 billion and $6.6 billion, respectively. These amounts have been calculated using results from the acquired business, adjusting them for:

•Additional DD&A that would have been charged assuming the fair value adjustments to PP&E had applied from January 1, 2022.

•Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2022.

•The consequential tax effects.

This pro forma information is not necessarily indicative of the results that would have been obtained if the Sunrise Acquisition had actually occurred on January 1, 2022.

B) BP-Husky Refining LLC

On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest in Toledo (the “Toledo Acquisition”). After closing the transaction, Cenovus will operate the Toledo Refinery. Total consideration for the transaction includes US$300 million in cash plus the value of inventory. The Toledo Acquisition will be accounted for using the acquisition method pursuant to IFRS 3. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The refinery remains shut down in a safe state. The acquisition is expected to close at the end of February 2023.

) Husky Energy Inc.

On January 1, 2021, Cenovus and Husky closed the Arrangement. The following table summarizes the details of the consideration and the recognized amounts of assets acquired and liabilities assumed at the date of the acquisition.

As at	January 1, 2021
Consideration
Common Shares	6,111
Preferred Shares	519
Share Purchase Warrants	216
Replacement Stock Options	9
Other	17
Non-Controlling Interest	11
Total Consideration and Non-Controlling Interest	6,883
Identifiable Assets Acquired and Liabilities Assumed
Cash	735
Restricted Cash	164
Accounts Receivable and Accrued Revenues	1,307
Inventories	1,133
Exploration and Evaluation Assets	45
Property, Plant and Equipment	13,296
Right-of-Use Assets	1,132
Long-Term Income Tax Receivable	66
Other Assets	230
Investment in Equity-Accounted Affiliates	363
Deferred Income Tax Assets, Net	1,062
Accounts Payable and Accrued Liabilities	(2,283)
Income Tax Payable	(94)
Short-Term Borrowings	(40)
Long-Term Debt	(6,602)
Lease Liabilities	(1,441)
Decommissioning Liabilities	(2,697)
Other Liabilities	(782)
Total Identifiable Net Assets	5,594
Goodwill	1,289

Goodwill of $1.3 billion was attributable to the Lloydminster thermal assets of $651 million; the Sunrise asset of $550 million; and the Tucker asset of $88 million, within the Oil Sands segment.

) Terra NovaOn September 8, 2021, the Company acquired an additional working    interest of 21 percent of the Terra Nova field in Atlantic Canada. Cenovus’s working interest in the joint operation is now 34 percent. The total consideration paid was $3 million, net of closing adjustments, and the effective date of the transaction was April 1, 2021. The additional working interest acquired was accounted for as an asset acquisition. Cenovus acquired cash of $78 million and PP&E of $84 million, and assumed decommissioning liabilities of     $159 million.

8. INTEGRATION AND TRANSACTION COSTS

Arrangement integration costs of $90 million were recognized in net earnings (loss) for the year ended December 31, 2022 (2021 – $349 million; 2020 – $29 million).

Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022, associated with the Sunrise Acquisition and the pending Toledo Acquisition.

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General and Administrative

12 Months Ended

Dec. 31, 2022

General And Administrative Expenses [Abstract]

General and Administrative

6. GENERAL AND ADMINISTRATIVE

For the years ended December 31,	2022	2021	2020
Salaries and Benefits	204	264	145
Administrative and Other	297	225	102
Stock-Based Compensation Expense (Recovery) (Note 34)	373	159	49
Other Incentive Benefits Expense (Recovery)	(9)	201	(4)
	865	849	292

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Finance Costs

12 Months Ended

Dec. 31, 2022

Finance Costs [Abstract]

Finance Costs

7. FINANCE COSTS

For the years ended December 31,	2022	2021	2020
Interest Expense – Short-Term Borrowings and Long-Term Debt	478	557	392
Net Premium (Discount) on Redemption of Long-Term Debt (1)	(29)	121	(25)
Interest Expense – Lease Liabilities (Note 27)	163	171	87
Unwinding of Discount on Decommissioning Liabilities (Note 29)	176	199	57
Other	37	34	25
	825	1,082	536
Capitalized Interest	(5)	—	—
	820	1,082	536

(1)     Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.

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Integration and Transaction Costs

12 Months Ended

Dec. 31, 2022

Integration Costs [Abstract]

Integration and Transaction Costs

5. ACQUISITIONS

A) Sunrise Oil Sands Partnership

i) Summary of the Acquisition

On August 31, 2022, Cenovus closed the transaction with BP Canada to purchase the remaining 50 percent interest in SOSP, previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). The Sunrise Acquisition had an effective date of May 1, 2022. It provides Cenovus with full ownership and further enhances Cenovus’s core strength in the oil sands.

The Sunrise Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is recorded as goodwill.

ii) Identifiable Assets Acquired and Liabilities Acquired

The purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect items not initially identified, as well as new information obtained about the conditions that existed at the date of the Sunrise Acquisition. Changes to identifiable assets acquired and liabilities assumed includes increases of $26 million to both PP&E and decommissioning liabilities. The impact to DD&A and finance costs (including the unwinding of the discount on decommissioning liabilities) as a result of the measurement period adjustments was not material.

As at	August 31, 2022
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	9
Accounts Receivable and Accrued Revenues	164
Inventories	88
Property, Plant and Equipment	3,218
Accounts Payable and Accrued Liabilities	(313)
Income Tax Payable	(39)
Decommissioning Liabilities	(48)
Deferred Income Tax Liabilities	(486)
Total Identifiable Net Assets	2,593

The fair value and gross contractual amount of acquired accounts receivable and accrued revenues is $164 million, all of which was collected.

iii) Total Consideration

Total consideration for the Sunrise Acquisition consisted of $600 million in cash, before closing adjustments, and Cenovus’s 35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. Cenovus also agreed to make quarterly variable payments to BP Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a specified threshold. The maximum cumulative variable payment is $600 million. The following table summarizes the fair value of total consideration:

As at	August 31, 2022
Cash, Net of Closing Adjustments	394
Bay Du Nord	40
Variable Payment	600
Total Consideration	1,034

Non-monetary assets transferred as part of consideration must be re-measured at their acquisition-date fair value, with any gain or loss recognized in net earnings (loss). As a result, the Company re-measured its interest in Bay du Nord to its estimated fair value and recognized a non-cash revaluation gain of $40 million.

Cenovus agreed to make quarterly payments from SOSP to BP Canada for up to two years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel. The first quarterly period ended on November 30, 2022. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price in the quarter less $53.00 multiplied by $2.8 million, for any of the eight quarters in which the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the contract term is $600 million.

The variable payment is accounted for as a financial instrument. The fair value of $600 million on August 31, 2022, was estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS differential futures pricing. The variable payment will be re-measured at fair value with changes in fair value recognized in net earnings (loss) at each reporting date until the earlier of when the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed (see Note 28).

iv) Goodwill

As at	August 31, 2022
Total Purchase Consideration	1,034
Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership	1,559
Fair Value of Identifiable Net Assets	(2,593)
Goodwill	—

Current and deferred income tax liabilities were recognized in the purchase price allocation for the 50 percent interest acquired in SOSP. The deferred income tax liability arises from the difference between the fair value of the acquired assets and liabilities assumed, and their tax basis.

Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership

Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11; therefore, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The acquisition-date fair value of the previously held interest was estimated to be $1.6 billion. The net carrying value of the SOSP assets was $960 million, including previously recorded goodwill (see Note 24). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re-measurement of its existing interest in SOSP to fair value.

v) Revenue and Profit Contribution

The acquired business contributed revenues of $599 million and net earnings of $nil for the period from August 31, 2022, to December 31, 2022. If the closing of the Sunrise Acquisition had occurred on January 1, 2022, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2022, would have been $67.8 billion and $6.6 billion, respectively. These amounts have been calculated using results from the acquired business, adjusting them for:

•Additional DD&A that would have been charged assuming the fair value adjustments to PP&E had applied from January 1, 2022.

•Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2022.

•The consequential tax effects.

This pro forma information is not necessarily indicative of the results that would have been obtained if the Sunrise Acquisition had actually occurred on January 1, 2022.

B) BP-Husky Refining LLC

On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest in Toledo (the “Toledo Acquisition”). After closing the transaction, Cenovus will operate the Toledo Refinery. Total consideration for the transaction includes US$300 million in cash plus the value of inventory. The Toledo Acquisition will be accounted for using the acquisition method pursuant to IFRS 3. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The refinery remains shut down in a safe state. The acquisition is expected to close at the end of February 2023.

) Husky Energy Inc.

On January 1, 2021, Cenovus and Husky closed the Arrangement. The following table summarizes the details of the consideration and the recognized amounts of assets acquired and liabilities assumed at the date of the acquisition.

As at	January 1, 2021
Consideration
Common Shares	6,111
Preferred Shares	519
Share Purchase Warrants	216
Replacement Stock Options	9
Other	17
Non-Controlling Interest	11
Total Consideration and Non-Controlling Interest	6,883
Identifiable Assets Acquired and Liabilities Assumed
Cash	735
Restricted Cash	164
Accounts Receivable and Accrued Revenues	1,307
Inventories	1,133
Exploration and Evaluation Assets	45
Property, Plant and Equipment	13,296
Right-of-Use Assets	1,132
Long-Term Income Tax Receivable	66
Other Assets	230
Investment in Equity-Accounted Affiliates	363
Deferred Income Tax Assets, Net	1,062
Accounts Payable and Accrued Liabilities	(2,283)
Income Tax Payable	(94)
Short-Term Borrowings	(40)
Long-Term Debt	(6,602)
Lease Liabilities	(1,441)
Decommissioning Liabilities	(2,697)
Other Liabilities	(782)
Total Identifiable Net Assets	5,594
Goodwill	1,289

Goodwill of $1.3 billion was attributable to the Lloydminster thermal assets of $651 million; the Sunrise asset of $550 million; and the Tucker asset of $88 million, within the Oil Sands segment.

) Terra NovaOn September 8, 2021, the Company acquired an additional working    interest of 21 percent of the Terra Nova field in Atlantic Canada. Cenovus’s working interest in the joint operation is now 34 percent. The total consideration paid was $3 million, net of closing adjustments, and the effective date of the transaction was April 1, 2021. The additional working interest acquired was accounted for as an asset acquisition. Cenovus acquired cash of $78 million and PP&E of $84 million, and assumed decommissioning liabilities of     $159 million.

8. INTEGRATION AND TRANSACTION COSTS

Arrangement integration costs of $90 million were recognized in net earnings (loss) for the year ended December 31, 2022 (2021 – $349 million; 2020 – $29 million).

Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022, associated with the Sunrise Acquisition and the pending Toledo Acquisition.

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Foreign Exchange (Gain) Loss, Net

12 Months Ended

Dec. 31, 2022

Foreign Exchange Gains Losses [Abstract]

Foreign Exchange (Gain) Loss, Net

9. FOREIGN EXCHANGE (GAIN) LOSS, NET

For the years ended December 31,	2022	2021	2020
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	365	(230)	(194)
Other	—	(82)	63
Unrealized Foreign Exchange (Gain) Loss	365	(312)	(131)
Realized Foreign Exchange (Gain) Loss	(22)	138	(50)
	343	(174)	(181)

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Divestitures

12 Months Ended

Dec. 31, 2022

Non-Current Assets Held For Sale And Discontinued Operations [Abstract]

Divestitures

10. DIVESTITURES

A) 2022 Divestitures

On January 31, 2022, the Company closed the sale of its Tucker asset in its Oil Sands segment for net proceeds of $730 million and recorded a before-tax gain of $165 million (after-tax gain – $126 million).

On February 28, 2022, the Company closed the sale of its Wembley assets in its Conventional segment for net proceeds of $221 million and recorded a before-tax gain of $76 million (after-tax gain – $58 million).

In September 2021, the Company entered into an agreement with a partner in the White Rose project in the Atlantic region that would transfer 12.5 percent of Cenovus’s working interest in the White Rose field and the satellite extensions, subject to certain closing conditions. On May 31, 2022, the final closing conditions were satisfied, which included the approval of the West White Rose project restarting. Cenovus paid $50 million associated with transferring the Company’s working interest, resulting in a before-tax gain of $62 million (after-tax gain – $47 million).

On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. (“Headwater”) for proceeds of $110 million, with no gain or loss recognized as the investment was recorded at fair value prior to the sale.

On September 13, 2022, the Company closed the sales of 337 gas stations in the historic retail fuels business, located across Western Canada and Ontario, for net cash proceeds of $404 million and recorded a before-tax loss of $74 million (after-tax loss – $56 million).

B) 2021 Divestitures

Effective May 1, 2021, the Company closed the sale of its GORR in the Marten Hills area of Alberta relating to the Conventional segment. Cenovus received cash proceeds of $102 million and recorded a before-tax gain of $60 million (after-tax gain – $47 million).

The Company sold Conventional segment assets in the Kaybob area in July 2021 and assets in the East Clearwater area in August 2021 for combined gross proceeds of approximately $82 million. A before-tax gain of $17 million (after-tax gain – $13 million) was recorded on the dispositions.

In 2020, as part of the sale of the Marten Hills assets, the Company received 50 million common shares of Headwater. On October 14, 2021, the Company sold 50 million common shares of Headwater for gross proceeds of $228 million and recorded a before-tax gain of $116 million (after-tax gain – $99 million).

C) 2020 Divestitures

On December 2, 2020, the Company sold its Marten Hills assets in northern Alberta to Headwater for total consideration of $138 million, excluding the retained GORR. A before-tax gain of $79 million was recorded on the sale (after-tax gain – $65 million). Total consideration was $33 million in cash, 50 million common shares valued at $97 million and 15 million share purchase warrants valued at $8 million at the date of close.

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Impairment Charges

12 Months Ended

Dec. 31, 2022

Disclosure of impairment loss recognised or reversed for cash-generating unit [abstract]

Impairment Charges and Reversals

11. IMPAIRMENT CHARGES AND REVERSALS

At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed the recoverable amount. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. Goodwill is tested for impairment at least annually. For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates.

A) Upstream Cash-Generating Units

i) 2022 Impairment Charges and Reversals

The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its carrying amount and no impairment was recorded. 

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment are approximated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include forward prices and costs, consistent with Cenovus’s IQREs, as well as costs to develop and the discount rates. Fair values for producing properties are calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2022. All reserves are evaluated as at December 31, 2022, by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2023	2024	2025	2026	2027	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	80.33	78.50	76.95	77.61	79.16	2.00	%
Western Canadian Select (C$/barrel)	76.54	77.75	77.55	80.07	81.89	2.00	%
Condensate at Edmonton (C$/barrel)	106.22	101.35	98.94	100.19	101.74	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	4.23	4.40	4.21	4.27	4.34	2.00	%

(1)      Assumes natural gas heating value of one million British thermal units per thousand cubic feet (“Mcf”).

Discount Rates

Discounted future cash flows are determined by applying a discount rate between 14 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

For the Sunrise CGU, a one percent increase in the discount rate would result in an impairment of $69 million and a five percent decrease in forward price estimates would result in an impairment of $226 million. A one percent increase in the discount rate or a five percent decrease in forward price estimates would not impact the result of the impairment tests performed on CGUs with associated goodwill.

ii) 2021 Impairment Charges and Reversals

As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. As at December 31, 2021, there were indicators of impairment reversals for the Company’s upstream CGUs due to an increase in forward commodity prices. An assessment was performed and indicated the recoverable amount was greater than the carrying value.

As at December 31, 2021, the recoverable amount of the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs was estimated to be $2.0 billion. In 2020, the Company recorded a total impairment charge of $555 million in the Conventional segment due to a decline in forward commodity prices and changes in future development plans. As at December 31, 2021, the Company reversed the full amount of impairment losses of $378 million, net of dispositions and the DD&A that would have been recorded had no impairment been recorded. The reversal was primarily due to improved forward commodity prices.

The following table summarizes impairment reversals recorded in 2021 and estimated recoverable amounts as at December 31, 2021, by CGU:

	Reversal of Impairment	Recoverable Amount
Clearwater	145	427
Elmworth-Wapiti	115	747
Kaybob-Edson	118	837

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves included forward prices and costs, consistent with Cenovus’s IQREs, costs to develop and the discount rates. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2021. All reserves were evaluated as at December 31, 2021, by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2021, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2022	2023	2024	2025	2026	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	72.83	68.78	66.76	68.09	69.45	2.00	%
Western Canadian Select (C$/barrel)	74.43	69.17	66.54	67.87	69.23	2.00	%
Edmonton C5+ (C$/barrel)	91.85	85.53	82.98	84.63	86.33	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	3.56	3.20	3.05	3.10	3.17	2.00	%

(1)      Assumes natural gas heating value of one million British thermal units per thousand cubic feet ("Mcf").

Discount Rates

Discounted future cash flows were determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the amount of impairment reversals recorded in the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs at December 31, 2021.

A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwill.

iii) 2020 Impairment Charges and Reversals

As at March 31, 2020, the Company recorded an impairment loss of $315 million in the Conventional CGU due to a decline in forward crude oil and natural gas prices. As at December 31, 2020, the Company recorded an additional impairment loss of $240 million in the Conventional CGU due to a change in future development plans.

The following table summarizes impairment losses recorded in 2020 and estimated recoverable amounts as at December 31, 2020, by CGU:

	Impairment	Recoverable Amount
Clearwater	260	160
Elmworth-Wapiti	120	259
Kaybob-Edson	175	384

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves included crude oil, NGLs and natural gas prices, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. All reserves were evaluated as at December 31, 2020, by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2021	2022	2023	2024	2025	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	47.17	50.17	53.17	54.97	56.07	2.00	%
Western Canadian Select (C$/barrel)	44.63	48.18	52.10	54.10	55.19	2.00	%
Edmonton C5+ (C$/barrel)	59.24	63.19	67.34	69.77	71.18	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	2.88	2.80	2.71	2.75	2.80	2.00	%

(1)      Assumes gas heating value of one million British thermal units per Mcf.

Discount Rates

Discounted future cash flows were determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated impairment amount used in the impairment testing completed as at December 31, 2020, for the following CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Clearwater	7	(7)	(68)	128
Elmworth-Wapiti	10	(10)	(71)	126
Kaybob-Edson	17	(19)	(71)	140

A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwillB) Downstream Cash-Generating Units

i) 2022 Impairment Charges and Reversals

As at December 31, 2022, the Company identified indicators of impairment for the Toledo CGU due to the pending acquisition of the remaining 50 percent from BP and a fire at the Toledo Refinery, and for the Superior CGU with the commissioning of the asset in preparation for restart. The total carrying amount of the Toledo and Superior CGUs was greater than the recoverable amount. An impairment charge of $1.5 billion was recorded as additional DD&A in the U.S. Manufacturing segment.

As at December 31, 2022, there were also indicators of impairment reversals for the Company’s Borger, Wood River and Lima CGUs due to an increase in forward crack spreads, resulting in higher margins for refined products. An assessment was performed that indicated the recoverable amount was greater than the carrying value of the associated CGUs. As at December 31, 2022, the Company reversed impairment charges of $1.2 billion, net of DD&A that would have been recorded had no impairment been recorded.

As at December 31, 2022, the aggregate recoverable amount of the U.S. Manufacturing CGUs was estimated to be $5.4 billion.

Key Assumptions

The recoverable amount (Level 3) of the U.S. Manufacturing CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts.

Crude Oil and Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were:

(US$/barrel)	2023	2024	2025	2026	2027
West Texas Intermediate	80.33	78.50	76.95	77.61	79.16
Differential WTI-WTS	(0.56)	(0.56)	(0.56)	(0.56)	(0.56)
Differential WTI-WCS	(23.32)	(19.09)	(17.42)	(15.87)	(15.74)
Chicago 3-2-1 Crack Spreads (WTI)	29.37	24.10	22.12	21.70	21.67

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of between 15 percent to 18 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have on the net impairment amount recorded as at December 31, 2022, for the U.S. Manufacturing segment CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
U.S. Manufacturing	69	(65)	(268)	268

	Increase (Decrease) to Impairment Reversal Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
U.S. Manufacturing	(72)	14	168	(342)

ii) 2021 Impairment Charges and Reversals

As at December 31, 2021, lower forward pricing that would result in lower margins for refined products was identified as an indicator of impairment for the Borger, Wood River, Lima and Toledo CGUs. As at December 31, 2021, the total carrying amounts of the Borger, Wood River and Lima CGUs were greater than the recoverable amount of $2.5 billion. An impairment charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, there was no impairment of the Toledo CGU.

Key Assumptions

The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads were based on an average of third-party consultant forecasts.

Crude Oil and Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2021, the forward prices used to determine future cash flows were:

	2022 to 2023		2024 to 2026
(US$/barrel)	Low	High	Low	High
West Texas Intermediate	68.78	72.83	66.76	69.45
Differential WTI-WTS	—	0.01	(0.06)	(0.06)
Differential WTI-WCS	13.54	13.67	13.75	14.30
Chicago 3-2-1 Crack Spreads (WTI)	14.87	18.44	14.68	16.81

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2037.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent to 12 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have had on the calculated recoverable amounts used in the impairment testing completed as at December 31, 2021, for the following CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Borger, Wood River and Lima	251	(283)	(990)	996

iii) 2020 Impairment Charges and Reversals

As at September 30, 2020, the recovery in demand for refined products from the impact of the novel coronavirus lagged expectations and resulted in higher than anticipated inventory levels. These factors, along with low market crack spreads and crude oil processing runs for North American refineries, were identified as indicators of impairment for the Wood River and Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was greater than the recoverable amount and an impairment charge of $450 million was recorded as additional DD&A in the U.S. Manufacturing segment. The recoverable amount of the Borger CGU was estimated at $692 million. As at September 30, 2020, no impairment of the Wood River CGU was identified.

Key Assumptions

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs, terminal values and the discount rate. Forward crack spreads were based on third-party consultant average forecasts.

Crude Oil and Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were:

	2021 to 2022		2023 to 2025
(US$/barrel)	Low	High	Low	High
West Texas Intermediate	36.36	50.84	49.66	58.74
Differential WTI-WTS	0.37	1.73	1.21	1.81
Group 3 3-2-1 Crack Spreads (WTI)	11.56	13.23	11.79	16.58

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount used in the impairment testing completed as at September 30, 2020, for the following CGU:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Borger	89	(110)	(348)	342

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Other Income (Loss), Net

12 Months Ended

Dec. 31, 2022

Analysis of income and expense [abstract]

Other Income (Loss), Net

12. OTHER INCOME (LOSS), NET

For the year ended December 31, 2022, the Company recorded insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region of $328 million (2021 – $120 million; 2020 – $nil).

For the year ended December 31, 2022, funding of $65 million (2021 – $42 million; 2020 – $nil) was received under the Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites.

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Income Taxes

12 Months Ended

Dec. 31, 2022

Disclosure Of Income Tax Expense Continuing Operations [Abstract]

Income Taxes

13. INCOME TAXES

A) Income Tax Expense (Recovery)

For the years ended December 31,	2022	2021	2020
Current Tax
Canada	1,252	104	(14)
United States	104	—	1
Asia Pacific	262	171	—
Other International	21	1	—
Total Current Tax Expense (Recovery)	1,639	276	(13)
Deferred Tax Expense (Recovery)	642	452	(838)
	2,281	728	(851)

For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income.

In 2021, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The increase is due to Asia Pacific operations acquired in the Arrangement and higher earnings compared to 2020. In 2021, the Company recorded a $217 million deferred tax expense due to a limitation in the availability of certain U.S. tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate change associated with provincial allocations.

In 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU, impairments in the Conventional segment and current period operating losses that will be carried forward, excluding unrealized foreign exchange gains and losses on long-term debt. In 2020, the Government of Alberta accelerated the reduction in the provincial corporate tax rate from 12 percent to eight percent.

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

For the years ended December 31,	2022		2021		2020
Earnings (Loss) From Operations Before Income Tax	8,731		1,315		(3,230)
Canadian Statutory Rate	23.7	%	23.7	%	24.0	%
Expected Income Tax Expense (Recovery) From Operations	2,069		312		(775)
Effect on Taxes Resulting From:
Statutory and Other Rate Differences	17		3		19
Non-Taxable Capital (Gains) Losses	84		63		(42)
Non-Recognition of Capital (Gains) Losses	84		27		(42)
Adjustments Arising From Prior Year Tax Filings	15		(5)		(8)
U.S. Tax Attribute Limitation	—		217		—
Impact of Rate Changes	—		106		(7)
Other	12		5		4
Total Tax Expense (Recovery) From Operations	2,281		728		(851)
Effective Tax Rate	26.1	%	55.4	%	26.3	%

B) Deferred Income Tax Assets and Liabilities

For the year ended December 31, 2022, deferred income tax liabilities of $486 million were recognized on the Sunrise Acquisition. The deferred income tax liability arises from the difference between the fair value of the assets acquired and the liabilities assumed, and their tax basis.

On January 1, 2021, as part of the Arrangement, the Company recorded net deferred tax assets of $1.1 billion. The net deferred tax assets consisted of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million related to U.S. operations, offset by a deferred tax liability of $444 million related to Asia Pacific activities. The Canadian deferred tax asset has been offset against the Canadian deferred tax liability.

The breakdown of deferred income tax liabilities and deferred income tax assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows:

For the years ended December 31,	2022	2021
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled Within Twelve Months	55	—
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months	4,460	4,046
	4,515	4,046
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months	(31)	(556)
Deferred Income Tax Assets to be Settled After More Than Twelve Months	(747)	(898)
	(778)	(1,454)
Net Deferred Income Tax Liability	3,737	2,592

The deferred income tax assets and liabilities to be settled within twelve months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year.

The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is:

Deferred Income Tax Liabilities	PP&E	Risk Management	Other	Total
As at December 31, 2020	4,124	—	22	4,146
Charged (Credited) to Earnings	(234)	—	75	(159)
Charged (Credited) to Husky Purchase Price Allocation	59	—	—	59
As at December 31, 2021	3,949	—	97	4,046
Charged (Credited) to Earnings	25	11	(53)	(17)
Charged (Credited) to Sunrise Purchase Price Allocation	486	—	—	486
As at December 31, 2022	4,460	11	44	4,515

Deferred Income Tax Assets	Unused Tax Losses	Risk Management	Other	Total
As at December 31, 2020	(659)	(13)	(276)	(948)
Charged (Credited) to Earnings	668	1	(58)	611
Charged (Credited) to Husky Purchase Price Allocation	(656)	1	(466)	(1,121)
Charged (Credited) to Other Comprehensive Income	(8)	—	12	4
As at December 31, 2021	(655)	(11)	(788)	(1,454)
Charged (Credited) to Earnings	490	11	158	659
Charged (Credited) to Sunrise Purchase Price Allocation	—	—	—	—
Charged (Credited) to Other Comprehensive Income	9	—	8	17
As at December 31, 2022	(156)	—	(622)	(778)

Net Deferred Income Tax Liabilities	Total
As at December 31, 2020	3,198
Charged (Credited) to Earnings	452
Charged (Credited) to Husky Purchase Price Allocation	(1,062)
Charged (Credited) to Other Comprehensive Income	4
As at December 31, 2021	2,592
Charged (Credited) to Earnings	642
Charged (Credited) to Sunrise Purchase Price Allocation	486
Charged (Credited) to Other Comprehensive Income	17
As at December 31, 2022	3,737

The deferred income tax asset of $546 million (2021 – $694 million) represents net deductible temporary differences in the U.S. jurisdiction which has been fully recognized, as the probability of realization is expected due to forecasted taxable income. No deferred tax liability has been recognized as at December 31, 2022 and 2021 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future.

C) Tax Pools

The approximate amounts of tax pools available, including tax losses, are:

As at December 31,	2022	2021
Canada	8,505	11,167
United States	6,477	5,915
Asia Pacific	457	600
	15,439	17,682

As at December 31, 2022, the above tax pools included $115 million (December 31, 2021 – $1.5 billion) of Canadian federal non-capital losses and $468 million (December 31, 2021 – $775 million) of U.S. net operating losses. These losses expire no earlier than 2035.

As at December 31, 2022, the Company had Canadian net capital losses totaling $28 million (December 31, 2021 – $102 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $504 million (December 31, 2021 – $102 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.

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Per Share Amounts

12 Months Ended

Dec. 31, 2022

Earnings per share [abstract]

Per Share Amounts

14. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Common Share – Basic and Diluted

For the years ended December 31,	2022	2021	2020
Net Earnings (Loss)	6,450	587	(2,379)
Effect of Cumulative Dividends on Preferred Shares	(35)	(34)	—
Net Earnings (Loss) – Basic and Diluted	6,415	553	(2,379)
Basic – Weighted Average Number of Shares	1,951.3	2,016.2	1,228.9
Dilutive Effect of Warrants	44.8	27.6	—
Dilutive Effect of Net Settlement Rights	10.0	1.3	—
Diluted – Weighted Average Number of Shares	2,006.1	2,045.1	1,228.9
Net Earnings (Loss) Per Common Share – Basic ($)	3.29	0.27	(1.94)
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)	3.20	0.27	(1.94)

(1)For the year ended December 31, 2022, net earnings of $52 million (2021 – $22 million; 2020 – $nil) and common shares of 1.6 million (2021 – 1.9 million; 2020 – nil) related to the assumed exercise of the Cenovus replacement stock options, were excluded from the calculation of dilutive net earnings (loss) per share. For further information on the Company’s stock-based compensation plans, see Note 34.

(2)For the year ended December 31, 2021 and December 31, 2020, NSRs of 18 million and 31 million, respectively, were excluded from the calculation of diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceeded the market price of Cenovus’s common shares.

B) Common Share Dividends

	2022		2021		2020
For the years ended December 31,	Per Share	Amount	Per Share	Amount	Per Share	Amount
Base Dividends	0.350	682	0.088	176	0.063	77
Variable Dividends	0.114	219	—	—	—	—
Total Common Share Dividends Declared and Paid	0.464	901	0.088	176	0.063	77

The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.

On February 15, 2023, the Company’s Board of Directors declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023.

C) Preferred Share Dividends

For the years ended December 31,	2022	2021
Series 1 First Preferred Shares	7	7
Series 2 First Preferred Shares	1	1
Series 3 First Preferred Shares	12	12
Series 5 First Preferred Shares	9	9
Series 7 First Preferred Shares	6	5
Total Preferred Share Dividends Declared	35	34

The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.

On January 3, 2023, the Company paid dividends on Cenovus’s preferred shares as declared on November 1, 2022.

On February 15, 2023, the Company’s Board of Directors declared first quarter dividends for Cenovus’s preferred shares, payable on March 31, 2023, in the amount of $9 million, to preferred shareholders of record as at March 15, 2023.

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Cash and Cash Equivalents

12 Months Ended

Dec. 31, 2022

Cash and cash equivalents [abstract]

Cash and Cash Equivalents

15. CASH AND CASH EQUIVALENTS

As at December 31,	2022	2021
Cash	3,195	2,366
Short-Term Investments	1,329	507
	4,524	2,873

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Accounts Receivable and Accrued Revenues

12 Months Ended

Dec. 31, 2022

Trade and other current receivables [abstract]

Accounts Receivable and Accrued Revenues

16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES

As at December 31,	2022	2021
Trade and Accruals	2,962	2,548
Prepaids and Deposits	402	486
Partner Advances	—	371
Joint Operations Receivables	51	225
Other (1)	58	240
	3,473	3,870

(1)As at December 31, 2022, includes insurance proceeds receivable of $nil related to the 2018 Superior Refinery incident (December 31, 2021 – $135 million).

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Inventories

12 Months Ended

Dec. 31, 2022

Classes of current inventories [abstract]

Inventories

17. INVENTORIES

As at December 31,	2022	2021
Product
Crude Oil	2,424	2,060
Diluent	366	515
Natural Gas and NGLs	50	33
Refined Products	1,169	1,043
Total Product	4,009	3,651
Parts and Supplies	303	268
	4,312	3,919

For the year ended December 31, 2022, approximately $49 billion of produced and purchased inventory was recorded as an expense (2021 – approximately $34 billion).

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Assets Held for Sale

12 Months Ended

Dec. 31, 2022

Assets Held for Sale [Abstract]

Assets Held for Sale

18. ASSETS HELD FOR SALE

The Company had the following assets held for sale as at December 31, 2021, that were sold in 2022 (see Note 10):

	PP&E	ROU Assets	Goodwill	Lease Liabilities	Decommissioning Liabilities
Retail Gas Stations	498	54	—	(58)	(86)
Tucker	505	—	88	—	(33)
Wembley	159	—	—	—	(9)
	1,162	54	88	(58)	(128)

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Exploration and Evaluation Assets, Net

12 Months Ended

Dec. 31, 2022

Disclosure Of Exploration And Evaluation Assets [Abstract]

Exploration and Evaluation Assets, Net

19. EXPLORATION AND EVALUATION ASSETS, NET

	Total
As at December 31, 2020	623
Acquisitions (Note 5)	45
Additions	55
Write-downs	(9)
Change in Decommissioning Liabilities	6
As at December 31, 2021	720
Additions	37
Write-downs	(64)
Change in Decommissioning Liabilities	(12)
Exchange Rate Movements and Other (1)	4
As at December 31, 2022	685

(1)Immediately prior to the Sunrise Acquisition, Bay du Nord had a carrying value of $nil. The Company re-measured its interest in Bay du Nord to $40 million and recognized a revaluation gain of $40 million.

For the year ended December 31, 2022, $2 million and $62 million of previously capitalized E&E costs were written off as exploration expense in the Oil Sands segment and Offshore segment, respectively (2021 – $9 million in the Oil Sands segment), as the carrying value was not considered to be recoverable.

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Property, Plant and Equipment, Net

12 Months Ended

Dec. 31, 2022

Disclosure of detailed information about property, plant and equipment [abstract]

Property, Plant and Equipment, Net

20. PROPERTY, PLANT AND EQUIPMENT, NET

	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Manufacturing Assets	Other Assets (1)	Total
COST
As at December 31, 2020	29,867	218	5,671	1,290	37,046
Acquisitions (Note 5)	8,633	—	3,901	846	13,380
Additions	1,368	9	1,023	115	2,515
Change in Decommissioning Liabilities	(63)	1	40	24	2
Divestitures (Note 10)	(630)	—	—	—	(630)
Transfers to Assets Held for Sale (Note 18)	(754)	—	—	(522)	(1,276)
Exchange Rate Movements and Other	22	—	(140)	(18)	(136)
As at December 31, 2021	38,443	228	10,495	1,735	50,901
Acquisitions (Note 5) (2)	3,230	—	—	—	3,230
Additions	2,409	11	1,143	108	3,671
Change in Decommissioning Liabilities	(186)	(6)	(29)	(32)	(253)
Divestitures (Note 5) (2)	(557)	—	—	—	(557)
Exchange Rate Movements and Other	189	21	523	14	747
As at December 31, 2022	43,528	254	12,132	1,825	57,739
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2020	8,361	42	2,195	1,037	11,635
Depreciation, Depletion and Amortization	3,335	10	526	128	3,999
Impairment Charges (Note 11)	—	—	1,931	—	1,931
Impairment Reversals (Note 11)	(378)	—	—	—	(378)
Divestitures (Note 10)	(377)	—	—	—	(377)
Transfers to Assets Held for Sale (Note 18)	(90)	—	—	(24)	(114)
Exchange Rate Movements and Other	61	1	(80)	(2)	(20)
As at December 31, 2021	10,912	53	4,572	1,139	16,676
Depreciation, Depletion and Amortization (3)	3,461	37	466	103	4,067
Impairment Charges (Note 11)	—	—	1,499	—	1,499
Impairment Reversals (Note 11)	—	—	(1,233)	—	(1,233)
Divestitures (Note 5) (2)	(84)	—	—	—	(84)
Exchange Rate Movements and Other	13	16	243	43	315
As at December 31, 2022	14,302	106	5,547	1,285	21,240
CARRYING VALUE
As at December 31, 2020	21,506	176	3,476	253	25,411
As at December 31, 2021	27,531	175	5,923	596	34,225
As at December 31, 2022	29,226	148	6,585	540	36,499

(1)Includes assets within the commercial and retail fuels businesses, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2)In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million.

(3)DD&A includes asset write-downs of $26 million in the Offshore segment and $25 million in the Canadian Manufacturing segment.

Assets Under Construction

PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A:

As at December 31,	2022	2021
Development and Production	2,142	2,415
Downstream	137	943
	2,279	3,358

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Right of Use Assets, Net

12 Months Ended

Dec. 31, 2022

Disclosure of quantitative information about right-of-use assets [abstract]

Right of Use Assets, Net

21. RIGHT-OF-USE ASSETS, NET

	Real Estate	Transportation and Storage Assets (1)	Manufacturing Assets	Other Assets (2)	Total
COST
As at December 31, 2020	495	977	15	15	1,502
Acquisitions (Note 5)	99	765	138	130	1,132
Additions	4	96	7	3	110
Modifications	1	20	1	—	22
Re-measurements	(2)	1	—	(3)	(4)
Transfers to Assets Held for Sale (Note 18)	—	—	—	(78)	(78)
Exchange Rate Movements and Other	(5)	(18)	—	(5)	(28)
As at December 31, 2021	592	1,841	161	62	2,656
Additions	—	22	1	2	25
Modifications	9	69	3	2	83
Re-measurements	1	3	2	1	7
Terminations	(1)	(6)	(2)	(1)	(10)
Exchange Rate Movements and Other	(2)	(89)	9	8	(74)
As at December 31, 2022	599	1,840	174	74	2,687
ACCUMULATED DEPRECIATION
As at December 31, 2020	58	293	5	7	363
Depreciation	38	239	23	23	323
Impairment Charges (Note 11)	—	5	5	1	11
Terminations	—	(3)	—	—	(3)
Transfers to Assets Held for Sale (Note 18)	—	—	—	(24)	(24)
Exchange Rate Movements and Other	(4)	(14)	—	(6)	(24)
As at December 31, 2021	92	520	33	1	646
Depreciation	36	226	21	14	297
Terminations	—	(6)	—	—	(6)
Exchange Rate Movements and Other	(1)	(95)	4	(3)	(95)
As at December 31, 2022	127	645	58	12	842
CARRYING VALUE
As at December 31, 2020	437	684	10	8	1,139
As at December 31, 2021	500	1,321	128	61	2,010
As at December 31, 2022	472	1,195	116	62	1,845

(1)Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.

(2)Includes assets within the commercial fuels business, fleet vehicles and other equipment.

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Joint Arrangements

12 Months Ended

Dec. 31, 2022

Subclassifications of assets, liabilities and equities [abstract]

JOINT ARRANGEMENTS

22. JOINT ARRANGEMENTS

A) Joint Operations

Cenovus has a number of joint operations in the Upstream segments. The Company also has the following joint operations held in separate entities in the U.S. Manufacturing segment.

BP-Husky Refining LLC

Cenovus holds a 50 percent interest in the Toledo Refinery with BP. BP is the operator of the refinery in Ohio and holds the remaining 50 percent interest. On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest. See Note 5 for further details.

WRB Refining LP

Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. Phillips 66 holds the remaining 50 percent interest and is the operator of the Wood River Refinery in Illinois and the Borger Refinery in Texas.

B) Joint Ventures

Husky-CNOOC Madura Ltd.

The Company holds a 40 percent interest in the jointly controlled entity, HCML, which is engaged in the exploration for and production of natural gas and NGLs in offshore Indonesia. The Company’s share of equity investment income (loss) related to the joint venture is included in the Consolidated Statements of Earnings (Loss) in the Offshore segment.

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations

For the years ended December 31,	2022	2021
Revenue	383	439
Expenses	350	395
Net Earnings (Loss)	33	44

Balance Sheet

As at December 31,	2022	2021
Current Assets (1)	247	167
Non-Current Assets	1,926	1,433
Current Liabilities	160	62
Non-Current Liabilities	1,293	896
Net Assets	720	642

(1)Includes cash and cash equivalents of $64 million (December 31, 2021 – $46 million).

For the year ended December 31, 2022, the Company’s share of income from the equity-accounted affiliate was $23 million (2021 – $47 million). As at December 31, 2022, the carrying amount of the Company’s share of net assets was $365 million (December 31, 2021 – $311 million). These amounts do not equal the 40 percent joint control of the revenues, expenses and net assets of HCML due to differences in the values attributed to the investment and accounting policies between the joint venture and the Company.

For the year ended December 31, 2022, the Company received $42 million of distributions from HCML (2021 – $100 million) and paid $54 million in contributions (2021 – $18 million).

Husky Midstream Limited Partnership

The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power Assets Holdings Ltd. holding a 49 percent interest and CK Infrastructure Holdings Ltd. holding a 16 percent interest in HMLP.

For the year ended December 31, 2022, HMLP had net earnings of $190 million (2021 – $134 million). The Company’s share of (income) loss from the equity-accounted affiliate does not equal the 35 percent of the net earnings of HMLP due to the nature of the profit-sharing arrangement as defined in the partnership agreement. The Company’s share of earnings will fluctuate depending on certain income thresholds of HMLP. For the year ended December 31, 2022, the Company did not record its share of pre-tax loss relating to HMLP of $23 million (2021 – loss of $22 million). The carrying value was $nil at December 31, 2022 and December 31, 2021.

As at December 31, 2022, the Company had $28 million in cumulative unrecognized losses and OCI, net of tax (December 31, 2021 – $17 million). The Company records its share of equity investment income related to the joint venture only in excess of the cumulated unrecognized loss and is included in the Consolidated Statements of Earnings (Loss) in the Oil Sands segment.

For the year ended December 31, 2022, the Company received $23 million of distributions from HMLP (2021 – $37 million) and paid $31 million in contributions (2021 – $32 million) to HMLP. The net amount of the distributions received and contributions paid are recorded in earnings from equity-accounted affiliates.

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Other Assets

12 Months Ended

Dec. 31, 2022

Other Noncurrent Assets [Abstract]

Other Assets

23. OTHER ASSETS

As at December 31,	2022	2021
Intangible Assets (1)	19	78
Private Equity Investments (Note 37)	55	53
Other Equity Investments	—	77
Net Investment in Finance Leases	62	60
Long-Term Receivables and Prepaids	120	77
Precious Metals	86	85
Other	—	1
	342	431

(1)    For the twelve months ended December 31, 2022, $49 million of previously capitalized intangible asset costs were written off as DD&A in the Oil Sands segment as the carrying value was not considered to be recoverable.

In December 2021, all of the outstanding share purchase warrants received in the sale of the Company's Marten Hills assets to Headwater were exercised for a total cost of $30 million. At December 31, 2021, the fair value of the Headwater investment was $77 million, included in other equity investments above. The investment was carried at FVTPL.

On June 8, 2022, the Company sold its investment in Headwater for proceeds of $110 million.

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Goodwill

12 Months Ended

Dec. 31, 2022

Goodwill [Abstract]

Goodwill

24. GOODWILL

	2022	2021
Carrying Value, Beginning of Year	3,473	2,272
Goodwill Recognized (Note 5)	—	1,289
Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18)	(550)	(88)
Carrying Value, End of Year	2,923	3,473

The carrying amount of goodwill is allocated to the following CGUs:

As at December 31,	2022	2021
Primrose (Foster Creek)	1,171	1,171
Christina Lake	1,101	1,101
Lloydminster Thermal	651	651
Sunrise (Note 5)	—	550
	2,923	3,473

For the purposes of impairment testing, goodwill is allocated to the CGUs to which it relates. The assumptions used to test Cenovus's goodwill for impairment as at December 31, 2022, are consistent with those disclosed in Note 11. There was no impairment of goodwill as at December 31, 2022 (December 31, 2021 – $nil).

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Accounts Payable and Accrued Liabilities

12 Months Ended

Dec. 31, 2022

Trade and other current payables [abstract]

Accounts Payable and Accrued Liabilities

25. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

As at December 31,	2022	2021
Accruals	3,412	2,722
Trade	2,331	2,554
Interest	80	128
Partner Advances	—	371
Employee Long-Term Incentives	162	317
Joint Operations Payable	66	28
Risk Management	39	116
Provisions for Onerous and Unfavourable Contracts	25	31
Other	9	86
	6,124	6,353

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Contingent Payments

12 Months Ended

Dec. 31, 2022

Disclosure of contingent liabilities in business combination [abstract]

Contingent Payments

28. CONTINGENT PAYMENTS

A) Sunrise Oil Sands Partnership

In connection with the Sunrise Acquisition (see Note 5), Cenovus agreed to make quarterly variable payments from SOSP to BP Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the term of the contract is $600 million.

The variable payment will continue to be re-measured at fair value at each reporting date until the earlier of the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed, with changes in fair value recognized in net earnings (loss).

The first quarterly period ended on November 30, 2022. A payment of $92 million was made in January 2023.

	Total
As at December 31, 2021	—
Initial Recognition	600
Liabilities Settled or Payable	(92)
Re-measurement (1)	(89)
As at December 31, 2022	419
Less: Current Portion	263
Long-Term Portion	156

(1)     The variable payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).

B) FCCL Partnership

On May 17, 2022, the contingent payment obligation associated with the acquisition of a 50 percent interest in the FCCL Partnership (“FCCL”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) ended. The final payment of $177 million was made in July 2022 (as at December 31, 2021 – $160 million was payable). In connection with the acquisition in 2017 from ConocoPhillips, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years ending May 17, 2022, for quarters in which the average WCS crude oil price exceeded $52.00 per barrel during the quarter. The quarterly payment was $6 million for each dollar that the WCS price exceeded $52.00 per barrel.

	2022	2021
Contingent Payment, Beginning of Year	236	63
Re-measurement (1)	251	575
Liabilities Settled	(487)	(402)
Contingent Payment, End of Year	—	236

(1)     The contingent payment was carried at fair value. Changes in fair value were recorded in net earnings (loss).

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Debt and Capital Structure

12 Months Ended

Dec. 31, 2022

Borrowings [abstract]

Debt and Capital Structure

26. DEBT AND CAPITAL STRUCTURE

For the year ended December 31, 2022, the weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings was 4.7 percent (December 31, 2021 – 4.6 percent).

A) Short-Term Borrowings

As at December 31,	Notes	2022	2021
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	115	79
Total Debt Principal		115	79

i) Uncommitted Demand Facilities

As at December 31, 2022, and December 31, 2021, the Company had uncommitted demand facilities of $1.9 billion in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at December 31, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no direct borrowings.

As at December 31, 2021, SOSP had an uncommitted demand credit facility of $10 million (the Company’s proportionate share – $5 million). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility.

ii) WRB Uncommitted Demand Facilities

As at December 31, 2022, WRB had uncommitted demand facilities of US$450 million (the Company’s proportionate share –US$225 million), which may be used to cover short-term working capital requirements (December 31, 2021 – US$300 million (the Company’s proportionate share – US$150 million)). As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US$63 million (C$79 million

B) Long-Term Debt

As at December 31,	Notes	2022	2021
Committed Credit Facility (1)	i	—	—
U.S. Dollar Denominated Unsecured Notes	ii	6,537	9,363
Canadian Dollar Unsecured Notes	ii	2,000	2,750
Total Debt Principal		8,537	12,113
Debt Premiums (Discounts), Net, and Transaction Costs		154	272
Long-Term Debt		8,691	12,385

(1)The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

i) Committed Credit Facility

At the closing of the Arrangement on January 1, 2021, the Company assumed Husky's committed credit facilities of $4.0 billion, with $350 million outstanding. In August 2021, $8.5 billion of committed facilities, which includes those assumed in the Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility.

On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to $5.5 billion and to extend the maturity dates by more than one year. The committed credit facility consists of a $1.8 billion tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at December 31, 2022, no amounts were drawn on the credit facility (December 31, 2021 – $nil).

ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes

For the year ended December 31, 2022, and December 31, 2021, Cenovus purchased outstanding principal amounts of the following unsecured notes:

	2022	2021
	US$ Principal	US$ Principal
U.S. Dollar Unsecured Notes
3.95% due April 15, 2022	—	500
3.00% due August 15, 2022	—	500
3.80% due September 15, 2023	115	335
4.00% due April 15, 2024	269	481
5.38% due July 15, 2025	533	334
4.25% due April 15, 2027	589	—
4.40% due April 15, 2029	510	—
6.75% due November 15, 2039	455	—
4.45% due September 15, 2042	58	—
5.20% due September 15, 2043	29	—
	2,558	2,150

	C$ Principal	C$ Principal
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025	750	—

The principal amounts of the Company’s outstanding unsecured notes are:

	2022		2021
As at December 31,	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Denominated Unsecured Notes
3.80% due September 15, 2023	—	—	115	146
4.00% due April 15, 2024	—	—	269	341
5.38% due July 15, 2025	133	181	666	844
4.25% due April 15, 2027	373	505	962	1,220
4.40% due April 15, 2029	240	324	750	951
2.65% due January 15, 2032	500	677	500	634
5.25% due June 15, 2037	583	790	583	739
6.80% due September 15, 2037	387	524	387	490
6.75% due November 15, 2039	935	1,267	1,390	1,763
4.45% due September 15, 2042	97	131	155	197
5.20% due September 15, 2043	29	39	58	73
5.40% due June 15, 2047	800	1,083	800	1,014
3.75% due February 15, 2052	750	1,016	750	951
	4,827	6,537	7,385	9,363
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025		—		750
3.60% due March 10, 2027		750		750
3.50% due February 7, 2028		1,250		1,250
		2,000		2,750
Total Unsecured Notes		8,537		12,113

At the closing of the Arrangement on January 1, 2021, the Company assumed Canadian dollar unsecured notes with a fair value of $2.9 billion (notional value – $2.8 billion) and U.S. dollar denominated notes with a fair value of $3.4 billion (notional value – US$2.4 billion or C$3.0 billion). The Company closed a public offering in the U.S. in September 2021, for US$1.25 billion of senior unsecured notes, consisting of US$500 million due on January 15, 2032, and US$750 million due on February 15, 2052.

As at December 31, 2022, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is well below this limit.

C) Mandatory Debt Payments

	U.S. Dollar Unsecured Notes		Canadian Dollar Unsecured Notes	Total
As at December 31, 2022	US$ Principal	C$ Principal Equivalent	C$ Principal	C$ Principal and Equivalent
2023	—	—	—	—
2024	—	—	—	—
2025	133	181	—	181
2026	—	—	—	—
2027	373	505	750	1,255
Thereafter	4,321	5,851	1,250	7,101
	4,827	6,537	2,000	8,537

D) Capital Structure

Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. Net Debt is used in managing the Company’s capital structure. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase the Company’s common shares or preferred shares for cancellation, issue new debt, or issue new shares.

Cenovus monitors its capital structure and financing requirements using, among other things, specified financial measures consisting of Total Debt, Net Debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Net Debt to Adjusted Funds Flow was a new metric as at March 31, 2022.

Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times and Net Debt at or below $4 billion over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices.

On October 7, 2021, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus will expire in November 2023. Offerings under the base shelf prospectus are subject to market conditions. As at December 31, 2022, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings.

Net Debt to Adjusted EBITDA

As at December 31,	2022	2021	2020
Short-Term Borrowings	115	79	121
Current Portion of Long-Term Debt	—	—	—
Long-Term Portion of Long-Term Debt	8,691	12,385	7,441
Total Debt	8,806	12,464	7,562
Less: Cash and Cash Equivalents	(4,524)	(2,873)	(378)
Net Debt	4,282	9,591	7,184
Net Earnings (Loss)	6,450	587	(2,379)
Add (Deduct):
Finance Costs	820	1,082	536
Interest Income	(81)	(23)	(9)
Income Tax Expense (Recovery)	2,281	728	(851)
Depreciation, Depletion and Amortization	4,679	5,886	3,464
E&E Asset Write-downs	64	18	91
(Income) Loss From Equity-Accounted Affiliates	(15)	(57)	—
Unrealized (Gain) Loss on Risk Management	(126)	2	56
Foreign Exchange (Gain) Loss, Net	343	(174)	(181)
Revaluation (Gains)	(549)	—	—
Re-measurement of Contingent Payments	162	575	(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)	(81)
Other (Income) Loss, Net	(532)	(309)	40
Adjusted EBITDA (1)	13,227	8,086	606
Net Debt to Adjusted EBITDA	0.3x	1.2x	11.9x

(1)Calculated on a trailing twelve-month basis.

Net Debt to Adjusted Funds Flow

As at December 31,	2022	2021	2020
Net Debt	4,282	9,591	7,184
Cash From (Used in) Operating Activities	11,403	5,919	273
(Add) Deduct:
Settlement of Decommissioning Liabilities	(150)	(102)	(42)
Net Change in Non-Cash Working Capital	575	(1,227)	198
Adjusted Funds Flow (1)	10,978	7,248	117
Net Debt to Adjusted Funds Flow	0.4x	1.3x	61.4x

(1)    Calculated on a trailing twelve-month basis.

Net Debt to Capitalization

As at December 31,	2022		2021		2020
Net Debt	4,282		9,591		7,184
Shareholders’ Equity	27,576		23,596		16,707
Capitalization	31,858		33,187		23,891
Net Debt to Capitalization	13	%	29	%	30	%

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Lease Liabilities

12 Months Ended

Dec. 31, 2022

Lease liabilities [abstract]

Lease Liabilities

27. LEASE LIABILITIES

	2022	2021
Lease Liabilities, Beginning of Year	2,957	1,757
Acquisitions (Note 5)	—	1,441
Additions	25	110
Interest Expense (Note 7)	163	171
Lease Payments	(465)	(471)
Modifications	83	22
Re-measurements	7	(4)
Terminations	(5)	(1)
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	—	(10)
Exchange Rate Movements and Other	71	(58)
Lease Liabilities, End of Year	2,836	2,957
Less: Current Portion	308	272
Long-Term Portion	2,528	2,685

The Company has lease liabilities for contracts related to office space, transportation and storage assets, which includes barges, vessels, pipelines, caverns, railcars and storage tanks, commercial fuel assets and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions.

The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are leases with terms of twelve months or less.

The Company includes extension options in the calculation of lease liabilities when the Company has the right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company does not have any significant termination options and the residual amounts are not material.

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Decommissioning Liabilities

12 Months Ended

Dec. 31, 2022

Provision for decommissioning, restoration and rehabilitation costs [abstract]

Decommissioning Liabilities

29. DECOMMISSIONING LIABILITIES

The decommissioning provision represents the present value of the expected future costs associated with the retirement of producing well sites, upstream processing facilities, surface and subsea plant and equipment, manufacturing facilities, the commercial fuels facilities and the crude-by-rail terminal.

The aggregate carrying amount of the obligation is:

	2022	2021
Decommissioning Liabilities, Beginning of Year	3,906	1,248
Liabilities Incurred	22	30
Liabilities Acquired (Note 5) (1)	48	2,856
Liabilities Settled	(215)	(144)
Liabilities Divested (Note 5) (1)	(89)	(140)
Change in Estimated Future Cash Flows	693	(472)
Change in Discount Rates	(980)	450
Unwinding of Discount on Decommissioning Liabilities (Note 7)	176	199
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	—	(128)
Exchange Rate Movements and Other	(2)	7
Decommissioning Liabilities, End of Year	3,559	3,906

(1)     In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million.

As at December 31, 2022, the undiscounted amount of estimated future cash flows required to settle the obligation is $14 billion (December 31, 2021 – $14 billion). Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $250 million to $300 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning liabilities over the estimated life of the reserves and an increase in cost estimates. These obligations have been discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2021 – 4.4 percent) and assumes an inflation rate of two percent (December 31, 2021 – two percent).

The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2022, the Company had $209 million in restricted cash (December 31, 2021 – $186 million).

Sensitivities

Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:

	Sensitivity	2022		2021
As at December 31,	Range	Increase	Decrease	Increase	Decrease
Credit-Adjusted Risk-Free Rate	± one percent	(319)	419	(623)	875
Inflation Rate	± one percent	419	(320)	873	(625)

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Other Liabilities

12 Months Ended

Dec. 31, 2022

Miscellaneous non-current liabilities [abstract]

Other Liabilities

30. OTHER LIABILITIES

As at December 31,	2022	2021
Pension and Other Post-Employment Benefit Plan	201	288
Provision for West White Rose Expansion Project (1)	204	259
Provisions for Onerous and Unfavourable Contracts	95	99
Employee Long-Term Incentives	245	74
Drilling Provisions	31	56
Deferred Revenue	45	41
Other (2)	221	112
	1,042	929

(1)     On May 31, 2022, the Company divested of 12.5 percent of its working interest in the White Rose field and satellite extensions reducing the provision by $47 million (see Note 10). Cenovus expects to draw down the provision by $58 million in the next twelve months.

(2)     As at December 31, 2022, other includes a net RVO of $101 million. Gross amounts of the RVO and RINs asset were $1.1 billion and $1.0 billion, respectively.

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Pensions and Other Post-Employment Benefits

12 Months Ended

Dec. 31, 2022

Pensions And Other Post Employment Benefits [Abstract]

Pensions and Other Post-Employment Benefits

31. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS

The Company provides the majority of employees with a defined contribution pension plan. The Company also provides OPEB plans to retirees and sponsors defined benefit pension plans in Canada and the U.S. (together, the “DB Pension Plan”).

The DB Pension Plan provides pension benefits at retirement based on years of service and final average earnings. In Canada, future enrollment is limited to eligible employees who may elect to move from the defined contribution component to the defined benefit component for their future service. In the U.S., the defined benefit pension is closed to new members. The Company’s OPEB plans provides certain retired employees with health care and dental benefits.

The Company is required to file an actuarial valuation of its registered defined benefit pension with regulators on a periodic basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2021, and the next required actuarial valuation will be as at December 31, 2024. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2022 and the next required actuarial valuation will be as at January 1, 2023.

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:

	Pension Benefits		OPEB
	2022	2021	2022	2021
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year	220	188	225	20
Plan Acquisition Upon the Arrangement (1)	—	41	—	224
Current Service Costs	16	16	8	9
Past Service Costs - Curtailment and Plan Amendments	—	(1)	—	(3)
Interest Costs (2)	7	6	7	6
Benefits Paid	(12)	(17)	(8)	(8)
Plan Participant Contributions	2	2	—	—
Re-measurements:
(Gains) Losses From Experience Adjustments	1	4	(2)	10
(Gains) Losses From Changes in Demographic Assumptions	—	(1)	—	(3)
(Gains) Losses From Changes in Financial Assumptions	(64)	(18)	(57)	(30)
Exchange Rate Movements and Other	2	—	1	—
Defined Benefit Obligation, End of Year	172	220	174	225
Plan Assets
Fair Value of Plan Assets, Beginning of Year	159	117	—	—
Plan Acquisition Upon the Arrangement (1)	—	32	—	—
Employer Contributions	16	9	8	3
Plan Participant Contributions	2	2	—	—
Benefits Paid	(10)	(13)	(8)	(3)
Interest Income (2)	4	3	—	—
Re-measurements:
Return on Plan Assets (Excluding Interest Income)	(26)	9	—	—
Exchange Rate Movements and Other	2	—	—	—
Fair Value of Plan Assets, End of Year	147	159	—	—
Pension and OPEB (Liability) (3)	(25)	(61)	(174)	(225)

(1)The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5.

(2)Based on the discount rate of the defined benefit obligation at the beginning of the year.

(3)Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities on the Consolidated Balance Sheets.

The weighted average duration of the defined benefit pension and OPEB obligations are 14 years and 14 years, respectively.

B) Pension and OPEB Costs

	Pension Benefits			OPEB
As at December 31,	2022	2021	2020	2022	2021	2020
Defined Benefit Plan Cost
Current Service Costs	16	16	13	8	9	1
Past Service Costs - Curtailments and Plan    Amendments	—	(1)	—	—	(3)	—
Net Interest Costs	3	3	3	7	6	—
Re-measurements:
Return on Plan Assets (Excluding    Interest Income)	26	(9)	(5)	—	—	—
(Gains) Losses From Experience    Adjustments	1	4	1	(2)	10	(2)
(Gains) Losses From Changes in    Demographic Assumptions	—	(1)	—	—	(3)	—
(Gains) Losses From Changes in Financial    Assumptions	(64)	(18)	15	(57)	(30)	1
Defined Benefit Plan Cost (Recovery)	(18)	(6)	27	(44)	(11)	—
Defined Contribution Plan Cost (1)	72	68	22	—	—	—
Total Plan Cost	54	62	49	(44)	(11)	—

(1)    Includes defined contribution and U.S. 401(k) plans.

C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the DB Pension Plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.

The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced as necessary. The Canadian defined benefit pension plan and U.S. defined benefit pension plan are managed independently of each other and, accordingly, the target asset allocation is reflective of their different liability profiles.

2022 Target Allocation (percent)	Canadian Plan	U.S. Plan
Equity Funds	25% - 75%	21% - 51%
Fixed Income Funds	20% - 50%	55% - 74%
Real Estate Funds	—% - 15%	—	%
Listed Infrastructure Funds	—% - 10%	—	%
Emerging Market Debt Funds	—% - 10%	—	%
Cash and Cash Equivalents	—% - 10%	—	%

The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods.

The fair value of the DB Pension Plan assets is:

As at December 31,	2022	2021
Equity Funds	68	77
Fixed Income Funds	50	54
Real Estate Funds	9	9
Listed Infrastructure Funds	7	8
Emerging Market Debt Funds	5	8
Cash and Cash Equivalents	7	2
Non-Invested Assets	1	1
Total Fair Value of DB Pension Plan Assets	147	159

Fair value of the cash and cash equivalents, equity, fixed income and listed infrastructure assets are based on the trading price of the underlying funds (Level 1). The fair value of the real estate funds reflects the appraisal valuation for each property investment (Level 2). The fair value of the non-invested assets is the discounted value of the expected future payments (Level 3).

The DB Pension Plan does not hold any direct investment in Cenovus common shares or preferred shares.

D) Funding

The DB Pension Plan is funded in accordance with applicable pension legislation. Contributions are made to trust funds administered by independent trustees. The Company’s contributions to the DB Pension Plan are based on the most recent actuarial valuations, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors.

Employees participating in the Canadian defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. In the year ended December 31, 2023, the Company expects to contribute $10 million for the DB Pension Plan.

The OPEB plans are funded on an as required basis. In the year ended December 31, 2023, the Company expects to contribute $10 million for the OPEB plans.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:

	Pension Benefits						OPEB
For the years ended December 31,	2022		2021		2020		2022		2021		2020
Discount Rate	5.12	%	2.95	%	2.50	%	5.13	%	2.98	%	2.50	%
Future Salary Growth Rate	4.05	%	4.03	%	3.97	%	N/A		4.94	%	4.94	%
Average Longevity (years)	88.4		88.3		88.3		88.4		88.3		88.2
Health Care Cost Trend Rate	N/A		N/A		N/A		5.24	%	5.64	%	6.00	%

Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations.

Sensitivities

Of the most significant actuarial assumptions, a change in discount rates and health care costs have the largest potential impact on the obligations for the DB Pension Plan and OPEB plans, with sensitivity to change as follows:

	2022		2021
As at December 31,	Increase	Decrease	Increase	Decrease
One Percent Change:
Discount Rate	(43)	51	(59)	76
Future Salary Growth Rate	3	(3)	4	(4)
Health Care Cost Trend Rate	19	(17)	26	(20)
One Year Change in Assumed Life Expectancy	10	(10)	4	(4)

The sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, the changes in some assumptions may be correlated. The same methodologies have been used to calculate the sensitivity of the DB Pension Plan obligation to significant actuarial assumptions as have been applied when calculating the liability for the DB Pension Plan recorded on the Consolidated Balance Sheets.

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Share Capital and Warrants

12 Months Ended

Dec. 31, 2022

Disclosure of classes of share capital [abstract]

Share Capital and Warrants

32. SHARE CAPITAL AND WARRANTS

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject to the Company’s articles.

B) Issued and Outstanding – Common Shares

	2022		2021
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	2,001,211	17,016	1,228,870	11,040
Issued Under the Arrangement, Net of Issuance Costs (Note 5)	—	—	788,518	6,111
Issued Upon Exercise of Warrants	9,399	93	314	3
Issued Under Stock Option Plans	11,069	170	535	7
Purchase of Common Shares under NCIBs	(112,489)	(959)	(17,026)	(145)
Outstanding, End of Year	1,909,190	16,320	2,001,211	17,016

As at December 31, 2022, there were 43 million (December 31, 2021 – 30 million) common shares available for future issuance under the stock option plan.

C) Normal Course Issuer Bid

On November 4, 2021, the TSX accepted the Company’s implementation of an NCIB to purchase up to 146.5 million common shares between November 9, 2021, and November 8, 2022. On November 7, 2022, the Company received approval from the TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period from November 9, 2022, to November 8, 2023.

For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares (December 31, 2021 – 17 million) through the NCIBs. The shares were purchased at a volume weighted average price of $22.49 per common share (December 31, 2021 – $15.56) for a total of $2.5 billion (December 31, 2021 – $265 million). Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value.

From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB.

D) Issued and Outstanding – Preferred Shares

For the year ended December 31, 2022, there were no preferred shares issued. As at December 31, 2022, there were 36 million preferred shares outstanding (December 31, 2021 – 36 million), with a carrying value of $519 million (December 31, 2021 – $519 million).

As at December 31, 2022	Dividend Reset Date	Dividend Rate		Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	%	10,740
Series 2 First Preferred Shares (1)	Quarterly	5.86	%	1,260
Series 3 First Preferred Shares	December 31, 2024	4.69	%	10,000
Series 5 First Preferred Shares	March 31, 2025	4.59	%	8,000
Series 7 First Preferred Shares	June 30, 2025	3.94	%	6,000

(1)The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June 30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 – 1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023.

Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such option to convert their shares into the other series.

Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1), 3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6) and 3.52 percent (series 8).

Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Second Preferred Shares

There were no second preferred shares outstanding as at December 31, 2022 (December 31, 2021 – nil).

E) Issued and Outstanding – Warrants

	2022		2021
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	65,119	215	—	—
Issued Under the Arrangement (Note 5)	—	—	65,433	216
Exercised	(9,399)	(31)	(314)	(1)
Outstanding, End of Year	55,720	184	65,119	215

The exercise price of the Cenovus warrants is $6.54 per share.

F) Paid in Surplus

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as Ovintiv Inc. ("Ovintiv")) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 34 and the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIBs.

	Retained Earnings Prior to Ovintiv Split	Stock-Based Compensation	Common Shares	Total
As at December 31, 2020	4,086	305	—	4,391
Stock-Based Compensation Expense	—	14	—	14
Purchase of Common Shares Under NCIBs	—	—	(120)	(120)
Common Shares Issued on Exercise of Stock Options	—	(1)	—	(1)
As at December 31, 2021	4,086	318	(120)	4,284
Stock-Based Compensation Expense	—	10	—	10
Purchase of Common Shares Under NCIBs	—	—	(1,571)	(1,571)
Common Shares Issued on Exercise of Stock Options	—	(32)	—	(32)
As at December 31, 2022	4,086	296	(1,691)	2,691

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Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2022

Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Pension and Other Post-Retirement Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
As at December 31, 2020	(10)	27	758	775
Other Comprehensive Income (Loss), Before Tax	47	—	(129)	(82)
Income Tax (Expense) Recovery	(9)	—	—	(9)
As at December 31, 2021	28	27	629	684
Other Comprehensive Income (Loss), Before Tax	96	2	713	811
Income Tax (Expense) Recovery	(25)	—	—	(25)
As at December 31, 2022	99	29	1,342	1,470

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Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2022

Disclosure of terms and conditions of share-based payment arrangement [abstract]

Stock-Based Compensation Plans

34. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Options

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market value for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.

Options issued by the Company have associated NSRs. The NSRs, in lieu of exercising the option, gives the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the excess of the market price received from the sale of the common shares over the exercise price of the option.

The NSRs vest and expire under the same terms and conditions as the underlying options.

Stock Options With Associated Net Settlement Rights

The weighted average unit fair value of NSRs granted during the year ended December 31, 2022, was $19.94 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	1.84	%
Expected Dividend Yield	0.72	%
Expected Volatility (1)	24.72	%
Expected Life (years)	5.75

(1)Expected volatility has been based on historical share volatility of the Company.

The following tables summarize information related to the NSRs:

	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
For the year ended December 31, 2022	(thousands)	($)
Outstanding, Beginning of Year	27,233	13.06
Granted	2,031	19.94
Exercised	(11,599)	12.77
Forfeited	(258)	9.75
Expired	(3,058)	22.25
Outstanding, End of Year	14,349	12.38

	Outstanding			Exercisable
As at December 31, 2022	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
Range of Exercise Price ($)	(thousands)	(Years)	($)	(thousands)	($)
5.00 to 9.99	5,234	4.88	8.76	1,474	8.94
10.00 to 14.99	6,229	3.80	12.01	4,280	12.13
15.00 to 19.99	2,834	4.26	19.71	919	19.36
20.00 to 24.99	52	6.69	22.37	—	—
	14,349	4.30	12.38	6,673	12.42

Cenovus Replacement Stock Options

For the year ended December 31, 2022, 6,042 thousand Cenovus replacement stock options, with a weighted average exercise price of $16.57, were exercised and net settled for cash and 103 thousand Cenovus replacement stock options were exercised with a weighted average exercise price of $14.98 and settled for 81 thousand common shares.

The Company recorded a liability of $42 million as at December 31, 2022, (December 31, 2021 – $30 million) in the Consolidated Balance Sheets for Cenovus Replacement Stock Options based on the fair value at year end using the Black-Scholes-Merton valuation model.

The following tables summarize the information related to the Cenovus replacement stock options:

	Number of Cenovus Replacement Stock Options	Weighted Average Exercise Price
For the year ended December 31, 2022	(thousands)	($)
Outstanding, Beginning of Year	12,256	15.21
Exercised	(6,145)	16.12
Forfeited	(186)	15.85
Expired	(2,458)	20.59
Outstanding, End of Year	3,467	9.99

	Outstanding			Exercisable
As at December 31, 2022	Number of Cenovus Replacement Stock Options	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Cenovus Replacement Stock Options	Weighted Average Exercise Price
Range of Exercise Price ($)	(thousands)	(Years)	($)	(thousands)	($)
3.00 to 4.99	2,065	1.63	3.54	742	3.54
5.00 to 9.99	124	1.36	6.06	59	6.06
10.00 to 14.99	14	0.47	12.88	14	12.88
15.00 to 19.99	594	1.04	18.35	594	18.35
20.00 to 24.99	524	0.20	21.77	524	21.77
25.00 to 29.99	146	0.58	27.88	146	27.88
	3,467	1.25	9.99	2,079	14.21

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are time-vested whole-share units that entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible to vest is determined by a multiplier that ranges from zero percent to 200 percent and is based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

The Company has recorded a liability of $216 million as at December 31, 2022, (December 31, 2021 – $61 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. PSUs are paid out upon vesting and, as a result, the intrinsic value was $nil as at December 31, 2022.

The following table summarizes the information related to the PSUs held by Cenovus employees:

	Number of Performance Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	7,163
Granted	3,226
Vested and Paid Out	(1,413)
Cancelled	(465)
Units in Lieu of Dividends	167
Outstanding, End of Year	8,678

C) Restricted Share Units

Cenovus granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs generally vest over three years.

The Company recorded a liability of $109 million as at December 31, 2022 (December 31, 2021 – $53 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2022.

The following table summarizes the information related to the RSUs held by Cenovus employees:

	Number of Restricted Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	6,025
Granted	3,161
Vested and Paid Out	(2,230)
Cancelled	(430)
Units in Lieu of Dividends	129
Outstanding, End of Year	6,655

D) Deferred Share Units

Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25, 50, 75 or 100 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

The Company recorded a liability of $40 million as at December 31, 2022 (December 31, 2021 – $20 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

	Number of Deferred Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	1,256
Granted to Directors	161
Granted	316
Units in Lieu of Dividends	30
Redeemed	(257)
Outstanding, End of Year	1,506

E) Total Stock-Based Compensation

For the years ended December 31,	2022	2021	2020
Stock Options With Associated Net Settlement Rights	15	14	11
Cenovus Replacement Stock Options	53	26	—
Performance Share Units	183	56	19
Restricted Share Units	100	48	23
Deferred Share Units	22	15	(4)
Stock-Based Compensation Expense (Recovery)	373	159	49
Stock-Based Compensation Costs Capitalized	—	8	16
Total Stock-Based Compensation	373	167	65

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Employee Salaries and Benefit Expenses

12 Months Ended

Dec. 31, 2022

Disclosure Of Salaries And Employee Benefits [Abstract]

Employee Salaries and Benefit Expenses

35. EMPLOYEE SALARIES AND BENEFIT EXPENSES

For the years ended December 31,	2022	2021	2020
Salaries, Bonuses and Other Short-Term Employee Benefits	1,246	1,327	605
Post-Employment Benefits	92	89	33
Stock-Based Compensation (Note 34)	373	159	49
Other Incentive Benefits (Recovery)	(9)	201	(4)
Termination Benefits	27	180	9
	1,729	1,956	692

Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock options, PSUs, RSUs and DSUs.

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Related Party Transactions

12 Months Ended

Dec. 31, 2022

Disclosure of transactions between related parties [abstract]

RELATED PARTY TRANSACTIONS

36. RELATED PARTY TRANSACTIONS

A) Key Management Compensation

Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is:

For the years ended December 31,	2022	2021	2020
Salaries, Director Fees and Other Short-Term Benefits	40	69	21
Post-Employment Benefits	4	4	3
Stock-Based Compensation	140	72	15
Other Incentive Benefits	—	4	1
Termination Benefits	3	3	6
	187	152	46

Post-employment benefits represent the present value of future pension benefits earned during the year.

B) Other Related Party Transactions

Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 22). As the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs.

The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or on a cost recovery basis with certain restrictions. For the year ended December 31, 2022, the Company charged HMLP $188 million, for construction costs and management services (2021 – $243 million).

The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the year ended December 31, 2022, the Company incurred costs of $263 million, for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million).

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Financial Instruments

12 Months Ended

Dec. 31, 2022

Disclosure of detailed information about financial instruments [abstract]

FINANCIAL INSTRUMENTS

37. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, net investment in finance leases, risk management assets and liabilities, investments in the equity of companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and other liabilities. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of restricted cash, net investment in finance leases and long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair value of long-term borrowings has been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2022, the carrying value of Cenovus’s long-term debt was $8.7 billion and the fair value was $7.8 billion (December 31, 2021 carrying value – $12.4 billion, fair value – $13.7 billion).

The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available.

The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:

	2022	2021
Fair Value, Beginning of Year	53	52
Acquisition (Note 5)	—	1
Changes in Fair Value (1)	2	—
Fair Value, End of Year	55	53

(1)     Changes in fair value are recorded in OCI.

Equity investments classified as FVTPL comprise equity investments in public companies. These assets were carried at fair value on the Consolidated Balance Sheets in other assets. Fair value was determined based on quoted prices in active markets (Level 1).

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures, as well as renewable power contracts, power and foreign exchange swaps. The Company may also enter into swaps, forwards, and options to manage commodity and foreign exchange exposures, as well as interest rate swaps.

Crude oil, natural gas, condensate, refined product contracts and power swaps are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange rate contracts, and interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2), respectively. The fair value of cross currency interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2).

The fair value of renewable power contracts are calculated using internal valuation models that incorporate broker pricing for relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair value of renewable power contracts are calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have experience in fair value techniques.

Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets (for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings within (gain) loss on risk management.

Summary of Risk Management Positions

	2022			2021
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	2	40	(38)	46	116	(70)
Power Swap Contracts	1	7	(6)	—	—	—
Renewable Power Contracts	90	—	90	—	—	—
Foreign Exchange Rate Contracts	—	—	—	2	—	2
	93	47	46	48	116	(68)

Level 2 prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Level 3 prices are sourced from partially observable data used in internal valuations.

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

As at December 31,	2022	2021
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(44)	(68)
Level 3 – Prices Sourced From Partially Observable Data	90	—
	46	(68)

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities from January 1 to December 31:

	2022	2021
Fair Value of Contracts, Beginning of Year	(68)	(53)
Acquisition (Note 5)	—	(14)
Change in Fair Value of Contracts in Place at Beginning of Year	(5)	—
Change in Fair Value of Contracts Entered Into During the Year	(1,641)	(995)
Fair Value of Contracts Realized During the Year	1,762	993
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	(2)	1
Fair Value of Contracts, End of Year	46	(68)

Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same.

	2022			2021
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	153	107	46	263	331	(68)
Amount Offset	(60)	(60)	—	(215)	(215)	—
Net Amount	93	47	46	48	116	(68)

The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.

Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. As at December 31, 2022, $211 million was pledged as cash collateral (December 31, 2021 – $114 million).

C) Fair Value of Contingent Payments

The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing discounted using a credit-adjusted risk-free rate. Fair value of the variable payment has been calculated by Cenovus’s internal valuation team, which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million applying a credit-adjusted risk-free rate of 5.2 percent. The maximum cumulative variable payment is $600 million.

As at December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is $72.79 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 44.2 percent and 7.6 percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

As at December 31, 2022	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $10.00 per barrel	(68)	157
WTI Option Volatility	± ten percent	(1)	4
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility	± five percent	—	—

The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $5.00 per barrel	(45)	45

The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in the Canadian-U.S. dollar foreign exchange rate options would result in nominal unrealized gains (losses) to earnings before income tax.

D) Earnings Impact of (Gains) Losses From Risk Management Positions

For the years ended December 31,	2022	2021	2020
Realized (Gain) Loss	1,762	993	252
Unrealized (Gain) Loss (1)	(126)	2	56
(Gain) Loss on Risk Management	1,636	995	308

(1)     All WTI positions related to crude oil sales price risk management were closed by June 30, 2022. In the three months ended June 30, 2022, Cenovus recorded a realized net loss related to these positions of $467 million.

Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

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Risk Management

12 Months Ended

Dec. 31, 2022

Risk Management [Abstract]

Risk Management

38. RISK MANAGEMENT

Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates, commodity power prices as well as credit risk and liquidity risk.

To manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus, the Company may periodically enter into financial positions as a part of ongoing operations to market the Company’s production and physical inventory positions of crude oil, natural gas, condensate, refined products, and power consumption. The Company may also enter into arrangements to manage exposure to future carbon compliance costs or to offset select carbon emissions.

The Company entered into risk management positions to help capture incremental margin expected to be received in future periods at the time products will be sold and to mitigate overall exposure to fluctuations in commodity prices related to inventories and physical sales. Mitigation of commodity price volatility may utilize financial positions to protect future cash flows. To manage exposure to interest rate volatility, the Company periodically enters into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs, power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts.

As at December 31, 2022, the fair value of risk management positions was a net asset of $46 million and consisted of crude oil, natural gas, condensate, refined products, power and foreign exchange rate instruments. As at December 31, 2022, there were foreign exchange contracts with a notional value of US$168 million outstanding (December 31, 2021 – US$144 million) and no interest rate contracts or cross currency interest rate swap contracts (December 31, 2021 – $nil) outstanding.

Net Fair Value of Risk Management Positions

As at December 31, 2022	Notional Volumes (1)(2)	Terms (3)	Weighted Average Price (1) (2)	Fair Value Asset (Liability)
Futures Contracts Related to Blending (4)
WTI Fixed – Sell	3.2 MMbbls	January 2023 - June 2024	US$80.35/bbl	1
WTI Fixed – Buy	2.3 MMbbls	February 2023 - June 2024	US$79.93/bbl	—
Power Swap Contacts				(6)
Renewable Power Contracts				90
Other Financial Positions (5)				(39)
Total Fair Value				46

(1)    Million barrels (“MMbbls”). Barrel (“bbl”).

(2)    Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3)    Contract terms represent various individual contracts with different terms, and range from one month to eighteen months.

(4)    Condensate related futures contract positions consist of WTI contracts to help manage condensate price exposure.

(5)    Other financial positions consist of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, natural gas basis contracts and the Company’s U.S. manufacturing and marketing activities.

A) Commodity Price, Foreign Exchange and Interest Rate Risk

i) Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.

The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.

The Company has used crude oil, natural gas and refined product swaps, futures, basis price risk management contracts and, if entered into, forwards, options, as well as condensate futures and swaps. These derivative instruments are used to partially mitigate exposure to the commodity price risk on its crude oil sales and to protect both near-term and future cash flows. Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials and to manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus. In addition, the Company has entered into risk management positions to help mitigate the risk to incremental margin expected to be received in future periods at the time products will be sold. The Company has used commodity futures and swaps, as well as differential price risk management contracts to partially mitigate its exposure to the commodity price risk on its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate its natural gas commodity price risk.

ii) Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.

Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada (see Note 9). As at December 31, 2022, Cenovus had US$4.8 billion in U.S. dollar debt (December 31, 2021 – US$7.4 billion).

iii) Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. To manage exposure to interest rate volatility, the Company periodically enters into interest rate swap contracts. As at December 31, 2022, Cenovus had no interest rate swap contracts outstanding (December 31, 2021 – $nil). To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2022, Cenovus had no cross currency interest rate swap contracts outstanding (December 31, 2021 – $nil).

iv) Commodity Price, Foreign Exchange and Interest Rate Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at December 31, 2022	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	1	(1)
WCS and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	13	(13)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(1)	1
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
Natural Gas Basis Price	± US$0.50/MCF Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/Megawatt Hour Applied to Power Hedges	113	(113)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	14	(17)

(1)    Excludes WCS (Hardisty) differential.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00/bbl Applied to WTI, Condensate and Related Hedges	(225)	225
WCS and Condensate Differential Price	± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production	4	(4)
Refined Products Commodity Price	± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	11	(12)

In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

As at December 31,	2022	2021
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate	246	372
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate	(246)	(372)

Management believes the fluctuations identified in the table above are a reasonable measure of volatility.

As at December 31, 2022, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $1 million (December 31, 2021 – $1 million). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates.

Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee and the Board of Directors, which is designed to ensure that its credit exposures are within an acceptable risk level. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.

Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within its credit policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, net investment in finance leases, risk management assets and long-term receivables is the total carrying value.

As at December 31, 2022, approximately 85 percent (December 31, 2021 – 94 percent) of the Company’s accruals, receivables related to Cenovus’s joint arrangements, trade receivables and net investment in finance leases were with investment grade counterparties, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss on these accounts was 0.4 percent as at December 31, 2022 (December 31, 2021 – 0.1 percent).

) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt, and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 26, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at the bottom of the commodity price cycle to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn capacity on its committed credit facility and uncommitted demand facilities as well as availability under its base shelf prospectus. As at December 31, 2022, the Company’s sources of capital included:

•$4.5 billion in cash and cash equivalents.

•$5.5 billion available on its committed credit facility.

•$1.4 billion available on its uncommitted demand facilities, of which $1.0 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit.

•US$140 million (C$190 million) on the Company’s proportionate share of the uncommitted demand facilities from WRB.

•US$4.7 billion unused capacity under its base shelf prospectus, availability of which is dependent on market conditions.

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2022	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,124	—	—	—	6,124
Short-Term Borrowings (1)	115	—	—	—	115
Long-Term Debt (1)	401	983	2,014	11,196	14,594
Contingent Payments	271	167	—	—	438
Lease Liabilities (1)	426	746	596	2,889	4,657
As at December 31, 2021	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,353	—	—	—	6,353
Short-Term Borrowings (1)	79	—	—	—	79
Long-Term Debt (1)	561	1,608	2,603	14,892	19,664
Contingent Payments	238	—	—	—	238
Lease Liabilities (1)	453	794	634	3,192	5,073

(1)     Principal and interest, including current portion if applicable.

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Supplementary Cash Flow Information

12 Months Ended

Dec. 31, 2022

Disclosure Of Supplementary Cash Flow Information [Abstract]

Supplementary Cash Flow Information

39. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital

As at December 31,	2022	2021
Total Current Assets	12,430	11,988
Total Current Liabilities	8,021	7,305
Working Capital	4,409	4,683

As at December 31, 2022, adjusted working capital was $4.7 billion (December 31, 2021 – $3.8 billion), excluding assets held for sale of $nil (December 31, 2021 – $1.3 billion), the current portion of the contingent payments of $263 million (December 31, 2021 – $236 million) and liabilities related to assets held for sale of $nil (December 31, 2021 – $186 million).

Changes in non-cash working capital is as follows:

For the years ended December 31,	2022	2021	2020
Accounts Receivable and Accrued Revenues	838	(953)	77
Income Tax Receivable	(58)	(1)	(12)
Inventories	(143)	(1,646)	450
Accounts Payable and Accrued Liabilities	(524)	1,645	(338)
Income Tax Payable	1,000	87	(17)
Total Change in Non-Cash Working Capital	1,113	(868)	160
Net Change in Non-Cash Working Capital – Operating Activities	575	(1,227)	198
Net Change in Non-Cash Working Capital – Investing Activities	538	359	(38)
Total Change in Non-Cash Working Capital	1,113	(868)	160

For the years ended December 31,	2022	2021	2020
Interest Paid	647	811	381
Interest Received	78	24	5
Income Taxes Paid	723	209	18

B) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2019	—	—	6,699	1,916
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	117	—	—
(Repayment) of Revolving Long-Term Debt	—	—	(220)	—
Issuance of Long-Term Debt	—	—	1,326	—
(Repayment) of Long-Term Debt	—	—	(112)	—
Principal Repayment of Leases	—	—	—	(197)
Base Dividends Paid on Common Shares	(77)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	(25)	—
Finance Costs	—	—	5	—
Lease Additions	—	—	—	49
Lease Modifications	—	—	—	(2)
Lease Re-measurements	—	—	—	(2)
Lease Terminations	—	—	—	(1)
Base Dividends Declared on Common Shares	77	—	—	—
Exchange Rate Movements and Other	—	4	(232)	(6)
As at December 31, 2020	—	121	7,441	1,757

	Dividends Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2020	—	121	7,441	1,757
Acquisition (Note 5)	—	40	6,602	1,441
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	(77)	—	—
(Repayment) of Revolving Long-Term Debt	—	—	(350)	—
Issuance of Long-Term Debt	—	—	1,557	—
(Repayment) of Long-Term Debt	—	—	(2,870)	—
Principal Repayment of Leases	—	—	—	(300)
Base Dividends Paid on Common Shares	(176)	—	—	—
Dividends Paid on Preferred Shares	(34)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	121	—
Finance Costs	—	—	(59)	—
Lease Additions	—	—	—	110
Lease Modifications	—	—	—	22
Lease Re-measurements	—	—	—	(4)
Lease Termination	—	—	—	(1)
Transfers to Liabilities Related to Assets Held for Sale	—	—	—	(58)
Base Dividends Declared on Common Shares	176	—	—	—
Dividends Declared on Preferred Shares	34	—	—	—
Exchange Rate Movements and Other	—	(5)	(57)	(10)
As at December 31, 2021	—	79	12,385	2,957
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	34	—	—
(Repayment) of Long-Term Debt	—	—	(4,149)	—
Principal Repayment of Leases	—	—	—	(302)
Base Dividends Paid on Common Shares	(682)	—	—	—
Variable Dividends Paid on Common Shares	(219)	—	—	—
Dividends Paid on Preferred Shares	(26)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	(29)	—
Finance Costs	—	—	(28)	—
Lease Additions	—	—	—	25
Lease Modifications	—	—	—	83
Lease Re-measurements	—	—	—	7
Lease Terminations	—	—	—	(5)
Base Dividends Declared on Common Shares	682	—	—	—
Variable Dividends Declared on Common Shares	219	—	—	—
Dividends Declared on Preferred Shares	35	—	—	—
Exchange Rate Movements and Other	—	2	512	71
As at December 31, 2022	9	115	8,691	2,836

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2022

Commitments And Contingencies [Abstract]

Commitments and Contingencies

40. COMMITMENTS AND CONTINGENCIES

A) Commitments

Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities less than one year are excluded from the table below. Future payments for the Company’s commitments are below:

As at December 31, 2022	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	1,747	2,011	1,542	1,416	1,360	13,005	21,081
Product Purchases	1,626	1,509	922	922	922	3,457	9,358
Real Estate (2)	48	50	50	50	54	604	856
Obligation to Fund Equity-Accounted Affiliate (3)	92	105	96	96	91	143	623
Other Long-Term Commitments (4)	381	90	75	74	65	395	1,080
Total Payments	3,894	3,765	2,685	2,558	2,492	17,604	32,998

As at December 31, 2021	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	1,677	1,958	1,853	1,488	1,350	13,244	21,570
Product Purchases (5)	1,684	1,682	1,593	731	731	4,204	10,625
Real Estate (2)	44	43	52	54	57	658	908
Obligation to Fund Equity-Accounted Affiliate (3)	68	85	99	90	90	210	642
Other Long-Term Commitments (4)	436	83	72	63	81	366	1,101
Total Payments	3,909	3,851	3,669	2,426	2,309	18,682	34,846

(1)    Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the commencement of the contract.

(2)    Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(3)    Relates to funding obligations for HCML.

(4)    Includes Cenovus’s proportionate share of the commitments related to WRB, Toledo and the Offshore segment.

(5)    Previously included in transportation and storage.

As at December 31, 2022, the Company had commitments with HMLP that include $2.2 billion related to long-term transportation and storage commitments (December 31, 2021 – $2.6 billion).

There were also outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) issued as security for financial and performance conditions under certain contracts.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2022

Disclosure Of Summary Of Significant Accounting Policies [Abstract]

Principles of Consolidation

A) Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s accounts reflect its share of the assets, liabilities, revenues and expenses from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s activities relate to joint ventures, which are accounted for using the equity method of accounting.

An associate is an entity for which the Company has significant influence over but does not control or jointly control the affiliate. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter to recognize the Company’s share of the affiliate’s profit or loss and other comprehensive income (“OCI”).

Foreign Currency Translation

B) Foreign Currency Translation

Functional and Presentation Currency

The Company’s functional and presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in OCI as cumulative translation adjustments.

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests.

Transactions and Balances

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the reporting date. Any gains or losses are recorded in the Consolidated Statements of Earnings (Loss).

Revenue Recognition

C) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided.

Cenovus recognizes revenue from the following major products and services:

•Sale of crude oil, NGLs and natural gas.

•Sale of petroleum and refined products.

•Crude oil and natural gas processing services.

•Pipeline transportation, the blending of crude oil and the storage of crude oil, diluent and natural gas.

•Fee-for-service hydrocarbon transloading services.

•Construction services.

The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products, which is generally at a point in time. Performance obligations for crude oil and natural gas processing revenue, transportation services and transloading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Revenue associated with natural gas processing, transportation services and transloading services are generally based on fixed price contracts.

Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and revenue from cost-plus contracts are recognized as services are performed.

The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date, the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered or the deferral provision can no longer be extended.

Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with the exception of certain construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.

Purchased Product

Purchased ProductThe cost of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market are recorded as purchased product.

Transportation and Blending

E) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of diluent used in blending, are recognized when the product is sold.

Exploration Expense

F) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.

Certain costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

Employee Benefit Plans

G) Employee Benefit Plans

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component.

Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans, benefits are not funded before retirement.

Pension expense for the defined contribution pension is recorded as the benefits are earned.

The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans.

Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows:

•Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs.

•Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

•Re-measurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Re-measurements are not reclassified to net earnings in subsequent periods.

Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded.

Government Grants

H) Government GrantsGovernment grants are recognized when there is reasonable assurance that the grant will be received and all conditions associated with the grant are met. If a grant is received, but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. Grants related to assets are recorded as a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the services have been performed.

Income Taxes

I) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

Related Party Transactions

J) Related Party Transactions

The Company enters into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value. Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.

Net Earnings per Share Amounts

K) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

Cash and Cash Equivalents

L) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a maturity of three months or less.

Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within twelve months, it is classified as a non-current asset.

Inventories

M) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

Exploration and Evaluation Assets

N) Exploration and Evaluation Assets

Certain costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. E&E assets are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired or the future economic value has decreased. E&E assets are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.

Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as depreciation, depletion and amortization (“DD&A”), is recognized on this production using a unit-of-production method based on estimated proved reserves determined using forward prices and costs and considering any estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an energy equivalent basis.

Non-producing assets classified as E&E are not depleted.

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

Any gains or losses from the divestiture of E&E assets are recognized in net earnings.

Property, Plant and Equipment

O) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated DD&A, and net of any impairment losses. Expenditures related to renewals or enhancements that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

Any gains or losses from the divestiture of PP&E are recognized in net earnings.

Crude Oil and Natural Gas Properties

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties and related infrastructure facilities, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations, natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to be incurred in developing those reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of either the asset received, or the asset given up, cannot be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and natural gas properties are depleted using a unit-of-production method.

Manufacturing Assets

The initial costs of refining and upgrading PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining and upgrading assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

•Land improvements and buildings: 15 to 40 years.

•Office improvements and buildings: 3 to 15 years.

•Refining equipment: 10 to 60 years.

The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate.

Processing, Transportation and Storage Assets, Commercial Fuels Business and Other

Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available for use by the Company.

The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

Impairment and Impairment Reversals of Non-Financial Assets

P) Impairment and Impairment Reversals of Non-Financial Assets

PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is estimated based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), costs to develop and the discount rate, and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.

Leases

Q) Leases

The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company has elected not to separate non-lease components.

As Lessee

Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments, costs to be incurred by the lessee in dismantling, removing and restoring the underlying asset, variable lease payments that are based on an index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating the lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with reasonably similar characteristics.

Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings over the lease term.

The lease liability is measured at amortized cost using the effective interest method. It is re-measured when there is a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the Company will exercise a purchase, extension or termination option that is within the control of the Company.

When the lease liability is re-measured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero.

The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date.

The ROU asset is depreciated on a straight-line basis, over the shorter of the estimated useful life of the asset or lease term, or using the unit-of-production method. The ROU asset may be adjusted for certain re-measurements of the lease liability and impairment losses.

Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating, transportation or general and administrative expense.

A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will re-measure the lease liability using the Company’s incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope.

As Lessor

As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments received under operating leases as income on a straight-line basis over the lease term as other income.

When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the sublease is classified as an operating lease.

Intangible Assets

Intangible AssetsIntangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset. Impairment losses are recognized in the Consolidated Statements of Earnings(Loss) as DD&A.

Business Combinations and Goodwill

S) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited to net earnings. Acquisition costs are expensed as incurred.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity in accordance with the terms of the agreement. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

Provisions

Provisions

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings (Loss).

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, surface and subsea plant and equipment, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Onerous Contract Provisions

Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss).

Renewable Fuel Obligations

The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured as the expected market price of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the month purchased. RINs purchased on a secondary market are measured at cost. A net RIN position is presented in other assets and a net RVO position is included in other liabilities.

Share Capital and Warrants

U) Share Capital and Warrants

Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the Company’s option. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative.

Transaction costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s paid in surplus. Common shares are cancelled subsequent to being purchased.

Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are recorded as share capital.

Stock-Based Compensation

V) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expenses, or recorded to PP&E or E&E assets when directly related to exploration or development activities.

Stock Options With Associated Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation over the vesting period, with a corresponding increase recorded as paid in surplus in shareholders’ equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Cenovus Replacement Stock Options

Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the stock option is recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation in the period they occur. Stock-based compensation is recorded to PP&E or E&E assets when it is directly related to exploration or development activities.

Financial Instruments

W) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets, net investment in finance leases, investments in the equity of companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, risk management liabilities and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously.

The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

•Level 1 inputs are quoted prices in active markets for identical assets and liabilities.

•Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly.

•Level 3 inputs are unobservable inputs for the asset or liability.

Classification and Measurement of Financial Assets

The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets:

•Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

•FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

•Fair Value through Profit or Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets.

On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis.

At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.

Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model.

A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership.

Impairment of Financial Assets

The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component.

Classification and Measurement of Financial Liabilities

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable.

Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.

A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is re-measured based on the new cash flows and a gain or loss is recorded in net earnings.

Derivatives

Derivative financial instruments are primarily used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

Derivative financial instruments are measured at FVTPL unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures

X) Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures

Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands segment and Corporate and Eliminations segment was revised.

During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows.

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows.

The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the corresponding revised amounts:

Year Ended December 31, 2021

Oil Sands Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Purchased Product	3,188	(784)	—	2,404
Transportation and Blending	7,841	784	—	8,625
	11,029	—	—	11,029

Canadian Manufacturing	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	4,472	—	1,743	6,215
Purchased Product	3,552	—	1,604	5,156
Operating	388	—	98	486
Depreciation, Depletion and Amortization	167	—	59	226
	365	—	(18)	347

Retail	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	2,158	—	(2,158)	—
Purchased Product	2,019	—	(2,019)	—
Operating	98	—	(98)	—
Depreciation, Depletion and Amortization	59	—	(59)	—
	(18)	—	18	—

Corporate and Eliminations Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	(5,706)	—	415	(5,291)
Purchased Product	(4,888)	629	415	(3,844)
Transportation and Blending	(47)	(629)	—	(676)
	(771)	—	—	(771)

Consolidated	Previously Reported	Revision	Segment Aggregation	Revised
Purchased Product	23,481	(155)	—	23,326
Transportation and Blending	7,883	155	—	8,038
	31,364	—	—	31,364

Recent Accounting Pronouncements

Y) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business.

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Description of Business and Segmented Disclosures (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure Of Reportable Segments [Abstract]

Schedule of Segment and Operational Information

A) Results of Operations – Segment and Operational Information

	Upstream
For the years ended December 31,	Oil Sands			Conventional			Offshore			Total
	2022	2021 (1)	2020	2022	2021	2020	2022	2021	2020	2022	2021 (1)	2020
Revenues
Gross Sales	34,775	22,827	8,804	4,332	3,235	904	2,020	1,782	—	41,127	27,844	9,708
Less: Royalties	4,493	2,196	331	298	150	40	77	108	—	4,868	2,454	371
	30,282	20,631	8,473	4,034	3,085	864	1,943	1,674	—	36,259	25,390	9,337
Expenses
Purchased Product	4,810	2,404	1,262	2,023	1,655	268	—	—	—	6,833	4,059	1,530
Transportation and    Blending	12,036	8,625	4,683	143	74	81	15	15	—	12,194	8,714	4,764
Operating	2,930	2,451	1,156	541	551	320	318	239	—	3,789	3,241	1,476
Realized (Gain) Loss on Risk    Management	1,527	786	268	92	2	—	—	—	—	1,619	788	268
Operating Margin	8,979	6,365	1,104	1,235	803	195	1,610	1,420	—	11,824	8,588	1,299
Unrealized (Gain) Loss on    Risk Management	(68)	18	57	13	1	—	—	—	—	(55)	19	57
Depreciation, Depletion and    Amortization	2,763	2,666	1,687	370	3	880	585	492	—	3,718	3,161	2,567
Exploration Expense	9	16	9	1	(3)	82	91	5	—	101	18	91
(Income) Loss From Equity-    Accounted Affiliates	8	(5)	—	—	—	—	(23)	(47)	—	(15)	(52)	—
Segment Income (Loss)	6,267	3,670	(649)	851	802	(767)	957	970	—	8,075	5,442	(1,416)

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).

	Downstream
	Canadian Manufacturing			U.S. Manufacturing			Total
For the years ended December 31,	2022	2021 (1)	2020	2022	2021	2020	2022	2021 (1)	2020
Revenues
Gross Sales	7,792	6,215	82	30,310	20,043	4,733	38,102	26,258	4,815
Less: Royalties	—	—	—	—	—	—	—	—	—
	7,792	6,215	82	30,310	20,043	4,733	38,102	26,258	4,815
Expenses
Purchased Product	6,389	5,156	—	26,112	17,955	4,429	32,501	23,111	4,429
Transportation and Blending	—	—	—	—	—	—	—	—	—
Operating	704	486	37	2,346	1,772	748	3,050	2,258	785
Realized (Gain) Loss on Risk    Management	—	—	—	112	104	(21)	112	104	(21)
Operating Margin	699	573	45	1,740	212	(423)	2,439	785	(378)
Unrealized (Gain) Loss on Risk    Management	—	—	—	18	1	(1)	18	1	(1)
Depreciation, Depletion and    Amortization	208	226	8	640	2,381	728	848	2,607	736
Exploration Expense	—	—	—	—	—	—	—	—	—
(Income) Loss From Equity-Accounted     Affiliates	—	—	—	—	—		—	—	—
Segment Income (Loss)	491	347	37	1,082	(2,170)	(1,150)	1,573	(1,823)	(1,113)

(1)Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

	Corporate and Eliminations			Consolidated
For the years ended December 31,	2022	2021 (1) (2)	2020	2022	2021 (1) (2)	2020
Revenues
Gross Sales	(7,464)	(5,291)	(609)	71,765	48,811	13,914
Less: Royalties	—	—	—	4,868	2,454	371
	(7,464)	(5,291)	(609)	66,897	46,357	13,543
Expenses
Purchased Product	(5,533)	(3,844)	(278)	33,801	23,326	5,681
Transportation and Blending	(664)	(676)	(36)	11,530	8,038	4,728
Operating	(1,270)	(783)	(306)	5,569	4,716	1,955
Realized (Gain) Loss on Risk Management	31	101	5	1,762	993	252
Unrealized (Gain) Loss on Risk Management	(89)	(18)	—	(126)	2	56
Depreciation, Depletion and Amortization	113	118	161	4,679	5,886	3,464
Exploration Expense	—	—	—	101	18	91
(Income) Loss From Equity-Accounted Affiliates	—	(5)	—	(15)	(57)	—
Segment Income (Loss)	(52)	(184)	(155)	9,596	3,435	(2,684)
General and Administrative	865	849	292	865	849	292
Finance Costs	820	1,082	536	820	1,082	536
Interest Income	(81)	(23)	(9)	(81)	(23)	(9)
Integration and Transaction Costs	106	349	29	106	349	29
Foreign Exchange (Gain) Loss, Net	343	(174)	(181)	343	(174)	(181)
Revaluation (Gains)	(549)	—	—	(549)	—	—
Re-measurement of Contingent Payment	162	575	(80)	162	575	(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)	(81)	(269)	(229)	(81)
Other (Income) Loss, Net	(532)	(309)	40	(532)	(309)	40
	865	2,120	546	865	2,120	546
Earnings (Loss) Before Income Tax				8,731	1,315	(3,230)
Income Tax Expense (Recovery)				2,281	728	(851)
Net Earnings (Loss)				6,450	587	(2,379)

(1)Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).

(2)Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

Schedule of Revenues by Product

B) Revenues by Product

For the years ended December 31,	2022	2021	2020
Upstream
Crude Oil (1)	29,834	19,877	8,017
NGLs (1)	2,346	1,983	727
Natural Gas	3,690	3,032	535
Other	389	498	58
Downstream
Canadian Manufacturing
Synthetic Crude Oil	2,360	1,951	—
Asphalt	620	477	—
Other Products and Services (2)	4,812	3,787	82
U.S. Manufacturing
Gasoline	14,116	10,111	2,352
Diesel and Distillate	11,453	6,429	1,569
Other Products	4,741	3,503	812
Corporate and Eliminations (2)	(7,464)	(5,291)	(609)
Consolidated	66,897	46,357	13,543

(1)Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.

(2)Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

Schedule of Geographical Information

C) Geographical Information

	Revenues (1)
For the years ended December 31,	2022	2021	2020
Canada	33,222	23,768	8,715
United States	32,313	21,326	4,828
China	1,362	1,263	—
Consolidated	66,897	46,357	13,543

(1)Revenues by country are classified based on where the operations are located.

	Non-Current Assets (1)
As at December 31,	2022	2021 (2)
Canada	35,194	33,981
United States	4,824	4,093
China	2,064	2,583
Indonesia	365	311
Consolidated	42,447	40,968

(1)Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill.

(2)Canada excludes assets held for sale of $1.3 billion that were divested in 2022.

Schedule of Assets by Segment

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
As at December 31,	2022	2021	2022	2021	2022	2021
Oil Sands	674	653	24,657	22,535	638	754
Conventional	6	6	2,020	2,174	2	2
Offshore	5	61	2,549	2,822	152	160
Canadian Manufacturing (1)	—	—	2,466	2,558	252	388
U.S. Manufacturing	—	—	4,482	3,745	329	252
Corporate and Eliminations	—	—	325	391	472	454
Consolidated	685	720	36,499	34,225	1,845	2,010

	Goodwill		Total Assets
As at December 31,	2022	2021	2022	2021 (2)
Oil Sands	2,923	3,473	32,248	31,070
Conventional	—	—	2,410	3,026
Offshore	—	—	3,339	3,597
Canadian Manufacturing (1)	—	—	3,172	3,884
U.S. Manufacturing (3)	—	—	8,324	7,509
Corporate and Eliminations (3)	—	—	6,376	5,018
Consolidated	2,923	3,473	55,869	54,104

(1)Prior period results have been re-presented. PP&E, ROU assets and total assets from the remaining commercial fuels business and the historic retail fuels business have been aggregated with the Canadian Manufacturing segment. 

(2)Total assets include assets held for sale $1.3 billion that were divested in 2022.

(3)Prior period results were re-presented to move income tax receivable and deferred income tax assets from the U.S. Manufacturing segment to the Corporate and Eliminations segment.

Schedule of Capital Expenditures

E) Capital Expenditures (1)

For the years ended December 31,	2022	2021	2020
Capital Investment
Oil Sands	1,792	1,019	427
Conventional	344	222	78
Offshore
Asia Pacific	8	21	—
Atlantic	302	154	—
Total Upstream	2,446	1,416	505
Canadian Manufacturing (2)	117	68	33
U.S. Manufacturing	1,059	995	243
Total Downstream	1,176	1,063	276
Corporate and Eliminations	86	84	60
	3,708	2,563	841
Acquisitions (Note 5)
Oil Sands (3)	1,609	5,005	6
Conventional	12	551	12
Offshore (4)	—	3,129	—
Canadian Manufacturing (2)	—	2,973	—
U.S. Manufacturing	—	1,618	—
Corporate and Eliminations	—	156	—
	1,621	13,432	18
Total Capital Expenditures	5,329	15,995	859

(1)Includes expenditures on PP&E, E&E assets and capitalized interest.

(2)Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).

(3)Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-existing interest in SOSP of $1.6 billion.

(4)Excludes capital expenditures related to the HCML joint venture, which are accounted for using the equity method.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure Of Summary Of Significant Accounting Policies [Abstract]

Disclosure of Revisions to Prior Period

Year Ended December 31, 2021

Oil Sands Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Purchased Product	3,188	(784)	—	2,404
Transportation and Blending	7,841	784	—	8,625
	11,029	—	—	11,029

Canadian Manufacturing	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	4,472	—	1,743	6,215
Purchased Product	3,552	—	1,604	5,156
Operating	388	—	98	486
Depreciation, Depletion and Amortization	167	—	59	226
	365	—	(18)	347

Retail	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	2,158	—	(2,158)	—
Purchased Product	2,019	—	(2,019)	—
Operating	98	—	(98)	—
Depreciation, Depletion and Amortization	59	—	(59)	—
	(18)	—	18	—

Corporate and Eliminations Segment	Previously Reported	Revisions	Segment Aggregation	Revised
Gross Sales	(5,706)	—	415	(5,291)
Purchased Product	(4,888)	629	415	(3,844)
Transportation and Blending	(47)	(629)	—	(676)
	(771)	—	—	(771)

Consolidated	Previously Reported	Revision	Segment Aggregation	Revised
Purchased Product	23,481	(155)	—	23,326
Transportation and Blending	7,883	155	—	8,038
	31,364	—	—	31,364

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2022

Business Combinations [Abstract]

Disclosure of detailed information about business combination

As at	August 31, 2022
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	9
Accounts Receivable and Accrued Revenues	164
Inventories	88
Property, Plant and Equipment	3,218
Accounts Payable and Accrued Liabilities	(313)
Income Tax Payable	(39)
Decommissioning Liabilities	(48)
Deferred Income Tax Liabilities	(486)
Total Identifiable Net Assets	2,593

As at	August 31, 2022
Cash, Net of Closing Adjustments	394
Bay Du Nord	40
Variable Payment	600
Total Consideration	1,034

As at	January 1, 2021
Consideration
Common Shares	6,111
Preferred Shares	519
Share Purchase Warrants	216
Replacement Stock Options	9
Other	17
Non-Controlling Interest	11
Total Consideration and Non-Controlling Interest	6,883
Identifiable Assets Acquired and Liabilities Assumed
Cash	735
Restricted Cash	164
Accounts Receivable and Accrued Revenues	1,307
Inventories	1,133
Exploration and Evaluation Assets	45
Property, Plant and Equipment	13,296
Right-of-Use Assets	1,132
Long-Term Income Tax Receivable	66
Other Assets	230
Investment in Equity-Accounted Affiliates	363
Deferred Income Tax Assets, Net	1,062
Accounts Payable and Accrued Liabilities	(2,283)
Income Tax Payable	(94)
Short-Term Borrowings	(40)
Long-Term Debt	(6,602)
Lease Liabilities	(1,441)
Decommissioning Liabilities	(2,697)
Other Liabilities	(782)
Total Identifiable Net Assets	5,594
Goodwill	1,289

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General and Administrative (Tables)

12 Months Ended

Dec. 31, 2022

General And Administrative Expenses [Abstract]

Summary of General and Administrative Expenses

For the years ended December 31,	2022	2021	2020
Salaries and Benefits	204	264	145
Administrative and Other	297	225	102
Stock-Based Compensation Expense (Recovery) (Note 34)	373	159	49
Other Incentive Benefits Expense (Recovery)	(9)	201	(4)
	865	849	292

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Finance Costs (Tables)

12 Months Ended

Dec. 31, 2022

Finance Costs [Abstract]

Schedule of Finance Cost

For the years ended December 31,	2022	2021	2020
Interest Expense – Short-Term Borrowings and Long-Term Debt	478	557	392
Net Premium (Discount) on Redemption of Long-Term Debt (1)	(29)	121	(25)
Interest Expense – Lease Liabilities (Note 27)	163	171	87
Unwinding of Discount on Decommissioning Liabilities (Note 29)	176	199	57
Other	37	34	25
	825	1,082	536
Capitalized Interest	(5)	—	—
	820	1,082	536

(1)     Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.

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Foreign Exchange (Gain) Loss, Net (Tables)

12 Months Ended

Dec. 31, 2022

Foreign Exchange Gains Losses [Abstract]

Schedule of Foreign Exchange Gain Loss Net

For the years ended December 31,	2022	2021	2020
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	365	(230)	(194)
Other	—	(82)	63
Unrealized Foreign Exchange (Gain) Loss	365	(312)	(131)
Realized Foreign Exchange (Gain) Loss	(22)	138	(50)
	343	(174)	(181)

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Impairment Charges and Reversals (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of impairment loss recognised or reversed for cash-generating unit [abstract]

Summary of Impairment Losses and Estimated Recoverable Amounts

The following table summarizes impairment reversals recorded in 2021 and estimated recoverable amounts as at December 31, 2021, by CGU:

	Reversal of Impairment	Recoverable Amount
Clearwater	145	427
Elmworth-Wapiti	115	747
Kaybob-Edson	118	837

The following table summarizes impairment losses recorded in 2020 and estimated recoverable amounts as at December 31, 2020, by CGU:

	Impairment	Recoverable Amount
Clearwater	260	160
Elmworth-Wapiti	120	259
Kaybob-Edson	175	384

Summary of Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2023	2024	2025	2026	2027	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	80.33	78.50	76.95	77.61	79.16	2.00	%
Western Canadian Select (C$/barrel)	76.54	77.75	77.55	80.07	81.89	2.00	%
Condensate at Edmonton (C$/barrel)	106.22	101.35	98.94	100.19	101.74	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	4.23	4.40	4.21	4.27	4.34	2.00	%

(1)      Assumes natural gas heating value of one million British thermal units per thousand cubic feet (“Mcf”).

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2021, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2022	2023	2024	2025	2026	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	72.83	68.78	66.76	68.09	69.45	2.00	%
Western Canadian Select (C$/barrel)	74.43	69.17	66.54	67.87	69.23	2.00	%
Edmonton C5+ (C$/barrel)	91.85	85.53	82.98	84.63	86.33	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	3.56	3.20	3.05	3.10	3.17	2.00	%

(1)      Assumes natural gas heating value of one million British thermal units per thousand cubic feet ("Mcf").

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2021	2022	2023	2024	2025	Average Annual Increase Thereafter
West Texas Intermediate (US$/barrel)	47.17	50.17	53.17	54.97	56.07	2.00	%
Western Canadian Select (C$/barrel)	44.63	48.18	52.10	54.10	55.19	2.00	%
Edmonton C5+ (C$/barrel)	59.24	63.19	67.34	69.77	71.18	2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	2.88	2.80	2.71	2.75	2.80	2.00	%

(1)      Assumes gas heating value of one million British thermal units per Mcf.

Summary of Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated impairment amount used in the impairment testing completed as at December 31, 2020, for the following CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Clearwater	7	(7)	(68)	128
Elmworth-Wapiti	10	(10)	(71)	126
Kaybob-Edson	17	(19)	(71)	140

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
U.S. Manufacturing	69	(65)	(268)	268

	Increase (Decrease) to Impairment Reversal Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
U.S. Manufacturing	(72)	14	168	(342)

The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have had on the calculated recoverable amounts used in the impairment testing completed as at December 31, 2021, for the following CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Borger, Wood River and Lima	251	(283)	(990)	996

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount used in the impairment testing completed as at September 30, 2020, for the following CGU:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates	Five Percent Decrease in the Forward Price Estimates
Borger	89	(110)	(348)	342

Summary of Crude Oil and Forward Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were:

(US$/barrel)	2023	2024	2025	2026	2027
West Texas Intermediate	80.33	78.50	76.95	77.61	79.16
Differential WTI-WTS	(0.56)	(0.56)	(0.56)	(0.56)	(0.56)
Differential WTI-WCS	(23.32)	(19.09)	(17.42)	(15.87)	(15.74)
Chicago 3-2-1 Crack Spreads (WTI)	29.37	24.10	22.12	21.70	21.67

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032.

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2021, the forward prices used to determine future cash flows were:

	2022 to 2023		2024 to 2026
(US$/barrel)	Low	High	Low	High
West Texas Intermediate	68.78	72.83	66.76	69.45
Differential WTI-WTS	—	0.01	(0.06)	(0.06)
Differential WTI-WCS	13.54	13.67	13.75	14.30
Chicago 3-2-1 Crack Spreads (WTI)	14.87	18.44	14.68	16.81

Crude Oil and Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were:

	2021 to 2022		2023 to 2025
(US$/barrel)	Low	High	Low	High
West Texas Intermediate	36.36	50.84	49.66	58.74
Differential WTI-WTS	0.37	1.73	1.21	1.81
Group 3 3-2-1 Crack Spreads (WTI)	11.56	13.23	11.79	16.58

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure Of Income Taxes Continuing Operations [Abstract]

Provision for Income Taxes

For the years ended December 31,	2022	2021	2020
Current Tax
Canada	1,252	104	(14)
United States	104	—	1
Asia Pacific	262	171	—
Other International	21	1	—
Total Current Tax Expense (Recovery)	1,639	276	(13)
Deferred Tax Expense (Recovery)	642	452	(838)
	2,281	728	(851)

For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income.

Disclosure Of Reconciliation Of Accounting Profit From Continuing Operations Multiplied By Applicable Tax Rates Explanatory

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

For the years ended December 31,	2022		2021		2020
Earnings (Loss) From Operations Before Income Tax	8,731		1,315		(3,230)
Canadian Statutory Rate	23.7	%	23.7	%	24.0	%
Expected Income Tax Expense (Recovery) From Operations	2,069		312		(775)
Effect on Taxes Resulting From:
Statutory and Other Rate Differences	17		3		19
Non-Taxable Capital (Gains) Losses	84		63		(42)
Non-Recognition of Capital (Gains) Losses	84		27		(42)
Adjustments Arising From Prior Year Tax Filings	15		(5)		(8)
U.S. Tax Attribute Limitation	—		217		—
Impact of Rate Changes	—		106		(7)
Other	12		5		4
Total Tax Expense (Recovery) From Operations	2,281		728		(851)
Effective Tax Rate	26.1	%	55.4	%	26.3	%

Disclosure of deferred taxes

The breakdown of deferred income tax liabilities and deferred income tax assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows:

For the years ended December 31,	2022	2021
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled Within Twelve Months	55	—
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months	4,460	4,046
	4,515	4,046
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months	(31)	(556)
Deferred Income Tax Assets to be Settled After More Than Twelve Months	(747)	(898)
	(778)	(1,454)
Net Deferred Income Tax Liability	3,737	2,592

Disclosure Of Reconciliation Of Changes In Deferred Tax Liability Asset Explanatory

The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is:

Deferred Income Tax Liabilities	PP&E	Risk Management	Other	Total
As at December 31, 2020	4,124	—	22	4,146
Charged (Credited) to Earnings	(234)	—	75	(159)
Charged (Credited) to Husky Purchase Price Allocation	59	—	—	59
As at December 31, 2021	3,949	—	97	4,046
Charged (Credited) to Earnings	25	11	(53)	(17)
Charged (Credited) to Sunrise Purchase Price Allocation	486	—	—	486
As at December 31, 2022	4,460	11	44	4,515

Deferred Income Tax Assets	Unused Tax Losses	Risk Management	Other	Total
As at December 31, 2020	(659)	(13)	(276)	(948)
Charged (Credited) to Earnings	668	1	(58)	611
Charged (Credited) to Husky Purchase Price Allocation	(656)	1	(466)	(1,121)
Charged (Credited) to Other Comprehensive Income	(8)	—	12	4
As at December 31, 2021	(655)	(11)	(788)	(1,454)
Charged (Credited) to Earnings	490	11	158	659
Charged (Credited) to Sunrise Purchase Price Allocation	—	—	—	—
Charged (Credited) to Other Comprehensive Income	9	—	8	17
As at December 31, 2022	(156)	—	(622)	(778)

Net Deferred Income Tax Liabilities	Total
As at December 31, 2020	3,198
Charged (Credited) to Earnings	452
Charged (Credited) to Husky Purchase Price Allocation	(1,062)
Charged (Credited) to Other Comprehensive Income	4
As at December 31, 2021	2,592
Charged (Credited) to Earnings	642
Charged (Credited) to Sunrise Purchase Price Allocation	486
Charged (Credited) to Other Comprehensive Income	17
As at December 31, 2022	3,737

Disclosure Of Temporary Difference Unused Tax Losses And Unused Tax Credits

The approximate amounts of tax pools available, including tax losses, are:

As at December 31,	2022	2021
Canada	8,505	11,167
United States	6,477	5,915
Asia Pacific	457	600
	15,439	17,682

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Per Share Amounts (Tables)

12 Months Ended

Dec. 31, 2022

Earnings per share [abstract]

Schedule Representing Per Share Amounts

For the years ended December 31,	2022	2021	2020
Net Earnings (Loss)	6,450	587	(2,379)
Effect of Cumulative Dividends on Preferred Shares	(35)	(34)	—
Net Earnings (Loss) – Basic and Diluted	6,415	553	(2,379)
Basic – Weighted Average Number of Shares	1,951.3	2,016.2	1,228.9
Dilutive Effect of Warrants	44.8	27.6	—
Dilutive Effect of Net Settlement Rights	10.0	1.3	—
Diluted – Weighted Average Number of Shares	2,006.1	2,045.1	1,228.9
Net Earnings (Loss) Per Common Share – Basic ($)	3.29	0.27	(1.94)
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)	3.20	0.27	(1.94)

(1)For the year ended December 31, 2022, net earnings of $52 million (2021 – $22 million; 2020 – $nil) and common shares of 1.6 million (2021 – 1.9 million; 2020 – nil) related to the assumed exercise of the Cenovus replacement stock options, were excluded from the calculation of dilutive net earnings (loss) per share. For further information on the Company’s stock-based compensation plans, see Note 34.

(2)For the year ended December 31, 2021 and December 31, 2020, NSRs of 18 million and 31 million, respectively, were excluded from the calculation of diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceeded the market price of Cenovus’s common shares.

Disclosure Of Dividends To Shareholders

Common Share Dividends

	2022		2021		2020
For the years ended December 31,	Per Share	Amount	Per Share	Amount	Per Share	Amount
Base Dividends	0.350	682	0.088	176	0.063	77
Variable Dividends	0.114	219	—	—	—	—
Total Common Share Dividends Declared and Paid	0.464	901	0.088	176	0.063	77

Preferred Share Dividends

For the years ended December 31,	2022	2021
Series 1 First Preferred Shares	7	7
Series 2 First Preferred Shares	1	1
Series 3 First Preferred Shares	12	12
Series 5 First Preferred Shares	9	9
Series 7 First Preferred Shares	6	5
Total Preferred Share Dividends Declared	35	34

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Cash and Cash Equivalents (Tables)

12 Months Ended

Dec. 31, 2022

Cash and cash equivalents [abstract]

Disclosure Of Cash And Cash Equivalent Explanatory

As at December 31,	2022	2021
Cash	3,195	2,366
Short-Term Investments	1,329	507
	4,524	2,873

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Accounts Receivable and Accrued Revenues (Tables)

12 Months Ended

Dec. 31, 2022

Trade and other current receivables [abstract]

Schedule of Accounts Receivable and Accrued Revenues

As at December 31,	2022	2021
Trade and Accruals	2,962	2,548
Prepaids and Deposits	402	486
Partner Advances	—	371
Joint Operations Receivables	51	225
Other (1)	58	240
	3,473	3,870

(1)As at December 31, 2022, includes insurance proceeds receivable of $nil related to the 2018 Superior Refinery incident (December 31, 2021 – $135 million).

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Inventories (Tables)

12 Months Ended

Dec. 31, 2022

Classes of current inventories [abstract]

Disclosure Of Detailed Information About Inventories Explanatory

As at December 31,	2022	2021
Product
Crude Oil	2,424	2,060
Diluent	366	515
Natural Gas and NGLs	50	33
Refined Products	1,169	1,043
Total Product	4,009	3,651
Parts and Supplies	303	268
	4,312	3,919

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Assets Held for Sale (Tables)

12 Months Ended

Dec. 31, 2022

Assets Held for Sale [Abstract]

Assets Held for Sale

	PP&E	ROU Assets	Goodwill	Lease Liabilities	Decommissioning Liabilities
Retail Gas Stations	498	54	—	(58)	(86)
Tucker	505	—	88	—	(33)
Wembley	159	—	—	—	(9)
	1,162	54	88	(58)	(128)

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Exploration and Evaluation Assets, Net (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure Of Exploration And Evaluation Assets [Abstract]

Summary of Exploration and Valuation Assets, Net

	Total
As at December 31, 2020	623
Acquisitions (Note 5)	45
Additions	55
Write-downs	(9)
Change in Decommissioning Liabilities	6
As at December 31, 2021	720
Additions	37
Write-downs	(64)
Change in Decommissioning Liabilities	(12)
Exchange Rate Movements and Other (1)	4
As at December 31, 2022	685

(1)Immediately prior to the Sunrise Acquisition, Bay du Nord had a carrying value of $nil. The Company re-measured its interest in Bay du Nord to $40 million and recognized a revaluation gain of $40 million.

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Property, Plant and Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of detailed information about property, plant and equipment [abstract]

Summary of Property, Plant and Equipment

	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Manufacturing Assets	Other Assets (1)	Total
COST
As at December 31, 2020	29,867	218	5,671	1,290	37,046
Acquisitions (Note 5)	8,633	—	3,901	846	13,380
Additions	1,368	9	1,023	115	2,515
Change in Decommissioning Liabilities	(63)	1	40	24	2
Divestitures (Note 10)	(630)	—	—	—	(630)
Transfers to Assets Held for Sale (Note 18)	(754)	—	—	(522)	(1,276)
Exchange Rate Movements and Other	22	—	(140)	(18)	(136)
As at December 31, 2021	38,443	228	10,495	1,735	50,901
Acquisitions (Note 5) (2)	3,230	—	—	—	3,230
Additions	2,409	11	1,143	108	3,671
Change in Decommissioning Liabilities	(186)	(6)	(29)	(32)	(253)
Divestitures (Note 5) (2)	(557)	—	—	—	(557)
Exchange Rate Movements and Other	189	21	523	14	747
As at December 31, 2022	43,528	254	12,132	1,825	57,739
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2020	8,361	42	2,195	1,037	11,635
Depreciation, Depletion and Amortization	3,335	10	526	128	3,999
Impairment Charges (Note 11)	—	—	1,931	—	1,931
Impairment Reversals (Note 11)	(378)	—	—	—	(378)
Divestitures (Note 10)	(377)	—	—	—	(377)
Transfers to Assets Held for Sale (Note 18)	(90)	—	—	(24)	(114)
Exchange Rate Movements and Other	61	1	(80)	(2)	(20)
As at December 31, 2021	10,912	53	4,572	1,139	16,676
Depreciation, Depletion and Amortization (3)	3,461	37	466	103	4,067
Impairment Charges (Note 11)	—	—	1,499	—	1,499
Impairment Reversals (Note 11)	—	—	(1,233)	—	(1,233)
Divestitures (Note 5) (2)	(84)	—	—	—	(84)
Exchange Rate Movements and Other	13	16	243	43	315
As at December 31, 2022	14,302	106	5,547	1,285	21,240
CARRYING VALUE
As at December 31, 2020	21,506	176	3,476	253	25,411
As at December 31, 2021	27,531	175	5,923	596	34,225
As at December 31, 2022	29,226	148	6,585	540	36,499

(1)Includes assets within the commercial and retail fuels businesses, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2)In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million.

(3)DD&A includes asset write-downs of $26 million in the Offshore segment and $25 million in the Canadian Manufacturing segment.

Disclosure Of Property Plant And Equipment Under Construction Explanatory

PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A:

As at December 31,	2022	2021
Development and Production	2,142	2,415
Downstream	137	943
	2,279	3,358

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Right of Use Assets, Net (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of quantitative information about right-of-use assets [abstract]

Summary of Right of Use Assets, Net

	Real Estate	Transportation and Storage Assets (1)	Manufacturing Assets	Other Assets (2)	Total
COST
As at December 31, 2020	495	977	15	15	1,502
Acquisitions (Note 5)	99	765	138	130	1,132
Additions	4	96	7	3	110
Modifications	1	20	1	—	22
Re-measurements	(2)	1	—	(3)	(4)
Transfers to Assets Held for Sale (Note 18)	—	—	—	(78)	(78)
Exchange Rate Movements and Other	(5)	(18)	—	(5)	(28)
As at December 31, 2021	592	1,841	161	62	2,656
Additions	—	22	1	2	25
Modifications	9	69	3	2	83
Re-measurements	1	3	2	1	7
Terminations	(1)	(6)	(2)	(1)	(10)
Exchange Rate Movements and Other	(2)	(89)	9	8	(74)
As at December 31, 2022	599	1,840	174	74	2,687
ACCUMULATED DEPRECIATION
As at December 31, 2020	58	293	5	7	363
Depreciation	38	239	23	23	323
Impairment Charges (Note 11)	—	5	5	1	11
Terminations	—	(3)	—	—	(3)
Transfers to Assets Held for Sale (Note 18)	—	—	—	(24)	(24)
Exchange Rate Movements and Other	(4)	(14)	—	(6)	(24)
As at December 31, 2021	92	520	33	1	646
Depreciation	36	226	21	14	297
Terminations	—	(6)	—	—	(6)
Exchange Rate Movements and Other	(1)	(95)	4	(3)	(95)
As at December 31, 2022	127	645	58	12	842
CARRYING VALUE
As at December 31, 2020	437	684	10	8	1,139
As at December 31, 2021	500	1,321	128	61	2,010
As at December 31, 2022	472	1,195	116	62	1,845

(1)Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.

(2)Includes assets within the commercial fuels business, fleet vehicles and other equipment.

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Joint Arrangements (Tables)

12 Months Ended

Dec. 31, 2022

Subclassifications of assets, liabilities and equities [abstract]

Disclosure of joint ventures

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations

For the years ended December 31,	2022	2021
Revenue	383	439
Expenses	350	395
Net Earnings (Loss)	33	44

Balance Sheet

As at December 31,	2022	2021
Current Assets (1)	247	167
Non-Current Assets	1,926	1,433
Current Liabilities	160	62
Non-Current Liabilities	1,293	896
Net Assets	720	642

(1)Includes cash and cash equivalents of $64 million (December 31, 2021 – $46 million).

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Other Assets (Tables)

12 Months Ended

Dec. 31, 2022

Other Noncurrent Assets [Abstract]

Summary of Other Assets

As at December 31,	2022	2021
Intangible Assets (1)	19	78
Private Equity Investments (Note 37)	55	53
Other Equity Investments	—	77
Net Investment in Finance Leases	62	60
Long-Term Receivables and Prepaids	120	77
Precious Metals	86	85
Other	—	1
	342	431

(1)    For the twelve months ended December 31, 2022, $49 million of previously capitalized intangible asset costs were written off as DD&A in the Oil Sands segment as the carrying value was not considered to be recoverable.

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2022

Goodwill [Abstract]

Schedule of changes in goodwill

	2022	2021
Carrying Value, Beginning of Year	3,473	2,272
Goodwill Recognized (Note 5)	—	1,289
Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18)	(550)	(88)
Carrying Value, End of Year	2,923	3,473

The carrying amount of goodwill is allocated to the following CGUs:

As at December 31,	2022	2021
Primrose (Foster Creek)	1,171	1,171
Christina Lake	1,101	1,101
Lloydminster Thermal	651	651
Sunrise (Note 5)	—	550
	2,923	3,473

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Accounts Payable and Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

Trade and other current payables [abstract]

Schedule of Accounts Payable and Accrued Liabilities

As at December 31,	2022	2021
Accruals	3,412	2,722
Trade	2,331	2,554
Interest	80	128
Partner Advances	—	371
Employee Long-Term Incentives	162	317
Joint Operations Payable	66	28
Risk Management	39	116
Provisions for Onerous and Unfavourable Contracts	25	31
Other	9	86
	6,124	6,353

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Contingent Payments (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of contingent liabilities in business combination [abstract]

Summary of Contingent Payment

	Total
As at December 31, 2021	—
Initial Recognition	600
Liabilities Settled or Payable	(92)
Re-measurement (1)	(89)
As at December 31, 2022	419
Less: Current Portion	263
Long-Term Portion	156

(1)     The variable payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).

	2022	2021
Contingent Payment, Beginning of Year	236	63
Re-measurement (1)	251	575
Liabilities Settled	(487)	(402)
Contingent Payment, End of Year	—	236

(1)     The contingent payment was carried at fair value. Changes in fair value were recorded in net earnings (loss).

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Debt and Capital Structure (Tables)

12 Months Ended

Dec. 31, 2022

Borrowings [abstract]

Schedule of Short-Term and Long-Term Debt

A) Short-Term Borrowings

As at December 31,	Notes	2022	2021
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	115	79
Total Debt Principal		115	79

B) Long-Term Debt

As at December 31,	Notes	2022	2021
Committed Credit Facility (1)	i	—	—
U.S. Dollar Denominated Unsecured Notes	ii	6,537	9,363
Canadian Dollar Unsecured Notes	ii	2,000	2,750
Total Debt Principal		8,537	12,113
Debt Premiums (Discounts), Net, and Transaction Costs		154	272
Long-Term Debt		8,691	12,385

(1)The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

Schedule Remaining Principal Amounts of U.S. Dollar Denominated Unsecured Notes

	2022	2021
	US$ Principal	US$ Principal
U.S. Dollar Unsecured Notes
3.95% due April 15, 2022	—	500
3.00% due August 15, 2022	—	500
3.80% due September 15, 2023	115	335
4.00% due April 15, 2024	269	481
5.38% due July 15, 2025	533	334
4.25% due April 15, 2027	589	—
4.40% due April 15, 2029	510	—
6.75% due November 15, 2039	455	—
4.45% due September 15, 2042	58	—
5.20% due September 15, 2043	29	—
	2,558	2,150

	C$ Principal	C$ Principal
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025	750	—

The principal amounts of the Company’s outstanding unsecured notes are:

	2022		2021
As at December 31,	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Denominated Unsecured Notes
3.80% due September 15, 2023	—	—	115	146
4.00% due April 15, 2024	—	—	269	341
5.38% due July 15, 2025	133	181	666	844
4.25% due April 15, 2027	373	505	962	1,220
4.40% due April 15, 2029	240	324	750	951
2.65% due January 15, 2032	500	677	500	634
5.25% due June 15, 2037	583	790	583	739
6.80% due September 15, 2037	387	524	387	490
6.75% due November 15, 2039	935	1,267	1,390	1,763
4.45% due September 15, 2042	97	131	155	197
5.20% due September 15, 2043	29	39	58	73
5.40% due June 15, 2047	800	1,083	800	1,014
3.75% due February 15, 2052	750	1,016	750	951
	4,827	6,537	7,385	9,363
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025		—		750
3.60% due March 10, 2027		750		750
3.50% due February 7, 2028		1,250		1,250
		2,000		2,750
Total Unsecured Notes		8,537		12,113

Mandatory Debt Payments

	U.S. Dollar Unsecured Notes		Canadian Dollar Unsecured Notes	Total
As at December 31, 2022	US$ Principal	C$ Principal Equivalent	C$ Principal	C$ Principal and Equivalent
2023	—	—	—	—
2024	—	—	—	—
2025	133	181	—	181
2026	—	—	—	—
2027	373	505	750	1,255
Thereafter	4,321	5,851	1,250	7,101
	4,827	6,537	2,000	8,537

Summary of Net Debt to Adjusted EBITDA

Net Debt to Adjusted EBITDA

As at December 31,	2022	2021	2020
Short-Term Borrowings	115	79	121
Current Portion of Long-Term Debt	—	—	—
Long-Term Portion of Long-Term Debt	8,691	12,385	7,441
Total Debt	8,806	12,464	7,562
Less: Cash and Cash Equivalents	(4,524)	(2,873)	(378)
Net Debt	4,282	9,591	7,184
Net Earnings (Loss)	6,450	587	(2,379)
Add (Deduct):
Finance Costs	820	1,082	536
Interest Income	(81)	(23)	(9)
Income Tax Expense (Recovery)	2,281	728	(851)
Depreciation, Depletion and Amortization	4,679	5,886	3,464
E&E Asset Write-downs	64	18	91
(Income) Loss From Equity-Accounted Affiliates	(15)	(57)	—
Unrealized (Gain) Loss on Risk Management	(126)	2	56
Foreign Exchange (Gain) Loss, Net	343	(174)	(181)
Revaluation (Gains)	(549)	—	—
Re-measurement of Contingent Payments	162	575	(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)	(81)
Other (Income) Loss, Net	(532)	(309)	40
Adjusted EBITDA (1)	13,227	8,086	606
Net Debt to Adjusted EBITDA	0.3x	1.2x	11.9x

(1)Calculated on a trailing twelve-month basis.

Disclosure Of Net Debt To Adjusted Funds Flow

Net Debt to Adjusted Funds Flow

As at December 31,	2022	2021	2020
Net Debt	4,282	9,591	7,184
Cash From (Used in) Operating Activities	11,403	5,919	273
(Add) Deduct:
Settlement of Decommissioning Liabilities	(150)	(102)	(42)
Net Change in Non-Cash Working Capital	575	(1,227)	198
Adjusted Funds Flow (1)	10,978	7,248	117
Net Debt to Adjusted Funds Flow	0.4x	1.3x	61.4x

(1)    Calculated on a trailing twelve-month basis.

Summary of Net Debt to Capitalization

Net Debt to Capitalization

As at December 31,	2022		2021		2020
Net Debt	4,282		9,591		7,184
Shareholders’ Equity	27,576		23,596		16,707
Capitalization	31,858		33,187		23,891
Net Debt to Capitalization	13	%	29	%	30	%

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Lease Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

Lease liabilities [abstract]

Summary of Lease Liabilities

	2022	2021
Lease Liabilities, Beginning of Year	2,957	1,757
Acquisitions (Note 5)	—	1,441
Additions	25	110
Interest Expense (Note 7)	163	171
Lease Payments	(465)	(471)
Modifications	83	22
Re-measurements	7	(4)
Terminations	(5)	(1)
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	—	(10)
Exchange Rate Movements and Other	71	(58)
Lease Liabilities, End of Year	2,836	2,957
Less: Current Portion	308	272
Long-Term Portion	2,528	2,685

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Decommissioning Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

Provision for decommissioning, restoration and rehabilitation costs [abstract]

Summary of Decommissioning Provision

	2022	2021
Decommissioning Liabilities, Beginning of Year	3,906	1,248
Liabilities Incurred	22	30
Liabilities Acquired (Note 5) (1)	48	2,856
Liabilities Settled	(215)	(144)
Liabilities Divested (Note 5) (1)	(89)	(140)
Change in Estimated Future Cash Flows	693	(472)
Change in Discount Rates	(980)	450
Unwinding of Discount on Decommissioning Liabilities (Note 7)	176	199
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	—	(128)
Exchange Rate Movements and Other	(2)	7
Decommissioning Liabilities, End of Year	3,559	3,906

(1)     In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was

Description Of Major Assumptions Made Concerning Future Events Other Provisions Explanatory

Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:

	Sensitivity	2022		2021
As at December 31,	Range	Increase	Decrease	Increase	Decrease
Credit-Adjusted Risk-Free Rate	± one percent	(319)	419	(623)	875
Inflation Rate	± one percent	419	(320)	873	(625)

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Other Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

Miscellaneous non-current liabilities [abstract]

Summary of Other Liabilities

As at December 31,	2022	2021
Pension and Other Post-Employment Benefit Plan	201	288
Provision for West White Rose Expansion Project (1)	204	259
Provisions for Onerous and Unfavourable Contracts	95	99
Employee Long-Term Incentives	245	74
Drilling Provisions	31	56
Deferred Revenue	45	41
Other (2)	221	112
	1,042	929

(1)     On May 31, 2022, the Company divested of 12.5 percent of its working interest in the White Rose field and satellite extensions reducing the provision by $47 million (see Note 10). Cenovus expects to draw down the provision by $58 million in the next twelve months.

(2)     As at December 31, 2022, other includes a net RVO of $101 million. Gross amounts of the RVO and RINs asset were $1.1 billion and $1.0 billion, respectively.

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Pensions and Other Post-Employment Benefits (Tables)

12 Months Ended

Dec. 31, 2022

Pensions And Other Post Employment Benefits [Abstract]

Summary of Defined Benefit and OPEB Plan Obligation and Funded Status

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:

	Pension Benefits		OPEB
	2022	2021	2022	2021
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year	220	188	225	20
Plan Acquisition Upon the Arrangement (1)	—	41	—	224
Current Service Costs	16	16	8	9
Past Service Costs - Curtailment and Plan Amendments	—	(1)	—	(3)
Interest Costs (2)	7	6	7	6
Benefits Paid	(12)	(17)	(8)	(8)
Plan Participant Contributions	2	2	—	—
Re-measurements:
(Gains) Losses From Experience Adjustments	1	4	(2)	10
(Gains) Losses From Changes in Demographic Assumptions	—	(1)	—	(3)
(Gains) Losses From Changes in Financial Assumptions	(64)	(18)	(57)	(30)
Exchange Rate Movements and Other	2	—	1	—
Defined Benefit Obligation, End of Year	172	220	174	225
Plan Assets
Fair Value of Plan Assets, Beginning of Year	159	117	—	—
Plan Acquisition Upon the Arrangement (1)	—	32	—	—
Employer Contributions	16	9	8	3
Plan Participant Contributions	2	2	—	—
Benefits Paid	(10)	(13)	(8)	(3)
Interest Income (2)	4	3	—	—
Re-measurements:
Return on Plan Assets (Excluding Interest Income)	(26)	9	—	—
Exchange Rate Movements and Other	2	—	—	—
Fair Value of Plan Assets, End of Year	147	159	—	—
Pension and OPEB (Liability) (3)	(25)	(61)	(174)	(225)

(1)The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5.

(2)Based on the discount rate of the defined benefit obligation at the beginning of the year.

(3)Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities on the Consolidated Balance Sheets.

Summary of Pension and OPEB Costs

B) Pension and OPEB Costs

	Pension Benefits			OPEB
As at December 31,	2022	2021	2020	2022	2021	2020
Defined Benefit Plan Cost
Current Service Costs	16	16	13	8	9	1
Past Service Costs - Curtailments and Plan    Amendments	—	(1)	—	—	(3)	—
Net Interest Costs	3	3	3	7	6	—
Re-measurements:
Return on Plan Assets (Excluding    Interest Income)	26	(9)	(5)	—	—	—
(Gains) Losses From Experience    Adjustments	1	4	1	(2)	10	(2)
(Gains) Losses From Changes in    Demographic Assumptions	—	(1)	—	—	(3)	—
(Gains) Losses From Changes in Financial    Assumptions	(64)	(18)	15	(57)	(30)	1
Defined Benefit Plan Cost (Recovery)	(18)	(6)	27	(44)	(11)	—
Defined Contribution Plan Cost (1)	72	68	22	—	—	—
Total Plan Cost	54	62	49	(44)	(11)	—

(1)    Includes defined contribution and U.S. 401(k) plans.

Summary of Fair Value of the Plan Assets

2022 Target Allocation (percent)	Canadian Plan	U.S. Plan
Equity Funds	25% - 75%	21% - 51%
Fixed Income Funds	20% - 50%	55% - 74%
Real Estate Funds	—% - 15%	—	%
Listed Infrastructure Funds	—% - 10%	—	%
Emerging Market Debt Funds	—% - 10%	—	%
Cash and Cash Equivalents	—% - 10%	—	%

The fair value of the DB Pension Plan assets is:

As at December 31,	2022	2021
Equity Funds	68	77
Fixed Income Funds	50	54
Real Estate Funds	9	9
Listed Infrastructure Funds	7	8
Emerging Market Debt Funds	5	8
Cash and Cash Equivalents	7	2
Non-Invested Assets	1	1
Total Fair Value of DB Pension Plan Assets	147	159

Fair value of the cash and cash equivalents, equity, fixed income and listed infrastructure assets are based on the trading price of the underlying funds (Level 1). The fair value of the real estate funds reflects the appraisal valuation for each property investment (Level 2). The fair value of the non-invested assets is the discounted value of the expected future payments (Level 3).

The DB Pension Plan does not hold any direct investment in Cenovus common shares or preferred shares.

Summary of principal weighted average actuarial assumptions used to determine benefit obligations and expenses

The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:

	Pension Benefits						OPEB
For the years ended December 31,	2022		2021		2020		2022		2021		2020
Discount Rate	5.12	%	2.95	%	2.50	%	5.13	%	2.98	%	2.50	%
Future Salary Growth Rate	4.05	%	4.03	%	3.97	%	N/A		4.94	%	4.94	%
Average Longevity (years)	88.4		88.3		88.3		88.4		88.3		88.2
Health Care Cost Trend Rate	N/A		N/A		N/A		5.24	%	5.64	%	6.00	%

Sensitivity of defined benefit and OPEB obligation to changes in relevant actuarial assumptions

	2022		2021
As at December 31,	Increase	Decrease	Increase	Decrease
One Percent Change:
Discount Rate	(43)	51	(59)	76
Future Salary Growth Rate	3	(3)	4	(4)
Health Care Cost Trend Rate	19	(17)	26	(20)
One Year Change in Assumed Life Expectancy	10	(10)	4	(4)

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Share Capital and Warrants (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of classes of share capital [abstract]

Summary of Share Capital

B) Issued and Outstanding – Common Shares

	2022		2021
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	2,001,211	17,016	1,228,870	11,040
Issued Under the Arrangement, Net of Issuance Costs (Note 5)	—	—	788,518	6,111
Issued Upon Exercise of Warrants	9,399	93	314	3
Issued Under Stock Option Plans	11,069	170	535	7
Purchase of Common Shares under NCIBs	(112,489)	(959)	(17,026)	(145)
Outstanding, End of Year	1,909,190	16,320	2,001,211	17,016

Issued and Outstanding – Preferred Shares

For the year ended December 31, 2022, there were no preferred shares issued. As at December 31, 2022, there were 36 million preferred shares outstanding (December 31, 2021 – 36 million), with a carrying value of $519 million (December 31, 2021 – $519 million).

As at December 31, 2022	Dividend Reset Date	Dividend Rate		Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	%	10,740
Series 2 First Preferred Shares (1)	Quarterly	5.86	%	1,260
Series 3 First Preferred Shares	December 31, 2024	4.69	%	10,000
Series 5 First Preferred Shares	March 31, 2025	4.59	%	8,000
Series 7 First Preferred Shares	June 30, 2025	3.94	%	6,000

(1)The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June 30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 – 1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023.

Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such option to convert their shares into the other series.

Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1), 3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6) and 3.52 percent (series 8).

Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Second Preferred Shares

There were no second preferred shares outstanding as at December 31, 2022 (December 31, 2021 – nil).

Issued and Outstanding – Warrants

	2022		2021
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	65,119	215	—	—
Issued Under the Arrangement (Note 5)	—	—	65,433	216
Exercised	(9,399)	(31)	(314)	(1)
Outstanding, End of Year	55,720	184	65,119	215

	Retained Earnings Prior to Ovintiv Split	Stock-Based Compensation	Common Shares	Total
As at December 31, 2020	4,086	305	—	4,391
Stock-Based Compensation Expense	—	14	—	14
Purchase of Common Shares Under NCIBs	—	—	(120)	(120)
Common Shares Issued on Exercise of Stock Options	—	(1)	—	(1)
As at December 31, 2021	4,086	318	(120)	4,284
Stock-Based Compensation Expense	—	10	—	10
Purchase of Common Shares Under NCIBs	—	—	(1,571)	(1,571)
Common Shares Issued on Exercise of Stock Options	—	(32)	—	(32)
As at December 31, 2022	4,086	296	(1,691)	2,691

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Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract]

Summary of Accumulated Other Comprehensive Income (Loss)

	Pension and Other Post-Retirement Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
As at December 31, 2020	(10)	27	758	775
Other Comprehensive Income (Loss), Before Tax	47	—	(129)	(82)
Income Tax (Expense) Recovery	(9)	—	—	(9)
As at December 31, 2021	28	27	629	684
Other Comprehensive Income (Loss), Before Tax	96	2	713	811
Income Tax (Expense) Recovery	(25)	—	—	(25)
As at December 31, 2022	99	29	1,342	1,470

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Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of terms and conditions of share-based payment arrangement [abstract]

Summary of Assumptions Used to Determine Fair Value of Options Granted

The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	1.84	%
Expected Dividend Yield	0.72	%
Expected Volatility (1)	24.72	%
Expected Life (years)	5.75

(1)Expected volatility has been based on historical share volatility of the Company.

Summary of Options Outstanding and Exercisable

The following tables summarize information related to the NSRs:

	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
For the year ended December 31, 2022	(thousands)	($)
Outstanding, Beginning of Year	27,233	13.06
Granted	2,031	19.94
Exercised	(11,599)	12.77
Forfeited	(258)	9.75
Expired	(3,058)	22.25
Outstanding, End of Year	14,349	12.38

	Outstanding			Exercisable
As at December 31, 2022	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
Range of Exercise Price ($)	(thousands)	(Years)	($)	(thousands)	($)
5.00 to 9.99	5,234	4.88	8.76	1,474	8.94
10.00 to 14.99	6,229	3.80	12.01	4,280	12.13
15.00 to 19.99	2,834	4.26	19.71	919	19.36
20.00 to 24.99	52	6.69	22.37	—	—
	14,349	4.30	12.38	6,673	12.42

The following tables summarize the information related to the Cenovus replacement stock options:

	Number of Cenovus Replacement Stock Options	Weighted Average Exercise Price
For the year ended December 31, 2022	(thousands)	($)
Outstanding, Beginning of Year	12,256	15.21
Exercised	(6,145)	16.12
Forfeited	(186)	15.85
Expired	(2,458)	20.59
Outstanding, End of Year	3,467	9.99

	Outstanding			Exercisable
As at December 31, 2022	Number of Cenovus Replacement Stock Options	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Cenovus Replacement Stock Options	Weighted Average Exercise Price
Range of Exercise Price ($)	(thousands)	(Years)	($)	(thousands)	($)
3.00 to 4.99	2,065	1.63	3.54	742	3.54
5.00 to 9.99	124	1.36	6.06	59	6.06
10.00 to 14.99	14	0.47	12.88	14	12.88
15.00 to 19.99	594	1.04	18.35	594	18.35
20.00 to 24.99	524	0.20	21.77	524	21.77
25.00 to 29.99	146	0.58	27.88	146	27.88
	3,467	1.25	9.99	2,079	14.21

The following table summarizes the information related to the PSUs held by Cenovus employees:

	Number of Performance Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	7,163
Granted	3,226
Vested and Paid Out	(1,413)
Cancelled	(465)
Units in Lieu of Dividends	167
Outstanding, End of Year	8,678

The following table summarizes the information related to the RSUs held by Cenovus employees:

	Number of Restricted Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	6,025
Granted	3,161
Vested and Paid Out	(2,230)
Cancelled	(430)
Units in Lieu of Dividends	129
Outstanding, End of Year	6,655

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

	Number of Deferred Share Units
For the year ended December 31, 2022	(thousands)
Outstanding, Beginning of Year	1,256
Granted to Directors	161
Granted	316
Units in Lieu of Dividends	30
Redeemed	(257)
Outstanding, End of Year	1,506

Summary of Stock-Based Compensation

E) Total Stock-Based Compensation

For the years ended December 31,	2022	2021	2020
Stock Options With Associated Net Settlement Rights	15	14	11
Cenovus Replacement Stock Options	53	26	—
Performance Share Units	183	56	19
Restricted Share Units	100	48	23
Deferred Share Units	22	15	(4)
Stock-Based Compensation Expense (Recovery)	373	159	49
Stock-Based Compensation Costs Capitalized	—	8	16
Total Stock-Based Compensation	373	167	65

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Employee Salaries and Benefit Expenses (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure Of Salaries And Employee Benefits [Abstract]

Summary of Employee Salaries and Benefit Expenses

35. EMPLOYEE SALARIES AND BENEFIT EXPENSES

For the years ended December 31,	2022	2021	2020
Salaries, Bonuses and Other Short-Term Employee Benefits	1,246	1,327	605
Post-Employment Benefits	92	89	33
Stock-Based Compensation (Note 34)	373	159	49
Other Incentive Benefits (Recovery)	(9)	201	(4)
Termination Benefits	27	180	9
	1,729	1,956	692

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of transactions between related parties [abstract]

Summary of Key Management Compensation

Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is:

For the years ended December 31,	2022	2021	2020
Salaries, Director Fees and Other Short-Term Benefits	40	69	21
Post-Employment Benefits	4	4	3
Stock-Based Compensation	140	72	15
Other Incentive Benefits	—	4	1
Termination Benefits	3	3	6
	187	152	46

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Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure of detailed information about financial instruments [abstract]

Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets

	2022	2021
Fair Value, Beginning of Year	53	52
Acquisition (Note 5)	—	1
Changes in Fair Value (1)	2	—
Fair Value, End of Year	55	53

(1)     Changes in fair value are recorded in OCI.

Summary of Unrealized Risk Management Positions

Summary of Risk Management Positions

	2022			2021
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	2	40	(38)	46	116	(70)
Power Swap Contracts	1	7	(6)	—	—	—
Renewable Power Contracts	90	—	90	—	—	—
Foreign Exchange Rate Contracts	—	—	—	2	—	2
	93	47	46	48	116	(68)

Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value

As at December 31,	2022	2021
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(44)	(68)
Level 3 – Prices Sourced From Partially Observable Data	90	—
	46	(68)

Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities

	2022	2021
Fair Value of Contracts, Beginning of Year	(68)	(53)
Acquisition (Note 5)	—	(14)
Change in Fair Value of Contracts in Place at Beginning of Year	(5)	—
Change in Fair Value of Contracts Entered Into During the Year	(1,641)	(995)
Fair Value of Contracts Realized During the Year	1,762	993
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	(2)	1
Fair Value of Contracts, End of Year	46	(68)

Summary of Offsetting Risk Management Positions

	2022			2021
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	153	107	46	263	331	(68)
Amount Offset	(60)	(60)	—	(215)	(215)	—
Net Amount	93	47	46	48	116	(68)

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

As at December 31, 2022	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $10.00 per barrel	(68)	157
WTI Option Volatility	± ten percent	(1)	4
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility	± five percent	—	—

The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $5.00 per barrel	(45)	45

The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in the Canadian-U.S. dollar foreign exchange rate options would result in nominal unrealized gains (losses) to earnings before income tax.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at December 31, 2022	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	1	(1)
WCS and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	13	(13)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(1)	1
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
Natural Gas Basis Price	± US$0.50/MCF Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/Megawatt Hour Applied to Power Hedges	113	(113)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	14	(17)

(1)    Excludes WCS (Hardisty) differential.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00/bbl Applied to WTI, Condensate and Related Hedges	(225)	225
WCS and Condensate Differential Price	± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production	4	(4)
Refined Products Commodity Price	± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	11	(12)

In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

As at December 31,	2022	2021
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate	246	372
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate	(246)	(372)

Summary of Earnings Impact of (Gain) Loss from Risk Management Positions

D) Earnings Impact of (Gains) Losses From Risk Management Positions

For the years ended December 31,	2022	2021	2020
Realized (Gain) Loss	1,762	993	252
Unrealized (Gain) Loss (1)	(126)	2	56
(Gain) Loss on Risk Management	1,636	995	308

(1)     All WTI positions related to crude oil sales price risk management were closed by June 30, 2022. In the three months ended June 30, 2022, Cenovus recorded a realized net loss related to these positions of $467 million.

Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

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Risk Management (Tables)

12 Months Ended

Dec. 31, 2022

Risk Management [Abstract]

Net Fair Value of Risk Management Positions

Net Fair Value of Risk Management Positions

As at December 31, 2022	Notional Volumes (1)(2)	Terms (3)	Weighted Average Price (1) (2)	Fair Value Asset (Liability)
Futures Contracts Related to Blending (4)
WTI Fixed – Sell	3.2 MMbbls	January 2023 - June 2024	US$80.35/bbl	1
WTI Fixed – Buy	2.3 MMbbls	February 2023 - June 2024	US$79.93/bbl	—
Power Swap Contacts				(6)
Renewable Power Contracts				90
Other Financial Positions (5)				(39)
Total Fair Value				46

(1)    Million barrels (“MMbbls”). Barrel (“bbl”).

(2)    Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3)    Contract terms represent various individual contracts with different terms, and range from one month to eighteen months.

(4)    Condensate related futures contract positions consist of WTI contracts to help manage condensate price exposure.

(5)    Other financial positions consist of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, natural gas basis contracts and the Company’s U.S. manufacturing and marketing activities.

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

As at December 31, 2022	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $10.00 per barrel	(68)	157
WTI Option Volatility	± ten percent	(1)	4
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility	± five percent	—	—

The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $5.00 per barrel	(45)	45

The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in the Canadian-U.S. dollar foreign exchange rate options would result in nominal unrealized gains (losses) to earnings before income tax.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at December 31, 2022	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	1	(1)
WCS and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	13	(13)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(1)	1
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
Natural Gas Basis Price	± US$0.50/MCF Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/Megawatt Hour Applied to Power Hedges	113	(113)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	14	(17)

(1)    Excludes WCS (Hardisty) differential.

As at December 31, 2021	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00/bbl Applied to WTI, Condensate and Related Hedges	(225)	225
WCS and Condensate Differential Price	± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production	4	(4)
Refined Products Commodity Price	± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	11	(12)

In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

As at December 31,	2022	2021
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate	246	372
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate	(246)	(372)

Undiscounted Cash Outflows Relating to Financial Liabilities

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2022	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,124	—	—	—	6,124
Short-Term Borrowings (1)	115	—	—	—	115
Long-Term Debt (1)	401	983	2,014	11,196	14,594
Contingent Payments	271	167	—	—	438
Lease Liabilities (1)	426	746	596	2,889	4,657
As at December 31, 2021	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,353	—	—	—	6,353
Short-Term Borrowings (1)	79	—	—	—	79
Long-Term Debt (1)	561	1,608	2,603	14,892	19,664
Contingent Payments	238	—	—	—	238
Lease Liabilities (1)	453	794	634	3,192	5,073

(1)     Principal and interest, including current portion if applicable.

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Supplementary Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2022

Disclosure Of Supplementary Cash Flow Information [Abstract]

Disclosure Of Changes In Non-Cash Working Capital Items

A) Working Capital

As at December 31,	2022	2021
Total Current Assets	12,430	11,988
Total Current Liabilities	8,021	7,305
Working Capital	4,409	4,683

As at December 31, 2022, adjusted working capital was $4.7 billion (December 31, 2021 – $3.8 billion), excluding assets held for sale of $nil (December 31, 2021 – $1.3 billion), the current portion of the contingent payments of $263 million (December 31, 2021 – $236 million) and liabilities related to assets held for sale of $nil (December 31, 2021 – $186 million).

Changes in non-cash working capital is as follows:

For the years ended December 31,	2022	2021	2020
Accounts Receivable and Accrued Revenues	838	(953)	77
Income Tax Receivable	(58)	(1)	(12)
Inventories	(143)	(1,646)	450
Accounts Payable and Accrued Liabilities	(524)	1,645	(338)
Income Tax Payable	1,000	87	(17)
Total Change in Non-Cash Working Capital	1,113	(868)	160
Net Change in Non-Cash Working Capital – Operating Activities	575	(1,227)	198
Net Change in Non-Cash Working Capital – Investing Activities	538	359	(38)
Total Change in Non-Cash Working Capital	1,113	(868)	160

For the years ended December 31,	2022	2021	2020
Interest Paid	647	811	381
Interest Received	78	24	5
Income Taxes Paid	723	209	18

Summary of Reconciliation of Liabilities to Cash Flows from Financing Activities

	Dividends Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2019	—	—	6,699	1,916
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	117	—	—
(Repayment) of Revolving Long-Term Debt	—	—	(220)	—
Issuance of Long-Term Debt	—	—	1,326	—
(Repayment) of Long-Term Debt	—	—	(112)	—
Principal Repayment of Leases	—	—	—	(197)
Base Dividends Paid on Common Shares	(77)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	(25)	—
Finance Costs	—	—	5	—
Lease Additions	—	—	—	49
Lease Modifications	—	—	—	(2)
Lease Re-measurements	—	—	—	(2)
Lease Terminations	—	—	—	(1)
Base Dividends Declared on Common Shares	77	—	—	—
Exchange Rate Movements and Other	—	4	(232)	(6)
As at December 31, 2020	—	121	7,441	1,757

	Dividends Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2020	—	121	7,441	1,757
Acquisition (Note 5)	—	40	6,602	1,441
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	(77)	—	—
(Repayment) of Revolving Long-Term Debt	—	—	(350)	—
Issuance of Long-Term Debt	—	—	1,557	—
(Repayment) of Long-Term Debt	—	—	(2,870)	—
Principal Repayment of Leases	—	—	—	(300)
Base Dividends Paid on Common Shares	(176)	—	—	—
Dividends Paid on Preferred Shares	(34)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	121	—
Finance Costs	—	—	(59)	—
Lease Additions	—	—	—	110
Lease Modifications	—	—	—	22
Lease Re-measurements	—	—	—	(4)
Lease Termination	—	—	—	(1)
Transfers to Liabilities Related to Assets Held for Sale	—	—	—	(58)
Base Dividends Declared on Common Shares	176	—	—	—
Dividends Declared on Preferred Shares	34	—	—	—
Exchange Rate Movements and Other	—	(5)	(57)	(10)
As at December 31, 2021	—	79	12,385	2,957
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	34	—	—
(Repayment) of Long-Term Debt	—	—	(4,149)	—
Principal Repayment of Leases	—	—	—	(302)
Base Dividends Paid on Common Shares	(682)	—	—	—
Variable Dividends Paid on Common Shares	(219)	—	—	—
Dividends Paid on Preferred Shares	(26)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	(29)	—
Finance Costs	—	—	(28)	—
Lease Additions	—	—	—	25
Lease Modifications	—	—	—	83
Lease Re-measurements	—	—	—	7
Lease Terminations	—	—	—	(5)
Base Dividends Declared on Common Shares	682	—	—	—
Variable Dividends Declared on Common Shares	219	—	—	—
Dividends Declared on Preferred Shares	35	—	—	—
Exchange Rate Movements and Other	—	2	512	71
As at December 31, 2022	9	115	8,691	2,836

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2022

Commitments And Contingencies [Abstract]

Minimum Future Payments, Commitments And Contingent Liabilities

Future payments for the Company’s commitments are below:

As at December 31, 2022	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	1,747	2,011	1,542	1,416	1,360	13,005	21,081
Product Purchases	1,626	1,509	922	922	922	3,457	9,358
Real Estate (2)	48	50	50	50	54	604	856
Obligation to Fund Equity-Accounted Affiliate (3)	92	105	96	96	91	143	623
Other Long-Term Commitments (4)	381	90	75	74	65	395	1,080
Total Payments	3,894	3,765	2,685	2,558	2,492	17,604	32,998

As at December 31, 2021	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	1,677	1,958	1,853	1,488	1,350	13,244	21,570
Product Purchases (5)	1,684	1,682	1,593	731	731	4,204	10,625
Real Estate (2)	44	43	52	54	57	658	908
Obligation to Fund Equity-Accounted Affiliate (3)	68	85	99	90	90	210	642
Other Long-Term Commitments (4)	436	83	72	63	81	366	1,101
Total Payments	3,909	3,851	3,669	2,426	2,309	18,682	34,846

(1)    Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the commencement of the contract.

(2)    Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(3)    Relates to funding obligations for HCML.

(4)    Includes Cenovus’s proportionate share of the commitments related to WRB, Toledo and the Offshore segment.

(5)    Previously included in transportation and storage.

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Events after reporting period (Tables)

12 Months Ended

Dec. 31, 2022

Subsequent Events [Abstract]

Disclosure of detailed information about business combination

As at	August 31, 2022
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	9
Accounts Receivable and Accrued Revenues	164
Inventories	88
Property, Plant and Equipment	3,218
Accounts Payable and Accrued Liabilities	(313)
Income Tax Payable	(39)
Decommissioning Liabilities	(48)
Deferred Income Tax Liabilities	(486)
Total Identifiable Net Assets	2,593

As at	August 31, 2022
Cash, Net of Closing Adjustments	394
Bay Du Nord	40
Variable Payment	600
Total Consideration	1,034

As at	January 1, 2021
Consideration
Common Shares	6,111
Preferred Shares	519
Share Purchase Warrants	216
Replacement Stock Options	9
Other	17
Non-Controlling Interest	11
Total Consideration and Non-Controlling Interest	6,883
Identifiable Assets Acquired and Liabilities Assumed
Cash	735
Restricted Cash	164
Accounts Receivable and Accrued Revenues	1,307
Inventories	1,133
Exploration and Evaluation Assets	45
Property, Plant and Equipment	13,296
Right-of-Use Assets	1,132
Long-Term Income Tax Receivable	66
Other Assets	230
Investment in Equity-Accounted Affiliates	363
Deferred Income Tax Assets, Net	1,062
Accounts Payable and Accrued Liabilities	(2,283)
Income Tax Payable	(94)
Short-Term Borrowings	(40)
Long-Term Debt	(6,602)
Lease Liabilities	(1,441)
Decommissioning Liabilities	(2,697)
Other Liabilities	(782)
Total Identifiable Net Assets	5,594
Goodwill	1,289

XML

Description of Business and Segmented Disclosures - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) Customer	Dec. 31, 2021 CAD ($) Customer		Dec. 31, 2020 CAD ($) Customer
Disclosure of operating segments [line items]
Number of major customers | Customer	2	2		3
Gross Sales	$ 71,765	$ 48,811	[1]	$ 13,914	[1]
Customer One
Disclosure of operating segments [line items]
Gross Sales	16,100	8,500		4,300
Customer Two
Disclosure of operating segments [line items]
Gross Sales	$ 9,100	$ 6,800		1,800
Customer Three
Disclosure of operating segments [line items]
Gross Sales				$ 1,500
Bottom of range
Disclosure of operating segments [line items]
Percentage of entity's revenues from gross sales	10.00%

[1] See Note 3X for revisions to prior period results.

XML

Description of Business and Segmented Disclosures - Schedule of Segment and Operational Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Revenues
Gross Sales	$ 71,765	$ 48,811	[1]	$ 13,914	[1]
Less: Royalties	4,868	2,454	[1]	371	[1]
Revenues	66,897	46,357	[1]	13,543	[1]
Expenses
Purchased Product	33,801	23,326	[1]	5,681	[1]
Transportation and Blending	11,530	8,038	[1]	4,728	[1]
Operating	5,569	4,716	[1]	1,955	[1]
(Gain) Loss on Risk Management	1,636	995	[1]	308	[1]
Depreciation, Depletion and Amortization	4,679	5,886	[1]	3,464	[1]
Exploration Expense	101	18	[1]	91	[1]
(Income) Loss From Equity-Accounted Affiliates	(15)	(57)		0
Segment Income (Loss)	9,596	3,435		(2,684)
General and Administrative	865	849	[1]	292	[1]
Finance Costs	820	1,082	[1]	536	[1]
Interest Income	(81)	(23)	[1]	(9)	[1]
Integration and Transaction Costs	106	349	[1]	29	[1]
Foreign Exchange (Gain) Loss, Net	343	(174)	[1]	(181)	[1]
Revaluation (Gains)	(549)	0		0
Re-measurement of Contingent Payment	162	575	[1]	(80)	[1]
Gains (losses) on disposals of non-current assets	(269)	(229)	[1]	(81)	[1]
Other (Income) Loss, Net	(532)	(309)	[1]	40	[1]
Total Non-operating (Income) Expense	865	2,120		546
Earnings (Loss) Before Income Tax	8,731	1,315	[1]	(3,230)	[1]
Income Tax Expense (Recovery)	2,281	728	[1]	(851)	[1]
Net Earnings (Loss)	6,450	587	[1]	(2,379)	[1]
Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	1,762	993		252
Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	(126)	2		56
Upstream
Revenues
Gross Sales	41,127	27,844		9,708
Less: Royalties	4,868	2,454		371
Revenues	36,259	25,390		9,337
Expenses
Purchased Product	6,833	4,059		1,530
Transportation and Blending	12,194	8,714		4,764
Operating	3,789	3,241		1,476
Operating Margin	11,824	8,588		1,299
Depreciation, Depletion and Amortization	3,718	3,161		2,567
Exploration Expense	101	18		91
(Income) Loss From Equity-Accounted Affiliates	(15)	(52)		0
Segment Income (Loss)	8,075	5,442		(1,416)
Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	1,619	788		268
Upstream | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	(55)	19		57
Downstream
Revenues
Gross Sales	38,102	26,258		4,815
Less: Royalties	0	0		0
Revenues	38,102	26,258		4,815
Expenses
Purchased Product	32,501	23,111		4,429
Transportation and Blending	0	0		0
Operating	3,050	2,258		785
Operating Margin	2,439	785		(378)
Depreciation, Depletion and Amortization	848	2,607		736
Exploration Expense	0	0		0
(Income) Loss From Equity-Accounted Affiliates	0	0		0
Segment Income (Loss)	1,573	(1,823)		(1,113)
Downstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	112	104		(21)
Downstream | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	18	1		(1)
Oil Sands
Expenses
Purchased Product		2,404
Transportation and Blending		8,625
Oil Sands | Upstream
Revenues
Gross Sales	34,775	22,827		8,804
Less: Royalties	4,493	2,196		331
Revenues	30,282	20,631		8,473
Expenses
Purchased Product	4,810	2,404		1,262
Transportation and Blending	12,036	8,625		4,683
Operating	2,930	2,451		1,156
Operating Margin	8,979	6,365		1,104
Depreciation, Depletion and Amortization	2,763	2,666		1,687
Exploration Expense	9	16		9
(Income) Loss From Equity-Accounted Affiliates	8	(5)		0
Segment Income (Loss)	6,267	3,670		(649)
Oil Sands | Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	1,527	786		268
Oil Sands | Upstream | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	(68)	18		57
Conventional | Upstream
Revenues
Gross Sales	4,332	3,235		904
Less: Royalties	298	150		40
Revenues	4,034	3,085		864
Expenses
Purchased Product	2,023	1,655		268
Transportation and Blending	143	74		81
Operating	541	551		320
Operating Margin	1,235	803		195
Depreciation, Depletion and Amortization	370	3		880
Exploration Expense	1	(3)		82
(Income) Loss From Equity-Accounted Affiliates	0	0		0
Segment Income (Loss)	851	802		(767)
Conventional | Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	92	2		0
Conventional | Upstream | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	13	1		0
Offshore | Upstream
Revenues
Gross Sales	2,020	1,782		0
Less: Royalties	77	108		0
Revenues	1,943	1,674		0
Expenses
Purchased Product	0	0		0
Transportation and Blending	15	15		0
Operating	318	239		0
Operating Margin	1,610	1,420		0
Depreciation, Depletion and Amortization	585	492		0
Exploration Expense	91	5		0
(Income) Loss From Equity-Accounted Affiliates	(23)	(47)		0
Segment Income (Loss)	957	970		0
Offshore | Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	0	0		0
Offshore | Upstream | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	0	0		0
Canadian Manufacturing
Revenues
Gross Sales		6,215
Expenses
Purchased Product		5,156
Operating		486
Depreciation, Depletion and Amortization		226
Canadian Manufacturing | Downstream
Revenues
Gross Sales	7,792	6,215		82
Less: Royalties	0	0		0
Revenues	7,792	6,215		82
Expenses
Purchased Product	6,389	5,156		0
Transportation and Blending	0	0		0
Operating	704	486		37
Operating Margin	699	573		45
Depreciation, Depletion and Amortization	208	226		8
Exploration Expense	0	0		0
(Income) Loss From Equity-Accounted Affiliates	0	0		0
Segment Income (Loss)	491	347		37
Canadian Manufacturing | Downstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	0	0		0
Canadian Manufacturing | Downstream | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	0	0		0
U.S. Manufacturing | Downstream
Revenues
Gross Sales	30,310	20,043		4,733
Less: Royalties	0	0		0
Revenues	30,310	20,043		4,733
Expenses
Purchased Product	26,112	17,955		4,429
Transportation and Blending	0	0		0
Operating	2,346	1,772		748
Operating Margin	1,740	212		(423)
Depreciation, Depletion and Amortization	640	2,381		728
Exploration Expense	0	0		0
(Income) Loss From Equity-Accounted Affiliates	0	0
Segment Income (Loss)	1,082	(2,170)		(1,150)
U.S. Manufacturing | Downstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	112	104		(21)
U.S. Manufacturing | Downstream | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	18	1		(1)
Corporate and Eliminations
Revenues
Gross Sales	(7,464)	(5,291)		(609)
Less: Royalties	0	0		0
Revenues	(7,464)	(5,291)		(609)
Expenses
Purchased Product	(5,533)	(3,844)		(278)
Transportation and Blending	(664)	(676)		(36)
Operating	(1,270)	(783)		(306)
Depreciation, Depletion and Amortization	113	118		161
Exploration Expense	0	0		0
(Income) Loss From Equity-Accounted Affiliates	0	(5)		0
Segment Income (Loss)	(52)	(184)		(155)
General and Administrative	865	849		292
Finance Costs	820	1,082		536
Interest Income	(81)	(23)		(9)
Integration and Transaction Costs	106	349		29
Foreign Exchange (Gain) Loss, Net	343	(174)		(181)
Revaluation (Gains)	(549)	0		0
Re-measurement of Contingent Payment	162	575		(80)
Gains (losses) on disposals of non-current assets	(269)	(229)		(81)
Other (Income) Loss, Net	(532)	(309)		40
Total Non-operating (Income) Expense	865	2,120		546
Corporate and Eliminations | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	31	101		5
Corporate and Eliminations | Unrealized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	$ (89)	$ (18)		$ 0

[1] See Note 3X for revisions to prior period results.

XML

Description of Business and Segmented Disclosures - Schedule of Revenues by Product (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
U.S. Manufacturing
Consolidated	$ 66,897	$ 46,357	[1]	$ 13,543	[1]
Corporate and Eliminations
U.S. Manufacturing
Corporate and Eliminations	(7,464)	(5,291)		(609)
Consolidated	(7,464)	(5,291)		(609)
Upstream
Upstream
Crude Oil (1)	29,834	19,877		8,017
NGLs (1)	2,346	1,983		727
Natural Gas	3,690	3,032		535
Other	389	498		58
Downstream | Canadian Manufacturing
Canadian Manufacturing
Asphalt	620	477		0
Other Products	4,812	3,787		82
U.S. Manufacturing
Other Products	4,812	3,787		82
Downstream | Canadian Manufacturing | Synthetic Oil
Canadian Manufacturing
Synthetic Crude Oil and Diesel and Distillate	2,360	1,951		0
U.S. Manufacturing
Diesel and Distillate	2,360	1,951		0
Downstream | U.S. Manufacturing
Canadian Manufacturing
Synthetic Crude Oil and Diesel and Distillate	11,453	6,429		1,569
Other Products	4,741	3,503		812
U.S. Manufacturing
Gasoline	14,116	10,111		2,352
Diesel and Distillate	11,453	6,429		1,569
Other Products	$ 4,741	$ 3,503		$ 812

[1] See Note 3X for revisions to prior period results.

XML

Description of Business and Segmented Disclosures - Schedule of Geographical Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Disclosure of geographical areas [line items]
Revenue	$ 66,897	$ 46,357	[1]	$ 13,543	[1]
Non-Current Assets	42,447	40,968
Assets held for sale, included in total assets, divested	1,300
Canada
Disclosure of geographical areas [line items]
Revenue	33,222	23,768		8,715
Non-Current Assets	35,194	33,981
Assets held for sale, included in total assets, divested	1,300
United States
Disclosure of geographical areas [line items]
Revenue	32,313	21,326		4,828
Non-Current Assets	4,824	4,093
China
Disclosure of geographical areas [line items]
Revenue	1,362	1,263		$ 0
Non-Current Assets	2,064	2,583
Indonesia
Disclosure of geographical areas [line items]
Non-Current Assets	$ 365	$ 311

[1] See Note 3X for revisions to prior period results.

XML

Description of Business and Segmented Disclosures - Schedule of Assets by Segment (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure Of Reportable Segments [Line Items]
E&E Assets	$ 685	$ 720
PP&E	36,499	34,225	$ 25,411
ROU Assets	1,845	2,010	1,139
Goodwill	2,923	3,473	$ 2,272
Total Assets	55,869	54,104
Total Current Assets	12,430	11,988
Assets held for sale, included in total assets, divested	1,300
Canada
Disclosure Of Reportable Segments [Line Items]
Assets held for sale, included in total assets, divested	1,300
Oil Sands
Disclosure Of Reportable Segments [Line Items]
E&E Assets	674	653
PP&E	24,657	22,535
ROU Assets	638	754
Goodwill	2,923	3,473
Total Assets	32,248	31,070
Conventional
Disclosure Of Reportable Segments [Line Items]
E&E Assets	6	6
PP&E	2,020	2,174
ROU Assets	2	2
Goodwill	0	0
Total Assets	2,410	3,026
Offshore
Disclosure Of Reportable Segments [Line Items]
E&E Assets	5	61
PP&E	2,549	2,822
ROU Assets	152	160
Goodwill	0	0
Total Assets	3,339	3,597
Canadian Manufacturing
Disclosure Of Reportable Segments [Line Items]
E&E Assets	0	0
PP&E	2,466	2,558
ROU Assets	252	388
Goodwill	0	0
Total Assets	3,172	3,884
U.S. Manufacturing
Disclosure Of Reportable Segments [Line Items]
E&E Assets	0	0
PP&E	4,482	3,745
ROU Assets	329	252
Goodwill	0	0
Total Assets	8,324	7,509
Corporate and Eliminations
Disclosure Of Reportable Segments [Line Items]
E&E Assets	0	0
PP&E	325	391
ROU Assets	472	454
Goodwill	0	0
Total Assets	$ 6,376	$ 5,018

XML

Description of Business and Segmented Disclosures - Schedule of Capital Expenditures (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Aug. 31, 2022
Disclosure Of Reportable Segments [Line Items]
Capital Investment	$ 3,708	$ 2,563	$ 841
Acquisitions (Note 5)	1,621	13,432	18
Total Capital Expenditures	5,329	15,995	859
Sunrise Oil Sands Partnership
Disclosure Of Reportable Segments [Line Items]
Investment in Equity-Accounted Affiliates				$ 1,559
Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	2,446	1,416	505
Upstream | Asia Pacific
Disclosure Of Reportable Segments [Line Items]
Capital Investment	8	21	0
Upstream | Atlantic
Disclosure Of Reportable Segments [Line Items]
Capital Investment	302	154	0
Downstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	1,176	1,063	276
Oil Sands
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 5)	1,609	5,005	6
Oil Sands | Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	1,792	1,019	427
Conventional
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 5)	12	551	12
Conventional | Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	344	222	78
Offshore
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 5)	0	3,129	0
Canadian Manufacturing
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 5)	0	2,973	0
Canadian Manufacturing | Downstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	117	68	33
U.S. Manufacturing
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 5)	0	1,618	0
U.S. Manufacturing | Downstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	1,059	995	243
Corporate and Eliminations
Disclosure Of Reportable Segments [Line Items]
Capital Investment	86	84	60
Acquisitions (Note 5)	$ 0	$ 156	$ 0

XML

Summary of Significant Accounting Policies - Additional information (Detail)	12 Months Ended
	Dec. 31, 2022
Information technology assets
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	3 years
Land improvements and buildings | Bottom of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	15 years
Land improvements and buildings | Top of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	40 years
Office improvements and buildings | Bottom of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	3 years
Office improvements and buildings | Top of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	15 years
Refining equipment | Bottom of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	10 years
Refining equipment | Top of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	60 years
Other | Bottom of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	3 years
Other | Top of range
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Useful life measured as period of time, property, plant and equipment	60 years

XML

Summary of Significant Accounting Policies - Revisions to Prior Periods (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales	$ 71,765	$ 48,811	[1]	$ 13,914	[1]
Purchased Product	33,801	23,326	[1]	5,681	[1]
Operating	5,569	4,716	[1]	1,955	[1]
Transportation and Blending	11,530	8,038	[1]	4,728	[1]
Depreciation, Depletion and Amortization	4,679	5,886	[1]	3,464	[1]
Purchased Product, Transportation and Blending		31,364
Oil Sands
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Purchased Product		2,404
Transportation and Blending		8,625
Purchased Product, Transportation and Blending		11,029
Canadian Manufacturing
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		6,215
Purchased Product		5,156
Operating		486
Depreciation, Depletion and Amortization		226
Gross sales less purchased product		347
Retail
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		0
Purchased Product		0
Operating		0
Depreciation, Depletion and Amortization		0
Gross sales less purchased product		0
Corporate and Eliminations
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales	(7,464)	(5,291)		(609)
Purchased Product	(5,533)	(3,844)		(278)
Operating	(1,270)	(783)		(306)
Transportation and Blending	(664)	(676)		(36)
Depreciation, Depletion and Amortization	$ 113	118		$ 161
Gross sales less purchased product		(771)
Previously Reported
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Purchased Product		23,481
Transportation and Blending		7,883
Purchased Product, Transportation and Blending		31,364
Previously Reported | Oil Sands
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Purchased Product		3,188
Transportation and Blending		7,841
Purchased Product, Transportation and Blending		11,029
Previously Reported | Canadian Manufacturing
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		4,472
Purchased Product		3,552
Operating		388
Depreciation, Depletion and Amortization		167
Gross sales less purchased product		365
Previously Reported | Retail
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		2,158
Purchased Product		2,019
Operating		98
Depreciation, Depletion and Amortization		59
Gross sales less purchased product		(18)
Previously Reported | Corporate and Eliminations
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		(5,706)
Purchased Product		(4,888)
Transportation and Blending		(47)
Gross sales less purchased product		(771)
Revisions
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Purchased Product		(155)
Transportation and Blending		155
Purchased Product, Transportation and Blending		0
Revisions | Oil Sands
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Purchased Product		(784)
Transportation and Blending		784
Purchased Product, Transportation and Blending		0
Revisions | Canadian Manufacturing
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		0
Purchased Product		0
Operating		0
Depreciation, Depletion and Amortization		0
Gross sales less purchased product		0
Revisions | Retail
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		0
Purchased Product		0
Operating		0
Depreciation, Depletion and Amortization		0
Gross sales less purchased product		0
Revisions | Corporate and Eliminations
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		0
Purchased Product		629
Transportation and Blending		(629)
Gross sales less purchased product		0
Segment Aggregation
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Purchased Product		0
Transportation and Blending		0
Purchased Product, Transportation and Blending		0
Segment Aggregation | Oil Sands
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Purchased Product		0
Transportation and Blending		0
Purchased Product, Transportation and Blending		0
Segment Aggregation | Canadian Manufacturing
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		1,743
Purchased Product		1,604
Operating		98
Depreciation, Depletion and Amortization		59
Gross sales less purchased product		(18)
Segment Aggregation | Retail
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		(2,158)
Purchased Product		(2,019)
Operating		(98)
Depreciation, Depletion and Amortization		(59)
Gross sales less purchased product		18
Segment Aggregation | Corporate and Eliminations
Disclosure Of Summary Of Significant Accounting Policies [Line Items]
Gross Sales		415
Purchased Product		415
Transportation and Blending		0
Gross sales less purchased product		$ 0

[1] See Note 3X for revisions to prior period results.

XML

Critical Accounting Judgments and Key Sources of Estimation Uncertainty - Additional Information (Detail)		8 Months Ended	12 Months Ended
	Jun. 13, 2022	Aug. 30, 2022	Dec. 31, 2022
WRB Refining LP
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation			50.00%
BP-Husky Refining LLC
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation			50.00%
Sunrise Oil Sands Partnership
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	35.00%	50.00%

XML

Acquisitions - Sunrise Oil Sands Partnership Narrative (Details) $ in Millions			8 Months Ended		12 Months Ended
	Aug. 31, 2022 CAD ($) $ / bbl	Jun. 13, 2022 CAD ($)	Aug. 31, 2022 CAD ($) $ / bbl	Aug. 30, 2022	Dec. 31, 2022 CAD ($)
Disclosure of detailed information about business combination [line items]
Revenue of acquiree since acquisition date					$ 599.0
Profit (loss) of acquiree since acquisition date					0.0
Revenue of combined entity as if combination occurred at beginning of period					67,800.0
Profit (loss) of combined entity as if combination occurred at beginning of period					6,600.0
Sunrise Oil Sands Partnership
Disclosure of detailed information about business combination [line items]
Proportion of ownership interest in joint operation		35.00%		50.00%
Sunrise Oil Sands Partnership
Disclosure of detailed information about business combination [line items]
Agreement to purchase remaining ownership	50.00%
Measurement period adjustments recognised for particular assets, liabilities, non-controlling interests or items of consideration					26.0
Fair value of accounts receivable and accrued revenues recognised as of acquisition date	$ 164.0		$ 164.0
Gross cash transferred in acquisition	600.0		600.0
Initial Recognition	$ 600.0	$ 600.0	600.0
Gain (loss) recognised as result of remeasuring to fair value equity interest in acquiree held by acquirer before business combination			$ 40.0
Contingent consideration, price per barrel (in dollars per share) | $ / bbl	52.00		52.00
Contingent consideration, quarterly payment	$ 2.8		$ 2.8
Initial Recognition	600.0		600.0
Investment in Equity-Accounted Affiliates	1,559.0		1,559.0
Carrying value of investment in joint ventures recognised​ as of​ acquisition​ date	$ 960.0		$ 960.0
Non-cash revaluation gain, before tax					599.0
Non-cash revaluation gain, after tax					$ 457.0
Sunrise Oil Sands Partnership | Bottom of range
Disclosure of detailed information about business combination [line items]
Contingent consideration, price per barrel (in dollars per share) | $ / bbl	52.00		52.00
Sunrise Oil Sands Partnership | Top of range
Disclosure of detailed information about business combination [line items]
Contingent consideration, price per barrel (in dollars per share) | $ / bbl	53.00		53.00

XML

Acquisitions - Sunrise Oil Sands Partnership, Assets Acquired and Liabilities Acquired (Details) - Sunrise Oil Sands Partnership $ in Millions	Aug. 31, 2022 CAD ($)
Disclosure of detailed information about business combination [line items]
Cash	$ 9
Accounts Receivable and Accrued Revenues	164
Inventories	88
Property, Plant and Equipment	3,218
Accounts Payable and Accrued Liabilities	(313)
Income Tax Payable	(39)
Decommissioning Liabilities	(48)
Deferred Income Tax Liabilities	(486)
Total Identifiable Net Assets	$ 2,593

XML

Acquisitions - Sunrise Oil Sands Partnership, Summary of Consideration (Details) - Sunrise Oil Sands Partnership - CAD ($) $ in Millions	Aug. 31, 2022	Jun. 13, 2022
Disclosure of detailed information about business combination [line items]
Cash transferred	$ 394
Acquisition-date fair value of equity interest in acquiree held by acquirer immediately before acquisition date	40
Initial Recognition	600	$ 600
Consideration transferred	$ 1,034

XML

Acquisitions - Sunrise Oil Sands Partnership, Summary of Goodwill (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Aug. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about business combination [line items]
Goodwill	$ 2,923		$ 3,473	$ 2,272
Sunrise Oil Sands Partnership
Disclosure of detailed information about business combination [line items]
Consideration transferred, acquisition-date fair value		$ 1,034
Investment in Equity-Accounted Affiliates		1,559
Total Identifiable Net Assets		(2,593)
Goodwill		$ 0

XML

Acquisitions - BP - Refining LLC (Details) - BP-Husky Refining LLC - USD ($) $ in Millions		12 Months Ended
	Aug. 08, 2022	Dec. 31, 2022
Disclosure of detailed information about business combination [line items]
Agreement to purchase remaining ownership	50.00%	50.00%
Purchase of oil and gas assets	$ 300

XML

Acquisitions - Husky Energy, Summary of Consideration and Goodwill (Details) - Husky Energy, Inc. $ in Millions	Jan. 01, 2021 CAD ($)
Disclosure of detailed information about business combination [line items]
Non-controlling interest in acquiree recognised at acquisition date	$ 11
Consideration transferred, acquisition-date fair value	6,883
Cash	735
Restricted Cash	164
Accounts Payable and Accrued Liabilities	1,307
Inventories	1,133
Exploration and Evaluation Assets	45
Property, Plant and Equipment	13,296
Right-of-Use Assets	1,132
Long-Term Income Tax Receivable	66
Other Assets	230
Investment in Equity-Accounted Affiliates	363
Deferred Income Tax Assets, Net	1,062
Accounts Payable and Accrued Liabilities	(2,283)
Income Tax Payable	(94)
Short-Term Borrowings	(40)
Long-Term Debt	(6,602)
Lease Liabilities	(1,441)
Decommissioning Liabilities	(2,697)
Other Liabilities	(782)
Total Identifiable Net Assets	5,594
Goodwill recognised as of acquisition date	1,289
Common Shares
Disclosure of detailed information about business combination [line items]
Equity interests of acquirer	6,111
Preference shares
Disclosure of detailed information about business combination [line items]
Equity interests of acquirer	519
Common Share Warrants
Disclosure of detailed information about business combination [line items]
Equity interests of acquirer	216
Cenovus Replacement Stock Options
Disclosure of detailed information about business combination [line items]
Equity interests of acquirer	9
Equity Interest Type, Other
Disclosure of detailed information about business combination [line items]
Equity interests of acquirer	$ 17

XML

Acquisitions - Husky Energy Inc. Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Jan. 01, 2021	Dec. 31, 2020
Disclosure of detailed information about business combination [line items]
Goodwill	$ 2,923	$ 3,473		$ 2,272
Non-current assets held for sale
Disclosure of detailed information about business combination [line items]
Goodwill		88
Oil Sands
Disclosure of detailed information about business combination [line items]
Goodwill	2,923	3,473
Sunrise
Disclosure of detailed information about business combination [line items]
Goodwill	$ 0	$ 550
Husky Energy, Inc.
Disclosure of detailed information about business combination [line items]
Goodwill recognised as of acquisition date			$ 1,289
Husky Energy, Inc. | Lloydminister Thermal | Oil Sands
Disclosure of detailed information about business combination [line items]
Goodwill			651
Husky Energy, Inc. | Sunrise | Oil Sands
Disclosure of detailed information about business combination [line items]
Goodwill			550
Husky Energy, Inc. | Tucker | Oil Sands
Disclosure of detailed information about business combination [line items]
Goodwill			$ 88

XML

Acquisitions - Terra Nova Narrative (Details) - Terra Nova - CAD ($) $ in Millions	Dec. 31, 2022	Sep. 08, 2021
Disclosure of detailed information about business combination [line items]
Percentage of working interest acquired		2100.00%
Working interest, percentage	3400.00%
Consideration paid for working interest in asset acquisition		$ 3
Cash acquired in asset acquisition		78
Property, plant and equipment acquired in asset acquisition		84
Decommissioning liabilities assumed in asset acquisition		$ 159

XML

General and Administrative - Summary of General and Administrative Expenses (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
General And Administrative Expenses [Abstract]
Salaries and Benefits	$ 204	$ 264		$ 145
Administrative and Other	297	225		102
Stock-Based Compensation Expense (Recovery) (Note 34)	373	159		49
Other Incentive Benefits Expense (Recovery)	(9)	201		(4)
General and Administrative Expenses	$ 865	$ 849	[1]	$ 292	[1]

[1] See Note 3X for revisions to prior period results.

XML

Finance Costs - Schedule of Finance Costs (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Finance Costs [Abstract]
Interest Expense – Short-Term Borrowings and Long-Term Debt	$ 478	$ 557		$ 392
Net Premium (Discount) on Redemption of Long-Term Debt	(29)	121		(25)
Interest Expense – Lease Liabilities (Note 27)	163	171		87
Unwinding of Discount on Decommissioning Liabilities (Note 29)	176	199		57
Other	37	34		25
Total finance costs excluding capitalized interest	825	1,082		536
Capitalized Interest	(5)	0		0
Finance Costs	$ 820	$ 1,082	[1]	$ 536	[1]

[1] See Note 3X for revisions to prior period results.

XML

Integration and Transaction Costs (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Disclosure of detailed information about business combination [line items]
Integration and Transaction Costs	$ 106	$ 349	[1]	$ 29	[1]
Husky Energy, Inc.
Disclosure of detailed information about business combination [line items]
Integration and Transaction Costs	90	$ 349		$ 29
Sunrise Oil Sands Partnership And Toledo CGU
Disclosure of detailed information about business combination [line items]
Acquisition-related costs for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination	$ 16

[1] See Note 3X for revisions to prior period results.

XML

Foreign Exchange (Gain) Loss, Net - Schedule of Foreign Exchange Gain Loss Net (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items]
Unrealized Foreign Exchange (Gain) Loss	$ 365	$ (312)		$ (131)
Realized Foreign Exchange (Gain) Loss	(22)	138		(50)
Total	343	(174)	[1]	(181)	[1]
U.S. Dollar Debt Issued From Canada
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items]
Unrealized Foreign Exchange (Gain) Loss	365	(230)		(194)
Other
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items]
Unrealized Foreign Exchange (Gain) Loss	$ 0	$ (82)		$ 63

[1] See Note 3X for revisions to prior period results.

XML

Divestitures (Details) shares in Millions, $ in Millions									1 Months Ended	2 Months Ended	3 Months Ended	12 Months Ended
	Sep. 13, 2022 CAD ($) gasStation	Jun. 08, 2022 CAD ($)	May 31, 2022 CAD ($)	Feb. 28, 2022 CAD ($)	Jan. 31, 2022 CAD ($)	Oct. 14, 2021 CAD ($) shares	May 01, 2021 CAD ($)	Dec. 02, 2020 CAD ($) shares	Sep. 30, 2021 CAD ($)	Aug. 31, 2021 CAD ($)	Sep. 30, 2021 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	[1]	Dec. 31, 2020 CAD ($)	[1]
Disclosure of analysis of single amount of discontinued operations [line items]
Before-tax gain (loss) on disposal												$ 269	$ 229		$ 81
Retail
Disclosure of analysis of single amount of discontinued operations [line items]
Before-tax gain (loss) on disposal	$ (74)
After-tax gain (loss) on disposal	$ (56)
Number of stores sold | gasStation	337
Consideration for sale of assets held for sale	$ 404
White Rose Field
Disclosure of analysis of single amount of discontinued operations [line items]
Before-tax gain (loss) on disposal									$ 62
After-tax gain (loss) on disposal									$ 47
Percentage of working interest acquired									12.50%		12.50%
Payment to transfer working interest			$ 50
Wembley
Disclosure of analysis of single amount of discontinued operations [line items]
Proceeds from disposal of oil and gas assets				$ 221
Before-tax gain (loss) on disposal				76
After-tax gain (loss) on disposal				$ 58
Tucker
Disclosure of analysis of single amount of discontinued operations [line items]
Proceeds from disposal of oil and gas assets					$ 730
Before-tax gain (loss) on disposal					165
After-tax gain (loss) on disposal					$ 126
Headwater Exploration Inc.
Disclosure of analysis of single amount of discontinued operations [line items]
Proceeds from disposal of oil and gas assets		$ 110
Headwater Exploration Inc.
Disclosure of analysis of single amount of discontinued operations [line items]
Before-tax gain (loss) on disposal						$ 116
After-tax gain (loss) on disposal						$ 99
Sale of common shares in equity method investment | shares						50
Proceeds from sales of investment in equity-accounted affiliate						$ 228
Marten Hills, Alberta
Disclosure of analysis of single amount of discontinued operations [line items]
Proceeds from disposal of oil and gas assets							$ 102
Before-tax gain (loss) on disposal							60
After-tax gain (loss) on disposal							$ 47
Marten Hills, Alberta | Marten Hills
Disclosure of analysis of single amount of discontinued operations [line items]
Proceeds from disposal of oil and gas assets								$ 33
Before-tax gain (loss) on disposal								79
After-tax gain (loss) on disposal								65
Consideration received for sale of operating assets								$ 138
Consideration received for sale of operating assets, common stock (in shares) | shares								50
Consideration received for sale of operating assets, common stock								$ 97
Consideration received for sale of operating assets, purchase warrants (in shares) | shares								15
Consideration received for sale of operating assets, purchase warrants								$ 8
East Clearwater and Kaybob
Disclosure of analysis of single amount of discontinued operations [line items]
Proceeds from disposal of oil and gas assets										$ 82
Before-tax gain (loss) on disposal											$ 17
After-tax gain (loss) on disposal											$ 13

[1] See Note 3X for revisions to prior period results.

XML

Impairment Charges and Reversals - Additional Information (Detail)		3 Months Ended	9 Months Ended	12 Months Ended
	Aug. 08, 2022	Mar. 31, 2020 CAD ($)	Sep. 30, 2020 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Goodwill impairments				$ 0	$ 0
BP-Husky Refining LLC
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Agreement to purchase remaining ownership	50.00%			50.00%
Discounted future cash flows
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets			0.10
Discounted future cash flows | Discount rate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.01	0.01	0.01
Discounted future cash flows | Forward Price Estimate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.05	0.05	0.05
Discounted future cash flows | Minimum
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets						0.10
Discounted future cash flows | Minimum | Discount rate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.14	0.10
Discounted future cash flows | Maximum
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets						0.15
Discounted future cash flows | Maximum | Discount rate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.15	0.15
Upstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments				$ 0	$ 0
Downstream | Discounted future cash flows | Minimum
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.15	0.10
Downstream | Discounted future cash flows | Maximum
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.18	0.12
Downstream | Growth rate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.02	0.02	0.02
Conventional
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments						$ 555,000,000
Reversal of impairment loss recognised in profit or loss					$ 378,000,000
U.S. Manufacturing | Downstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Recoverable Amount				$ 5,400,000,000
Clearwater, Elmworth-Wapiti and Kaybob-Edson
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Recoverable Amount					$ 2,000,000,000
Clearwater, Elmworth-Wapiti and Kaybob-Edson | Discounted future cash flows | Discount rate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets					0.01
Clearwater, Elmworth-Wapiti and Kaybob-Edson | Discounted future cash flows | Forward Price Estimate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets					0.05
CGUs | Conventional | Upstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments		$ 315,000,000				$ 240,000,000
Borger, Wood River, and Lima CGUs | Downstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments					$ 1,900,000,000
Recoverable Amount					$ 2,500,000,000
Impairment Reversals (Note 11)				1,200,000,000
Borger CGU | Downstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Recoverable Amount			$ 692,000,000
Borger CGU | U.S. Manufacturing | Downstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments			450,000,000
Wood River CGU | Downstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Goodwill impairments			$ 0
Superior and Toledo CGU | Downstream
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments				$ 1,500,000,000
Sunrise | Discounted future cash flows | Discount rate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.01
Sunrise | Discounted future cash flows | Forward Price Estimate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Significant unobservable input, assets				0.05
Sunrise | Upstream | Discount rate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments				$ 69,000,000
Sunrise | Upstream | Forward Price Estimate
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
CGU Impairments				$ 226,000,000

XML

Impairment Charges and Reversals - Summary of Impairment Losses and Estimated Recoverable Amounts (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Clearwater
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Reversal of impairment loss recognised in profit or loss	$ 145
Recoverable Amount	427	$ 160
CGU Impairments		260
Elmworth-Wapiti
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Reversal of impairment loss recognised in profit or loss	115
Recoverable Amount	747	259
CGU Impairments		120
Kaybob-Edson
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Reversal of impairment loss recognised in profit or loss	118
Recoverable Amount	$ 837	384
CGU Impairments		$ 175

XML

Impairment Charges and Reversals - Forward Price Assumptions (Details) BTU in Millions	12 Months Ended
	Dec. 31, 2022 $ / bbl $ / bbl $ / Mcf BTU	Dec. 31, 2021 $ / bbl $ / Mcf $ / bbl BTU	Dec. 31, 2020 $ / bbl $ / bbl $ / Mcf BTU
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Gas Heating Value | BTU	1	1	1
West Texas Intermediate | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	80.33	72.83	47.17
West Texas Intermediate | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	78.50	68.78	50.17
West Texas Intermediate | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	76.95	66.76	53.17
West Texas Intermediate | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	77.61	68.09	54.97
West Texas Intermediate | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	79.16	69.45	56.07
West Texas Intermediate | Thereafter
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Forward price, average annual increase	2.00%	2.00%	2.00%
Western Canada Select | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	76.54	74.43	44.63
Western Canada Select | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	77.75	69.17	48.18
Western Canada Select | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	77.55	66.54	52.10
Western Canada Select | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	80.07	67.87	54.10
Western Canada Select | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	81.89	69.23	55.19
Western Canada Select | Thereafter
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Forward price, average annual increase	2.00%	2.00%	2.00%
Edmonton C5+ | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	106.22	91.85	59.24
Edmonton C5+ | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	101.35	85.53	63.19
Edmonton C5+ | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	98.94	82.98	67.34
Edmonton C5+ | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	100.19	84.63	69.77
Edmonton C5+ | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal	101.74	86.33	71.18
Edmonton C5+ | Thereafter
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Forward price, average annual increase	2.00%	2.00%	2.00%
Alberta Energy Company Natural Gas | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal | $ / Mcf	4.23	3.56	2.88
Alberta Energy Company Natural Gas | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal | $ / Mcf	4.40	3.20	2.80
Alberta Energy Company Natural Gas | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal | $ / Mcf	4.21	3.05	2.71
Alberta Energy Company Natural Gas | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal | $ / Mcf	4.27	3.10	2.75
Alberta Energy Company Natural Gas | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used In Current Measurement Of Fair Value Less Costs Of Disposal | $ / Mcf	4.34	3.17	2.80
Alberta Energy Company Natural Gas | Thereafter
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Forward price, average annual increase	2.00%	2.00%	2.00%

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Impairment Charges and Reversals - Sensitivity (Details) - CAD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Clearwater
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Increase through change in discount rate, impairments				$ 7
Decrease through change in discount rate, impairments				(7)
Five percent increase through change in forward price estimates, Impairments				(68)
Five percent decrease through change in forward price estimates, Impairments				128
Elmworth-Wapiti
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Increase through change in discount rate, impairments				10
Decrease through change in discount rate, impairments				(10)
Five percent increase through change in forward price estimates, Impairments				(71)
Five percent decrease through change in forward price estimates, Impairments				126
Kaybob-Edson
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Increase through change in discount rate, impairments				17
Decrease through change in discount rate, impairments				(19)
Five percent increase through change in forward price estimates, Impairments				(71)
Five percent decrease through change in forward price estimates, Impairments				$ 140
Borger, Wood River, and Lima CGUs
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Increase through change in discount rate, impairments		$ 69	$ 251
Decrease through change in discount rate, impairments		(65)	(283)
Five percent increase through change in forward price estimates, Impairments		(268)	(990)
Five percent decrease through change in forward price estimates, Impairments		268	$ 996
One percent increase through change in discount rate, impairment reversal		(72)
One percent decrease through change in discount rate, impairment reversal		14
Five percent increase through change in forward price estimates, impairment reversal		168
Five percent decrease through change in forward price estimates, impairment reversal		$ (342)
Borger CGU
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Increase through change in discount rate, impairments	$ 89
Decrease through change in discount rate, impairments	(110)
Five percent increase through change in forward price estimates, Impairments	(348)
Five percent decrease through change in forward price estimates, Impairments	$ 342

XML

Impairment Charges and Reversals - Crude Oil and Forward Crack Spreads (Details)	Dec. 31, 2022 $ / bbl	Dec. 31, 2021 $ / bbl	Sep. 30, 2020 $ / barrel
West Texas Intermediate | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	80.33
West Texas Intermediate | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	78.50
West Texas Intermediate | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	76.95
West Texas Intermediate | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	77.61
West Texas Intermediate | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	79.16
West Texas Intermediate | Not later than two years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		68.78	36.36
West Texas Intermediate | Not later than two years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		72.83	50.84
West Texas Intermediate | Later than two years and not later than four years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		66.76	49.66
West Texas Intermediate | Later than two years and not later than four years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		69.45	58.74
WTI-WTS | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(0.56)
WTI-WTS | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(0.56)
WTI-WTS | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(0.56)
WTI-WTS | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(0.56)
WTI-WTS | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(0.56)
WTI-WTS | Not later than two years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		0	0.37
WTI-WTS | Not later than two years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		0.01	1.73
WTI-WTS | Later than two years and not later than four years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		(0.06)	1.21
WTI-WTS | Later than two years and not later than four years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		(0.06)	1.81
WTI-WCS | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(23.32)
WTI-WCS | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(19.09)
WTI-WCS | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(17.42)
WTI-WCS | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(15.87)
WTI-WCS | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	(15.74)
WTI-WCS | Not later than two years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		13.54
WTI-WCS | Not later than two years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		13.67
WTI-WCS | Later than two years and not later than four years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		13.75
WTI-WCS | Later than two years and not later than four years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		14.30
Chicago 3-2-1 Crack Spreads (WTI) | 1 Year
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	29.37
Chicago 3-2-1 Crack Spreads (WTI) | 2 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	24.10
Chicago 3-2-1 Crack Spreads (WTI) | 3 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	22.12
Chicago 3-2-1 Crack Spreads (WTI) | 4 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	21.70
Chicago 3-2-1 Crack Spreads (WTI) | 5 Years
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows	21.67
Chicago 3-2-1 Crack Spreads (WTI) | Not later than two years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		14.87
Chicago 3-2-1 Crack Spreads (WTI) | Not later than two years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		18.44
Chicago 3-2-1 Crack Spreads (WTI) | Later than two years and not later than four years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		14.68
Chicago 3-2-1 Crack Spreads (WTI) | Later than two years and not later than four years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows		16.81
Group 3 3-2-1 Crack Spreads (WTI) | Not later than two years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows | $ / barrel			11.56
Group 3 3-2-1 Crack Spreads (WTI) | Not later than two years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows | $ / barrel			13.23
Group 3 3-2-1 Crack Spreads (WTI) | Later than two years and not later than four years | Bottom of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows | $ / barrel			11.79
Group 3 3-2-1 Crack Spreads (WTI) | Later than two years and not later than four years | Top of range
Disclosure of information for impairment loss recognised or reversed for individual asset or cash-generating unit [line items]
Long-term Price Assumptions Used to Determine Future Cash Flows | $ / barrel			16.58

XML

Other Income (Loss), Net (Details) - CAD ($) $ in Millions	12 Months Ended			48 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2021
Disclosure of attribution of expenses by nature to their function [line items]
Insurance proceeds	$ 0			$ 135
Decommissioning Liabilities	3,559	$ 3,906	$ 1,248	3,906
Site Rehabilitation Program
Disclosure of attribution of expenses by nature to their function [line items]
Decommissioning Liabilities	65	42	0	$ 42
2018 Atlantic Region Incident
Disclosure of attribution of expenses by nature to their function [line items]
Insurance proceeds	$ 328	$ 120	$ 0

XML

Income Taxes - Provision for Income Taxes (Detail) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)		$ 1,639	$ 276		$ (13)
Deferred Tax Expense (Recovery)		642	452		(838)
Total Tax Expense (Recovery) From Operations		2,281	728	[1]	(851)	[1]
Canada
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)		1,252	104		(14)
Deferred Tax Expense (Recovery)	$ 106
United States
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)		104	0		1
Deferred Tax Expense (Recovery)	$ 217
Asia Pacific
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)		262	171		0
Other International
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)		$ 21	$ 1		$ 0

[1] See Note 3X for revisions to prior period results.

XML

Income Taxes - Additional Information (Detail) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2018	Jan. 01, 2021
Disclosure of income taxes [line items]
Deferred Tax Expense (Recovery)		$ 642	$ 452	$ (838)
Canadian statutory tax rate		23.70%	23.70%	24.00%
Deferred Income Taxes	$ 694	$ 546	$ 694			$ 1,100
Amounts of tax pools available, including tax losses	17,682	15,439	17,682
Sunrise
Disclosure of income taxes [line items]
Deferred Income Taxes		(486)
Canadian Federal Non Capital Losses
Disclosure of income taxes [line items]
Amounts of tax pools available, including tax losses	1,500	115	1,500
US Federal Net Operating Losses
Disclosure of income taxes [line items]
Amounts of tax pools available, including tax losses	775	468	775
Canadian Net Capital Losses
Disclosure of income taxes [line items]
Amounts of tax pools available, including tax losses	102	28	102
Net capital losses associated with unrealized foreign exchange losses		504	102
United States
Disclosure of income taxes [line items]
Deferred Tax Expense (Recovery)	217
Deferred Income Taxes						359
Amounts of tax pools available, including tax losses	5,915	6,477	5,915
Canada
Disclosure of income taxes [line items]
Deferred Tax Expense (Recovery)	106
Deferred Income Taxes						1,100
Amounts of tax pools available, including tax losses	11,167	8,505	11,167
Alberta
Disclosure of income taxes [line items]
Canadian statutory tax rate				8.00%	12.00%
Asia Pacific
Disclosure of income taxes [line items]
Deferred Income Taxes						$ (444)
Amounts of tax pools available, including tax losses	$ 600	$ 457	$ 600

XML

Income Taxes - Reconciliation of Income Taxes Calculated at Statutory Rate (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Disclosure Of Income Tax Expense Continuing Operations [Abstract]
Earnings (Loss) Before Income Tax	$ 8,731	$ 1,315	[1]	$ (3,230)	[1]
Canadian Statutory Rate	23.70%	23.70%		24.00%
Expected Income Tax Expense (Recovery) From Operations	$ 2,069	$ 312		$ (775)
Effect on Taxes Resulting From:
Statutory and Other Rate Differences	17	3		19
Non-Taxable Capital (Gains) Losses	84	63		(42)
Non-Recognition of Capital (Gains) Losses	84	27		(42)
Adjustments Arising From Prior Year Tax Filings	15	(5)		(8)
U.S. Tax Attribute Limitation	0	217		0
Impact of Rate Changes	0	106		(7)
Other	12	5		4
Total Tax Expense (Recovery) From Operations	$ 2,281	$ 728	[1]	$ (851)	[1]
Effective Tax Rate	26.10%	55.40%		26.30%

[1] See Note 3X for revisions to prior period results.

XML

Income Taxes - Deferred Income Tax Liabilities and Deferred Income Tax Assets (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of income taxes [line items]
Deferred income tax liabilities	$ 4,515	$ 4,046	$ 4,146
Deferred Income Tax Assets	(778)	(1,454)	(948)
Net deferred income tax liability, beginning balance	3,737	2,592	$ 3,198
1 Year
Disclosure of income taxes [line items]
Deferred income tax liabilities	55	0
Deferred Income Tax Assets	(31)	(556)
Deferred Income Tax Assets to be Settled After More Than Twelve Months
Disclosure of income taxes [line items]
Deferred income tax liabilities	4,460	4,046
Deferred Income Tax Assets	$ (747)	$ (898)

XML

Income Taxes - Schedule of Movement in Deferred Income Tax Liabilities and Assets (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred income tax liabilities, beginning balance	$ 4,046	$ 4,146
Deferred income tax assets, beginning balance	(1,454)	(948)
Net deferred income tax liabilities, beginning balance	2,592	3,198
Deferred income tax liabilities, ending balance	4,515	4,046
Deferred income tax assets, ending balance	(778)	(1,454)
Net deferred income tax liabilities, ending balance	3,737	2,592
Unused Tax Losses
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred income tax assets, beginning balance	(655)	(659)
Deferred income tax assets, ending balance	(156)	(655)
Deferred Income Tax Liabilities
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	(17)	(159)
Deferred Income Tax Liabilities | Husky Energy, Inc.
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions		59
Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions	486
Deferred Income Tax Assets
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	659	611
Charged (Credited) to Acquisitions	0	(1,121)
Charged (Credited) to Other Comprehensive Income	17	4
Deferred Income Tax Assets | Unused Tax Losses
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	490	668
Charged (Credited) to Acquisitions	0	(656)
Charged (Credited) to Other Comprehensive Income	9	(8)
Net Deferred Income Tax Liabilities
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	642	452
Charged (Credited) to Acquisitions	486	(1,062)
Charged (Credited) to Other Comprehensive Income	17	4
PP&E
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred income tax liabilities, beginning balance	3,949	4,124
Deferred income tax liabilities, ending balance	4,460	3,949
PP&E | Deferred Income Tax Liabilities
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	25	(234)
PP&E | Deferred Income Tax Liabilities | Husky Energy, Inc.
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions		59
PP&E | Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions	486
Risk Management
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred income tax liabilities, beginning balance	0	0
Deferred income tax assets, beginning balance	(11)	(13)
Deferred income tax liabilities, ending balance	11	0
Deferred income tax assets, ending balance	0	(11)
Risk Management | Deferred Income Tax Liabilities
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	11	0
Risk Management | Deferred Income Tax Liabilities | Husky Energy, Inc.
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions		0
Risk Management | Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions	0
Risk Management | Deferred Income Tax Assets
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	11	1
Charged (Credited) to Acquisitions	0	1
Charged (Credited) to Other Comprehensive Income	0	0
Other
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred income tax liabilities, beginning balance	97	22
Deferred income tax assets, beginning balance	(788)	(276)
Deferred income tax liabilities, ending balance	44	97
Deferred income tax assets, ending balance	(622)	(788)
Other | Deferred Income Tax Liabilities
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	(53)	75
Other | Deferred Income Tax Liabilities | Husky Energy, Inc.
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions		0
Other | Deferred Income Tax Liabilities | Sunrise Oil Sands Partnership
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Acquisitions	0
Other | Deferred Income Tax Assets
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	158	(58)
Charged (Credited) to Acquisitions	0	(466)
Charged (Credited) to Other Comprehensive Income	$ 8	$ 12

XML

Income Taxes - Schedule of Amounts of Tax Pools Available, Including Tax Losses (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Amounts of tax pools available, including tax losses	$ 15,439	$ 17,682
Canada
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Amounts of tax pools available, including tax losses	8,505	11,167
United States
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Amounts of tax pools available, including tax losses	6,477	5,915
Asia Pacific
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Amounts of tax pools available, including tax losses	$ 457	$ 600

XML

Per Share Amounts - Schedule Representing Per Share Amounts (Detail) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Earnings per share [abstract]
Net Earnings (Loss)	$ 6,450	$ 587	[1]	$ (2,379)	[1]
Effect of Cumulative Dividends on Preferred Shares	(35)	(34)		0
Net Earnings (Loss) – Basic and Diluted	$ 6,415	$ 553		$ (2,379)
Basic – Weighted Average Number of Shares (in shares)	1,951.3	2,016.2		1,228.9
Dilutive Effect of Warrants (in shares)	44.8	27.6		0.0
Dilutive Effect of Net Settlement Rights (in shares)	10.0	1.3		0.0
Diluted - Weighted Average Number of Shares (in shares)	2,006.1	2,045.1		1,228.9
Net Earnings (Loss) Per Share — Basic (CAD per share)	$ 3.29	$ 0.27	[1]	$ (1.94)	[1]
Net Earnings (Loss) Per Share — Diluted (CAD per share)	$ 3.20	$ 0.27	[1]	$ (1.94)	[1]

[1] See Note 3X for revisions to prior period results.

XML

Per Share Amounts - Additional Information (Detail) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
	Feb. 15, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net settlement rights
Disclosure of non-adjusting events after reporting period [line items]
Instruments excluded from calculation, shares (in shares)			18.0	31.0
Common shares
Disclosure of non-adjusting events after reporting period [line items]
Instruments excluded from calculation, value		$ 52	$ 22	$ 0
Instruments excluded from calculation, shares (in shares)		1.6	1.9	0.0
Common shares | Potential ordinary share transactions
Disclosure of non-adjusting events after reporting period [line items]
Dividends declared (in CAD per share)	$ 0.105
Preference shares | Preferred Stock Dividend Transactions
Disclosure of non-adjusting events after reporting period [line items]
Dividends declared	$ 9

XML

Per Share Amounts - Common Share Dividends (Details) - Common shares - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings per share [line items]
Dividends paid (in CAD per share)	$ 0.350	$ 0.088	$ 0.063
Dividends paid on common shares	$ 682	$ 176	$ 77
Variable dividends declared (in CAD per share)	$ 0.114	$ 0	$ 0
Variable dividends paid on common shares	$ 219	$ 0	$ 0
Total common share dividends paid (in CAD per share)	$ 0.464	$ 0.088	$ 0.063
Total dividends paid on common shares	$ 901	$ 176	$ 77

XML

Per Share Amounts - Preferred Share Dividends (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Earnings per share [line items]
Total Preferred Share Dividends Declared	$ 35	$ 34
Series 1 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	7	7
Series 2 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	1	1
Series 3 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	12	12
Series 5 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	9	9
Series 7 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	$ 6	$ 5

XML

Cash and Cash Equivalents - Schedule Representing Cash and Cash Equivalents (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash and cash equivalents [abstract]
Cash	$ 3,195	$ 2,366
Short-Term Investments	1,329	507
Total Cash and Cash Equivalents	$ 4,524	$ 2,873	$ 378	$ 186

XML

Accounts Receivables and Accrued Revenues - Schedule of accounts receivables and accrued revenues (Detail) - CAD ($) $ in Millions	12 Months Ended	48 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Trade and other current receivables [abstract]
Trade and Accruals	$ 2,962	$ 2,548
Prepaids and Deposits	402	486
Partner Advances	0	371
Joint Operations Receivables	51	225
Other	58	240
Accounts Receivable and Accrued Revenues	3,473	3,870
Insurance proceeds	$ 0	$ 135

XML

Inventories - Schedule of Inventories (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of inventories [line items]
Total Product	$ 4,009	$ 3,651
Parts and supplies	303	268
Current inventories	4,312	3,919
Crude Oil
Disclosure of inventories [line items]
Total Product	2,424	2,060
Diluent
Disclosure of inventories [line items]
Total Product	366	515
Natural Gas and NGLs
Disclosure of inventories [line items]
Total Product	50	33
Refined Products
Disclosure of inventories [line items]
Total Product	$ 1,169	$ 1,043

XML

Inventories - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Classes of current inventories [abstract]
Cost of inventories recognized as expense during period	$ 49,000	$ 34,000

XML

Assets Held for Sale (Details) - CAD ($) $ in Millions	Sep. 13, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [line items]
Property, Plant and Equipment, Net		$ 36,499	$ 34,225	$ 25,411
Right-of-Use Assets, Net		1,845	2,010	1,139
Goodwill		2,923	3,473	2,272
Lease Liabilities		(2,836)	(2,957)	(1,757)
Decommissioning Liabilities		$ (3,559)	(3,906)	$ (1,248)
Non-current assets held for sale
Disclosure of operating segments [line items]
Property, Plant and Equipment, Net			1,162
Right-of-Use Assets, Net			54
Goodwill			88
Liabilities classified as held for sale
Disclosure of operating segments [line items]
Lease Liabilities			(58)
Decommissioning Liabilities			(128)
Retail
Disclosure of operating segments [line items]
Consideration for sale of assets held for sale	$ 404
Retail | Non-current assets held for sale
Disclosure of operating segments [line items]
Property, Plant and Equipment, Net			498
Right-of-Use Assets, Net			54
Goodwill			0
Retail | Liabilities classified as held for sale
Disclosure of operating segments [line items]
Lease Liabilities			(58)
Decommissioning Liabilities			(86)
Tucker | Non-current assets held for sale
Disclosure of operating segments [line items]
Property, Plant and Equipment, Net			505
Right-of-Use Assets, Net			0
Tucker | Liabilities classified as held for sale
Disclosure of operating segments [line items]
Lease Liabilities			0
Decommissioning Liabilities			(33)
Wembley | Non-current assets held for sale
Disclosure of operating segments [line items]
Property, Plant and Equipment, Net			159
Right-of-Use Assets, Net			0
Goodwill			0
Wembley | Liabilities classified as held for sale
Disclosure of operating segments [line items]
Lease Liabilities			0
Decommissioning Liabilities			$ (9)

XML

Exploration and Evaluation Assets, Net - Summary of Exploration and Valuation Assets, Net (Detail) - CAD ($) $ in Millions	8 Months Ended	12 Months Ended
	Aug. 31, 2022	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	$ 720	$ 720
Write-downs		(101)	$ (18)	[1]	$ (91)	[1]
Ending Balance		685	720
Sunrise Oil Sands Partnership
Disclosure Of Exploration And Evaluation Assets [Line Items]
Carrying Value Of Investment In Joint Ventures Prior To Acquisition​ Date	0
Gain (loss) recognised as result of remeasuring to fair value equity interest in acquiree held by acquirer before business combination	40
Oil Sands
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	653	653
Ending Balance		674	653
Offshore
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	61	61
Ending Balance		5	61
E&E Asset
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	$ 720	720	623
Acquisitions (Note 5)			45
Additions		37	55
Write-downs		(64)	(9)
Change in Decommissioning Liabilities		(12)	6
Exchange Rate Movements and Other		4
Ending Balance		685	720		$ 623
E&E Asset | Oil Sands
Disclosure Of Exploration And Evaluation Assets [Line Items]
Exploration and evaluation costs previously capitalized, written off		2	$ 9
E&E Asset | Offshore
Disclosure Of Exploration And Evaluation Assets [Line Items]
Exploration and evaluation costs previously capitalized, written off		$ 62

[1] See Note 3X for revisions to prior period results.

XML

Property, Plant and Equipment, Net - Summary of Property, Plant and Equipment (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Aug. 31, 2022
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	$ 34,225	$ 25,411
Ending Balance	36,499	34,225
Property, Plant and Equipment, Net	36,499	34,225
Offshore
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	2,822
Ending Balance	2,549	2,822
Property, Plant and Equipment, Net	2,549	2,822
Write-downs (reversals of write-downs) of property, plant and equipment	26
Canadian Manufacturing
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	2,558
Ending Balance	2,466	2,558
Property, Plant and Equipment, Net	2,466	2,558
Write-downs (reversals of write-downs) of property, plant and equipment	25
Sunrise Oil Sands Partnership
Disclosure of detailed information about property, plant and equipment [line items]
Property, Plant and Equipment, Net			$ 454
COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	50,901	37,046
Acquisitions (Note 5)	3,230	13,380
Additions	3,671	2,515
Change in Decommissioning Liabilities	(253)	2
Divestitures (Note 5) (2)	(557)	(630)
Transfers to Assets Held for Sale (Note 18)		(1,276)
Exchange Rate Movements and Other	747	(136)
Ending Balance	57,739	50,901
Property, Plant and Equipment, Net	57,739	50,901
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	(16,676)	(11,635)
Divestitures (Note 5) (2)	84	377
Transfers to Assets Held for Sale (Note 18)		(114)
Exchange Rate Movements and Other	315	(20)
Depreciation, Depletion and Amortization (3)	4,067	3,999
Impairment Charges (Note 11)	1,499	1,931
Impairment Reversals (Note 11)	(1,233)	(378)
Ending Balance	(21,240)	(16,676)
Property, Plant and Equipment, Net	(21,240)	(16,676)
Oil and Gas Properties
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	27,531	21,506
Ending Balance	29,226	27,531
Property, Plant and Equipment, Net	29,226	27,531
Oil and Gas Properties | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	38,443	29,867
Acquisitions (Note 5)	3,230	8,633
Additions	2,409	1,368
Change in Decommissioning Liabilities	(186)	(63)
Divestitures (Note 5) (2)	(557)	(630)
Transfers to Assets Held for Sale (Note 18)		(754)
Exchange Rate Movements and Other	189	22
Ending Balance	43,528	38,443
Property, Plant and Equipment, Net	43,528	38,443
Oil and Gas Properties | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	(10,912)	(8,361)
Divestitures (Note 5) (2)	84	377
Transfers to Assets Held for Sale (Note 18)		(90)
Exchange Rate Movements and Other	13	61
Depreciation, Depletion and Amortization (3)	3,461	3,335
Impairment Charges (Note 11)	0	0
Impairment Reversals (Note 11)	0	(378)
Ending Balance	(14,302)	(10,912)
Property, Plant and Equipment, Net	(14,302)	(10,912)
Processing, Transportation and Storage Assets
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	175	176
Ending Balance	148	175
Property, Plant and Equipment, Net	148	175
Processing, Transportation and Storage Assets | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	228	218
Acquisitions (Note 5)	0	0
Additions	11	9
Change in Decommissioning Liabilities	(6)	1
Divestitures (Note 5) (2)	0	0
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	21	0
Ending Balance	254	228
Property, Plant and Equipment, Net	254	228
Processing, Transportation and Storage Assets | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	(53)	(42)
Divestitures (Note 5) (2)	0	0
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	16	1
Depreciation, Depletion and Amortization (3)	37	10
Impairment Charges (Note 11)	0	0
Impairment Reversals (Note 11)	0	0
Ending Balance	(106)	(53)
Property, Plant and Equipment, Net	(106)	(53)
Manufacturing Assets
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	5,923	3,476
Ending Balance	6,585	5,923
Property, Plant and Equipment, Net	6,585	5,923
Manufacturing Assets | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	10,495	5,671
Acquisitions (Note 5)	0	3,901
Additions	1,143	1,023
Change in Decommissioning Liabilities	(29)	40
Divestitures (Note 5) (2)	0	0
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	523	(140)
Ending Balance	12,132	10,495
Property, Plant and Equipment, Net	12,132	10,495
Manufacturing Assets | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	(4,572)	(2,195)
Divestitures (Note 5) (2)	0	0
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	243	(80)
Depreciation, Depletion and Amortization (3)	466	526
Impairment Charges (Note 11)	1,499	1,931
Impairment Reversals (Note 11)	(1,233)	0
Ending Balance	(5,547)	(4,572)
Property, Plant and Equipment, Net	(5,547)	(4,572)
Retail and other
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	596	253
Ending Balance	540	596
Property, Plant and Equipment, Net	540	596
Retail and other | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	1,735	1,290
Acquisitions (Note 5)	0	846
Additions	108	115
Change in Decommissioning Liabilities	(32)	24
Divestitures (Note 5) (2)	0	0
Transfers to Assets Held for Sale (Note 18)		(522)
Exchange Rate Movements and Other	14	(18)
Ending Balance	1,825	1,735
Property, Plant and Equipment, Net	1,825	1,735
Retail and other | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning Balance	(1,139)	(1,037)
Divestitures (Note 5) (2)	0	0
Transfers to Assets Held for Sale (Note 18)		(24)
Exchange Rate Movements and Other	43	(2)
Depreciation, Depletion and Amortization (3)	103	128
Impairment Charges (Note 11)	0	0
Impairment Reversals (Note 11)	0	0
Ending Balance	(1,285)	(1,139)
Property, Plant and Equipment, Net	$ (1,285)	$ (1,139)

XML

Property, Plant and Equipment, Net - Assets Under Construction (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about property, plant and equipment [line items]
Property Plant and Equipment Temporarily Idle	$ 2,279	$ 3,358
Development and Production
Disclosure of detailed information about property, plant and equipment [line items]
Property Plant and Equipment Temporarily Idle	2,142	2,415
Refining equipment
Disclosure of detailed information about property, plant and equipment [line items]
Property Plant and Equipment Temporarily Idle	$ 137	$ 943

XML

Right of Use Assets, Net - Summary of Right of Use Assets, Net (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	$ 2,010	$ 1,139
Balance at end of period	1,845	2,010
COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	2,656	1,502
Acquisition (Note 5)		1,132
Additions	25	110
Modifications	83	22
Re-measurements	7	(4)
Transfers to Assets Held for Sale (Note 18)		(78)
Exchange Rate Movements and Other	(74)	(28)
Terminations	(10)
Balance at end of period	2,687	2,656
ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	646	363
Transfers to Assets Held for Sale (Note 18)		(24)
Exchange Rate Movements and Other	95	24
Terminations	(6)	(3)
Depreciation	297	323
Impairment Reversals (Note 11)		11
Balance at end of period	842	646
Real Estate
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	500	437
Balance at end of period	472	500
Real Estate | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	592	495
Acquisition (Note 5)		99
Additions	0	4
Modifications	9	1
Re-measurements	1	(2)
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	(2)	(5)
Terminations	(1)
Balance at end of period	599	592
Real Estate | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	92	58
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	1	4
Terminations	0	0
Depreciation	36	38
Impairment Reversals (Note 11)		0
Balance at end of period	127	92
Transportation And Storage Assets
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	1,321	684
Balance at end of period	1,195	1,321
Transportation And Storage Assets | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	1,841	977
Acquisition (Note 5)		765
Additions	22	96
Modifications	69	20
Re-measurements	3	1
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	(89)	(18)
Terminations	(6)
Balance at end of period	1,840	1,841
Transportation And Storage Assets | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	520	293
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	95	14
Terminations	(6)	(3)
Depreciation	226	239
Impairment Reversals (Note 11)		5
Balance at end of period	645	520
Manufacturing Assets
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	128	10
Balance at end of period	116	128
Manufacturing Assets | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	161	15
Acquisition (Note 5)		138
Additions	1	7
Modifications	3	1
Re-measurements	2	0
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	9	0
Terminations	(2)
Balance at end of period	174	161
Manufacturing Assets | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	33	5
Transfers to Assets Held for Sale (Note 18)		0
Exchange Rate Movements and Other	(4)	0
Terminations	0	0
Depreciation	21	23
Impairment Reversals (Note 11)		5
Balance at end of period	58	33
Other Assets
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	61	8
Balance at end of period	62	61
Other Assets | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	62	15
Acquisition (Note 5)		130
Additions	2	3
Modifications	2	0
Re-measurements	1	(3)
Transfers to Assets Held for Sale (Note 18)		(78)
Exchange Rate Movements and Other	8	(5)
Terminations	(1)
Balance at end of period	74	62
Other Assets | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	1	7
Transfers to Assets Held for Sale (Note 18)		(24)
Exchange Rate Movements and Other	3	6
Terminations	0	0
Depreciation	14	23
Impairment Reversals (Note 11)		1
Balance at end of period	$ 12	$ 1

XML

Joint Arrangements - Joint Operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020	[1]
Disclosure of joint operations [line items]
Net Earnings (Loss)	$ 6,450	$ 587	[1]	$ (2,379)
Husky-CNOOC Madura Ltd.
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	40.00%
Share of income from equity-accounted affiliate	$ 23	47
Investments in joint ventures accounted for using equity method	365	311
Distributions received	42	100
Joint venture, contributions	54	18
Net Earnings (Loss)	$ 33	44
Husky Midstream Limited Partnership
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	35.00%
Investments in joint ventures accounted for using equity method	$ 0	0
Distributions received	23	37
Joint venture, contributions	31	32
Net Earnings (Loss)	190	134
Unrecognised share of pre-tax net losses of joint ventures	23	22
Unrecognised share of losses of joint ventures	$ 28	$ 17
Power Assets Holding Ltd. | Husky Midstream Limited Partnership
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	49.00%
Cheung Kong Infrastructure Holdings Ltd. | Husky Midstream Limited Partnership
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	16.00%
BP-Husky Refining LLC
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
BP-Husky Refining LLC | BP
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
WRB Refining LP
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
WRB Refining LP | Phillips 66
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%

[1] See Note 3X for revisions to prior period results.

XML

Joint Arrangements - Husky - CNOOC Madura Ltd (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Results of Operations
Revenue	$ 66,897	$ 46,357	[1]	$ 13,543	[1]
Operating	5,569	4,716	[1]	1,955	[1]
Net Earnings (Loss)	6,450	587	[1]	(2,379)	[1]
Balance Sheets
Total Current Assets	12,430	11,988
Current Liabilities	8,021	7,305
Cash and Cash Equivalents	4,524	2,873		$ 378		$ 186
Husky-CNOOC Madura Ltd.
Results of Operations
Revenue	383	439
Operating	350	395
Net Earnings (Loss)	33	44
Balance Sheets
Total Current Assets	247	167
Non-Current Assets	1,926	1,433
Current Liabilities	160	62
Non-Current Liabilities	1,293	896
Net Assets	720	642
Cash and Cash Equivalents	$ 64	$ 46

[1] See Note 3X for revisions to prior period results.

XML

Other Assets - Schedule of Other Assets (Detail) - CAD ($) $ in Millions		12 Months Ended
	Jun. 08, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 23, 2021
Disclosure of classes of share capital [Line Items]
Intangible Assets (1)		$ 19	$ 78
Private Equity Investments (Note 37)		55	53
Other Equity Investments		0	77
Net Investment in Finance Leases		62	60
Long-Term Receivables and Prepaids		120	77
Precious Metals		86	85
Other		0	1
Other assets		342	431
Oil Sands
Disclosure of classes of share capital [Line Items]
Disposals, intangible assets other than goodwill		$ 49
Headwater Exploration Inc.
Disclosure of classes of share capital [Line Items]
Proceeds from disposal of oil and gas assets	$ 110
Headwater Exploration Inc.
Disclosure of classes of share capital [Line Items]
Other Equity Investments			$ 77
Consideration transferred in sale of non-current assets, warrants, amount				$ 30

XML

Goodwill - Activity (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Abstract]
Goodwill at beginning of period	$ 3,473	$ 2,272
Goodwill Recognized (Note 5)	0	1,289
Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18)	(550)	(88)
Goodwill at end of period	$ 2,923	$ 3,473

XML

Goodwill - Allocation (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of reconciliation of changes in goodwill [line items]
Goodwill	$ 2,923	$ 3,473	$ 2,272
Primrose (Foster Creek)
Disclosure of reconciliation of changes in goodwill [line items]
Goodwill	1,171	1,171
Christina Lake
Disclosure of reconciliation of changes in goodwill [line items]
Goodwill	1,101	1,101
Lloydminister thermal
Disclosure of reconciliation of changes in goodwill [line items]
Goodwill	651	651
Sunrise
Disclosure of reconciliation of changes in goodwill [line items]
Goodwill	$ 0	$ 550

XML

Goodwill - Additional Information (Detail) - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Abstract]
Goodwill impairments	$ 0	$ 0

XML

Accounts Payable and Accrued Liabilities - Schedule of Accounts Payable and Accrued Liabilities (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Trade and other current payables [abstract]
Accruals	$ 3,412	$ 2,722
Trade	2,331	2,554
Interest	80	128
Partner Advances	0	371
Employee Long-Term Incentives	162	317
Joint Operations Payable	66	28
Risk Management	39	116
Provisions for Onerous and Unfavourable Contracts	25	31
Other	9	86
Accounts payable and accrued liabilities	$ 6,124	$ 6,353

XML

Contingent Payments - Summary of Contingent Payment (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Aug. 31, 2022
Disclosure of contingent liabilities in business combination [line items]
Less: Current Portion	$ 263	$ 236
Long-Term Portion	156	0
Sunrise Oil Sands Partnership
Disclosure of contingent liabilities in business combination [line items]
Contingent Payment, Beginning of Year	0
Initial Recognition			$ 600
Liabilities Settled	(92)
Re-measurement	(89)
Contingent Payment, End of Year	419	0
Less: Current Portion	263
Long-Term Portion	156
FCCL Partnership
Disclosure of contingent liabilities in business combination [line items]
Contingent Payment, Beginning of Year	236	63
Liabilities Settled	(487)	(402)
Re-measurement	251	575
Contingent Payment, End of Year	$ 0	$ 236

XML

Contingent Payments - Additional Information (Detail) $ in Millions			1 Months Ended		8 Months Ended	12 Months Ended
	Jun. 13, 2022 CAD ($)	May 17, 2022 CAD ($) $ / bbl	Jan. 31, 2023 CAD ($)	Jul. 31, 2022 CAD ($)	Aug. 30, 2022	Dec. 31, 2022 CAD ($) $ / bbl	Dec. 31, 2021 CAD ($)	Aug. 31, 2022 CAD ($) $ / bbl
Disclosure of contingent liabilities in business combination [line items]
Average crude oil price | $ / bbl						45.00
FCCL Partnership
Disclosure of contingent liabilities in business combination [line items]
Proportion of ownership interest in joint operation		50.00%
Sunrise Oil Sands Partnership
Disclosure of contingent liabilities in business combination [line items]
Proportion of ownership interest in joint operation	35.00%				50.00%
Conoco Phillips Company and certain of its subsidiaries
Disclosure of contingent liabilities in business combination [line items]
Contingent payable				$ 177.0			$ 160.0
Proportion of ownership interest in joint operation						5000.00%
Contingent payments period		5 years
Average crude oil price | $ / bbl		52.00
Quarterly contingent payment		$ 6.0
Sunrise Oil Sands Partnership
Disclosure of contingent liabilities in business combination [line items]
Contingent consideration, quarterly payment								$ 2.8
Contingent consideration, price per barrel (in dollars per share) | $ / bbl								52.00
Contingent Consideration Maximum Payment	$ 600.0							$ 600.0
Contingent payable						$ 92.0
Sunrise Oil Sands Partnership | Major business combination [member]
Disclosure of contingent liabilities in business combination [line items]
Contingent payable			$ 92.0
Sunrise Oil Sands Partnership | Top of range
Disclosure of contingent liabilities in business combination [line items]
Contingent consideration, price per barrel (in dollars per share) | $ / bbl								53.00

XML

Debt and Capital Structure - Schedule of Short-Term Borrowings (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about borrowings [line items]
Short-Term Borrowings	$ 115	$ 79
Uncommitted Demand Facilities
Disclosure of detailed information about borrowings [line items]
Short-Term Borrowings	0	0
WRB Refining LP
Disclosure of detailed information about borrowings [line items]
Short-Term Borrowings	$ 115	$ 79

XML

Debt and Capital Structure - Additional Information (Detail) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / bbl	Dec. 31, 2022 USD ($)	Nov. 10, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)	Oct. 07, 2021 USD ($)	Sep. 13, 2021 USD ($)	Aug. 18, 2021 CAD ($)	Jan. 01, 2021 CAD ($)	Jan. 01, 2021 USD ($)
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	$ 490			$ 565
Weighted average interest rate	4.70%	4.70%		4.60%	4.60%
Total Debt	$ 8,691			$ 12,385
Maximum debt to capitalization ratio	65.00%	65.00%
Target Net Debt to Adjusted EBITDA Ratio	1.0
Average crude oil price | $ / bbl	45.00
Target net debt	$ 4,000
Debt offering, maximum amount		$ 4,700				$ 5,000
Uncommitted Demand Facilities
Disclosure of detailed information about borrowings [line items]
Committed demand facilities	1,400
Uncommitted Demand Facilities | Top of range
Disclosure of detailed information about borrowings [line items]
Amount of undrawn facilities for general purposes	1,000
WRB Refining LP
Disclosure of detailed information about borrowings [line items]
Committed demand facilities	190	140
Undrawn borrowing facilities		170			$ 125
WRB Refining LP | Cenovus Energy Inc
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing facilities	115	85		79	63
Maximum
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity	1,900
Maximum | Top of range
Disclosure of detailed information about borrowings [line items]
Amount of undrawn facilities for general purposes	1,400
Maximum | WRB Refining LP
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity		450			300
Maximum | WRB Refining LP | Cenovus Energy Inc
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity		$ 225			$ 150
Maximum | Sunrise Oil Sands Partnership
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity				10
Maximum | Sunrise Oil Sands Partnership | Cenovus Energy Inc
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity				5
Committed Credit Facility
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity			$ 5,500					$ 6,000
Undrawn borrowing facilities	0			$ 0
Decrease in capacity of committed credit facility			$ 500
Committed credit facilities, cancelled								$ 8,500
Committed Credit Facility | The Arrangement
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity									$ 4,000
Total Debt									350
Committed Credit Facilities, Maturing August 18, 2024
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity	1,800
Committed Credit Facilities, Maturing August 18, 2025
Disclosure of detailed information about borrowings [line items]
Committed credit facilities, maximum borrowing capacity	$ 3,700
Senior unsecured notes, 2.65%, maturing January 15, 2032
Disclosure of detailed information about borrowings [line items]
Total Debt							$ 500
Senior unsecured notes, 3.75%, maturing February 15, 2052
Disclosure of detailed information about borrowings [line items]
Total Debt							750
Senior Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total Debt							$ 1,250
Canadian Dollar Denominated Unsecured Notes | The Arrangement
Disclosure of detailed information about borrowings [line items]
Total Debt									2,800
Long-term debt, fair value									2,900
U.S. Dollar Denominated Unsecured Notes | The Arrangement
Disclosure of detailed information about borrowings [line items]
Total Debt									3,000	$ 2,400
Long-term debt, fair value									$ 3,400

XML

Debt and Capital Structure - Schedule of Long-Term Debt (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about borrowings [line items]
Net Debt Premiums (Discounts) and Transaction Costs	$ 154	$ 272
Total Debt	8,691	12,385
Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	8,537	12,113
Long-Term Debt | Revolving Term Debt
Disclosure of detailed information about borrowings [line items]
Revolving Term Debt	0	0
Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	6,537	9,363
Long-Term Debt | Canadian Dollar Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	$ 2,000	$ 2,750

XML

Debt and Capital Structure - Unsecured Notes (Details) $ in Millions, $ in Millions	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 CAD ($)
Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total debt principal	$ 2,558		$ 2,150
3.95% due April 15, 2022
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.95%	3.95%
Total debt principal	$ 0		500
3.00% due August 15, 2022
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.00%	3.00%
Total debt principal	$ 0		500
3.80% due September 15, 2023
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.80%	3.80%
Total debt principal	$ 115		335
4.00% due April 15, 2024
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.00%	4.00%
Total debt principal	$ 269		481
5.38% due July 15, 2025
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.38%	5.38%
Total debt principal	$ 533		334
4.25% due April 15, 2027
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.25%	4.25%
Total debt principal	$ 589		0
4.40% due April 15, 2029
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.40%	4.40%
Total debt principal	$ 510		0
6.75% due November 15, 2039
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	6.75%	6.75%
Total debt principal	$ 455		0
4.45% due September 15, 2042
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.45%	4.45%
Total debt principal	$ 58		0
5.20% due September 15, 2043
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.20%	5.20%
Total debt principal	$ 29		$ 0
3.55% due March 12, 2025
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.55%	3.55%
Total debt principal		$ 750		$ 0

XML

Debt and Capital Structure - Schedule Remaining Principal Amounts of U.S. Dollar Denominated Unsecured Notes (Detail) $ in Millions, $ in Millions	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about borrowings [line items]
Total debt principal			$ 7,400
Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal		$ 8,537		$ 12,113
Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total debt principal	$ 4,827	$ 6,537	7,385	9,363
3.80% due September 15, 2023 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.80%	3.80%
Total debt principal	$ 0	$ 0	115	146
4.00% due April 15, 2024 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.00%	4.00%
Total debt principal	$ 0	$ 0	269	341
5.38% due July 15, 2025 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.38%	5.38%
Total debt principal	$ 133	$ 181	666	844
4.25% due April 15, 2027 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.25%	4.25%
Total debt principal	$ 373	$ 505	962	1,220
4.40% due April 15, 2029 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.40%	4.40%
Total debt principal	$ 240	$ 324	750	951
2.65% due January 15, 2032 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	2.65%	2.65%
Total debt principal	$ 500	$ 677	500	634
5.25% due June 15, 2037 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.25%	5.25%
Total debt principal	$ 583	$ 790	583	739
6.80% due September 15, 2037 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	6.80%	6.80%
Total debt principal	$ 387	$ 524	387	490
6.75% due November 15, 2039 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	6.75%	6.75%
Total debt principal	$ 935	$ 1,267	1,390	1,763
4.45% due September 15, 2042 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.45%	4.45%
Total debt principal	$ 97	$ 131	155	197
5.20% due September 15, 2043 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.20%	5.20%
Total debt principal	$ 29	$ 39	58	73
5.40% due June 15, 2047 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.40%	5.40%
Total debt principal	$ 800	$ 1,083	800	1,014
3.75% due February 15, 2052 | Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.75%	3.75%
Total debt principal	$ 750	$ 1,016	$ 750	$ 951

XML

Debt and Capital Structure - Schedule Remaining Principal Amounts of Canadian Dollar Denominated Unsecured Notes (Details) $ in Millions, $ in Billions	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about borrowings [line items]
Total debt principal		$ 7.4
Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal	$ 8,537		$ 12,113
Long-Term Debt | Canadian Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total debt principal	$ 2,000		2,750
3.55% due March 12, 2025 | Long-Term Debt | Canadian Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.55%
Total debt principal	$ 0		750
3.60% due March 10, 2027 | Long-Term Debt | Canadian Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.60%
Total debt principal	$ 750		750
3.50% due February 7, 2028 | Long-Term Debt | Canadian Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.50%
Total debt principal	$ 1,250		$ 1,250

XML

Debt and Capital Structure - Mandatory Debt Payments (Details) $ in Millions, $ in Millions	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Disclosure of detailed information about borrowings [line items]
Total debt principal				$ 7,400
Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal	$ 8,537		$ 12,113
Total Debt Principal, (CAD equivalent)	8,537		12,113
1 Year | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	0
2024 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	0
2025 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	181
2026 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	0
5 Years | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	1,255
Thereafter | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	7,101
U.S. Dollar Denominated Unsecured Notes | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal	6,537	$ 4,827	9,363	$ 7,385
Total Debt Principal, (CAD equivalent)	6,537		9,363
U.S. Dollar Denominated Unsecured Notes | 1 Year | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal		0
Total Debt Principal, (CAD equivalent)	0
U.S. Dollar Denominated Unsecured Notes | 2024 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal		0
Total Debt Principal, (CAD equivalent)	0
U.S. Dollar Denominated Unsecured Notes | 2025 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal		133
Total Debt Principal, (CAD equivalent)	181
U.S. Dollar Denominated Unsecured Notes | 2026 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal		0
Total Debt Principal, (CAD equivalent)	0
U.S. Dollar Denominated Unsecured Notes | 5 Years | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal		373
Total Debt Principal, (CAD equivalent)	505
U.S. Dollar Denominated Unsecured Notes | Thereafter | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal		$ 4,321
Total Debt Principal, (CAD equivalent)	5,851
Canadian Dollar Denominated Unsecured Notes | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total debt principal	2,000		$ 2,750
Total Debt Principal, (CAD equivalent)	2,000
Canadian Dollar Denominated Unsecured Notes | 1 Year | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	0
Canadian Dollar Denominated Unsecured Notes | 2024 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	0
Canadian Dollar Denominated Unsecured Notes | 2025 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	0
Canadian Dollar Denominated Unsecured Notes | 2026 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	0
Canadian Dollar Denominated Unsecured Notes | 5 Years | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	750
Canadian Dollar Denominated Unsecured Notes | Thereafter | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	$ 1,250

XML

Debt and Capital Structure - Summary of Net Debt to Adjusted EBITDA (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Disclosure of objectives, policies and processes for managing capital [line items]
Short-Term Borrowings	$ 115	$ 79
Current Portion of Long-Term Debt	0	0		$ 0
Long-Term Portion of Long-Term Debt	8,691	12,385
Total Debt	8,691	12,385
Less: Cash and Cash Equivalents	(4,524)	(2,873)		(378)		$ (186)
Net Debt	4,282	9,591		7,184
Net Earnings (Loss)	6,450	587	[1]	(2,379)	[1]
Add (Deduct):
Interest Income	(81)	(23)	[1]	(9)	[1]
Foreign Exchange (Gain) Loss, Net	343	(174)	[1]	(181)	[1]
Revaluation (Gains)	549	0		0
Re-measurement of Contingent Payment	(162)	(575)	[1]	80	[1]
Other (Income) Loss, Net	$ (532)	$ (309)	[1]	$ 40	[1]
Net Debt to Adjusted EBITDA	30.00%	120.00%		1190.00%
Rolling Twelve Month Basis
Disclosure of objectives, policies and processes for managing capital [line items]
Short-Term Borrowings	$ 115	$ 79		$ 121
Long-Term Portion of Long-Term Debt	8,691	12,385		7,441
Total Debt	8,806	12,464		7,562
Less: Cash and Cash Equivalents	(4,524)	(2,873)		(378)
Net Debt	4,282	9,591		7,184
Net Earnings (Loss)	6,450	587		(2,379)
Add (Deduct):
Finance Costs	820	1,082		536
Interest Income	(81)	(23)		(9)
Income Tax Expense (Recovery)	2,281	728		(851)
Depreciation, Depletion and Amortization	4,679	5,886		3,464
E&E Asset Write-downs	64	18		91
(Income) Loss From Equity-Accounted Affiliates	(15)	(57)		0
Unrealized (Gain) Loss on Risk Management	(126)	2		56
Foreign Exchange (Gain) Loss, Net	343	(174)		(181)
Revaluation (Gains)	(549)	0		0
Re-measurement of Contingent Payment	162	575		(80)
(Gain) Loss on Divestiture of Assets	(269)	(229)		(81)
Other (Income) Loss, Net	(532)	(309)		40
Adjusted EBITDA	$ 13,227	$ 8,086		$ 606

[1] See Note 3X for revisions to prior period results.

XML

Debt and Capital Structure - Summary of Net Debt to Adjusted Funds Flow (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Borrowings [abstract]
Net Debt	$ 4,282	$ 9,591	$ 7,184
Cash flows from (used in) operating activities	11,403	5,919	273
Settlement of Decommissioning Liabilities	(150)	(102)	(42)
Net Change In Non-Cash Working Capital	575	(1,227)	198
Adjusted Funds Flow	$ 10,978	$ 7,248	$ 117
Net Debt To Adjusted Funds Flow	40.00%	130.00%	6140.00%

XML

Debt and Capital Structure - Summary of Net Debt to Capitalization (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Borrowings [abstract]
Net Debt	$ 4,282	$ 9,591	$ 7,184
Shareholders’ Equity	27,576	23,596	16,707	$ 19,201
Capitalization	$ 31,858	$ 33,187	$ 23,891
Net Debt to Capitalization	13.00%	29.00%	30.00%

XML

Lease Liabilities - Summary of Lease Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lease liabilities [abstract]
Lease Liabilities, Beginning of Year	$ 2,957	$ 1,757
Acquisitions (Note 5)	0	1,441
Additions	25	110
Interest Expense (Note 7)	163	171	$ 87
Lease Payments	(465)	(471)
Modifications	83	22
Re-measurements	7	(4)
Terminations	(5)	(1)
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	0	(10)
Exchange Rate Movements and Other	71	(58)
Lease Liabilities, End of Year	2,836	2,957	$ 1,757
Less: Current Portion	308	272
Long-Term Portion	$ 2,528	$ 2,685

XML

Decommissioning Liabilities - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Aug. 31, 2022	Dec. 31, 2021
Disclosure of other provisions [line items]
Estimated future cash flows required to settle the obligation	$ 14,000		$ 14,000
Credit-adjusted risk-free rate	6.10%		4.40%
Inflation rate	2.00%		2.00%
Restricted Cash	$ 209		$ 186
Sunrise Oil Sands Partnership
Disclosure of other provisions [line items]
Carrying value of pre-existing decommissioning liabilities		$ 11
Bottom of range
Disclosure of other provisions [line items]
Expected settlement of decommissioning liabilities	250
Top of range
Disclosure of other provisions [line items]
Expected settlement of decommissioning liabilities	$ 300

XML

Decommissioning Liabilities - Summary of Decommissioning Provision (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Provision for decommissioning, restoration and rehabilitation costs [abstract]
Beginning balance	$ 3,906	$ 1,248
Liabilities Incurred	22	30
Liabilities Acquired (Note 5) (1)	48	2,856
Liabilities Settled	(215)	(144)
Liabilities Divested (Note 5) (1)	(89)	(140)
Change in Estimated Future Cash Flows	693	(472)
Change in Discount Rates	(980)	450
Unwinding of Discount on Decommissioning Liabilities (Note 7)	176	199
Transfers to Liabilities Related to Assets Held for Sale (Note 18)	0	(128)
Exchange Rate Movements and Other	(2)	7
Ending balance	$ 3,559	$ 3,906

XML

Decommissioning Liabilities - Summary of Changes to the Credit-Adjusted Risk-Free Rate or the Inflation Rate Impact on the Decommissioning Liabilities (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of other provisions [line items]
Credit-adjusted risk-free rate, sensitivity range	1.00%
Inflation rate, sensitivity range	1.00%
One percent increase
Disclosure of other provisions [line items]
Credit-adjusted risk-free rate	$ (319)	$ (623)
Inflation rate	419	873
One percent decrease
Disclosure of other provisions [line items]
Credit-adjusted risk-free rate	419	875
Inflation rate	$ (320)	$ (625)

XML

Other Liabilities - Summary of Other Liabilities (Detail) - CAD ($) $ in Millions		12 Months Ended
	May 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Disclosure of non-current liabilities [Line Items]
Pension and Other Post-Employment Benefit Plan		$ 201	$ 288
Provision for West White Rose Expansion Project (1)		204	259
Provisions for Onerous and Unfavourable Contracts		95	99
Employee Long-Term Incentives		245	74
Drilling Provisions		31	56
Deferred Revenue		45	41
Other (2)		221	112
Other Liabilities		1,042	$ 929
Adjustment to West White Rose expansion project provision	$ 47
West white rose expansion project, expected draw down to provision		58
RVO included in other liabilities, net		101
RVO included in other liabilities, gross		1,100
RINs included in other liabilities, gross		$ 1,000
West White Rose Expansion Project
Disclosure of non-current liabilities [Line Items]
Percentage of working interest acquired	1250.00%

XML

Pensions and Other Post-Employment Benefits - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)
Pension Benefits
Disclosure of defined benefit plans [line items]
Weighted average duration	14 years
Percentage of employees contribution under pension plan	4.00%
Employer contribution	$ 10
OPEB
Disclosure of defined benefit plans [line items]
Weighted average duration	14 years
Estimate of contributions expected to be paid to plan for next annual reporting period	$ 10

XML

Pensions and Other Post-Employment Benefits - Summary of Defined Benefit and OPEB Plan Obligation and Funded Status (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Disclosure of net defined benefit liability (asset) [line items]
Current Service Costs	$ 16	$ 16	$ 13
Past Service Costs - Curtailment and Plan Amendments	0	(1)	0
Interest Costs (2)	(3)	(3)	(3)
Re-measurements:
(Gains) Losses From Experience Adjustments	1	4	1
(Gains) Losses From Changes in Demographic Assumptions	0	(1)	0
(Gains) Losses From Changes in Financial Assumptions	(64)	(18)	15
Return on Plan Assets (Excluding Interest Income)	(26)	9	5
Pension and OPEB (Liability) (3)	(25)	(61)
Pension Benefits | Defined Benefit Obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined Benefit Obligation, Beginning of Year	220	188
Plan Acquisition Upon the Arrangement (1)	0	41
Current Service Costs	16	16
Interest Costs (2)	(7)	(6)
Benefits Paid	(12)	(17)
Plan Participant Contributions	2	2
Re-measurements:
(Gains) Losses From Experience Adjustments	1	4
(Gains) Losses From Changes in Demographic Assumptions	0	(1)
(Gains) Losses From Changes in Financial Assumptions	(64)	(18)
Exchange Rate Movements and Other	2	0
Defined Benefit Obligation, End of Year	172	220	188
Pension Benefits | Plan Assets
Disclosure of net defined benefit liability (asset) [line items]
Fair Value of Plan Assets, Beginning of Year	159	117
Plan Acquisition Upon the Arrangement (1)	0	32
Interest Costs (2)	4	3
Employer Contributions	16	9
Benefits Paid	(10)	(13)
Plan Participant Contributions	2	2
Re-measurements:
Return on Plan Assets (Excluding Interest Income)	(26)	9
Exchange Rate Movements and Other	2	0
Fair Value of Plan Assets, End of Year	147	159	117
OPEB
Disclosure of net defined benefit liability (asset) [line items]
Current Service Costs	8	9	1
Past Service Costs - Curtailment and Plan Amendments	0	(3)	0
Interest Costs (2)	(7)	(6)	0
Re-measurements:
(Gains) Losses From Experience Adjustments	(2)	10	(2)
(Gains) Losses From Changes in Demographic Assumptions	0	(3)	0
(Gains) Losses From Changes in Financial Assumptions	(57)	(30)	1
Return on Plan Assets (Excluding Interest Income)	0	0	0
Pension and OPEB (Liability) (3)	(174)	(225)
OPEB | Defined Benefit Obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined Benefit Obligation, Beginning of Year	225	20
Plan Acquisition Upon the Arrangement (1)	0	224
Current Service Costs	8	9
Interest Costs (2)	(7)	(6)
Benefits Paid	(8)	(8)
Plan Participant Contributions	0	0
Re-measurements:
(Gains) Losses From Experience Adjustments	(2)	10
(Gains) Losses From Changes in Demographic Assumptions	0	(3)
(Gains) Losses From Changes in Financial Assumptions	(57)	(30)
Exchange Rate Movements and Other	1	0
Defined Benefit Obligation, End of Year	174	225	20
OPEB | Plan Assets
Disclosure of net defined benefit liability (asset) [line items]
Fair Value of Plan Assets, Beginning of Year	0	0
Plan Acquisition Upon the Arrangement (1)	0	0
Interest Costs (2)	0	0
Employer Contributions	8	3
Benefits Paid	(8)	(3)
Plan Participant Contributions	0	0
Re-measurements:
Return on Plan Assets (Excluding Interest Income)	0	0
Exchange Rate Movements and Other	0	0
Fair Value of Plan Assets, End of Year	$ 0	$ 0	$ 0

XML

Pensions and Other Post-Employment Benefits - Summary of Pension and OPEB Costs (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Disclosure of defined benefit plans [line items]
Current Service Costs	$ 16	$ 16	$ 13
Past Service Costs - Curtailments and Plan Amendments	0	(1)	0
Interest Costs (2)	3	3	3
Re-measurements:
Return on Plan Assets (Excluding Interest Income)	26	(9)	(5)
(Gains) Losses From Experience Adjustments	1	4	1
(Gains) Losses From Changes in Demographic Assumptions	0	(1)	0
(Gains) Losses From Changes in Financial Assumptions	(64)	(18)	15
Defined Benefit Plan Cost (Recovery)	(18)	(6)	27
Defined Contribution Plan Cost (1)	72	68	22
Total Plan Cost	54	62	49
OPEB
Disclosure of defined benefit plans [line items]
Current Service Costs	8	9	1
Past Service Costs - Curtailments and Plan Amendments	0	(3)	0
Interest Costs (2)	7	6	0
Re-measurements:
Return on Plan Assets (Excluding Interest Income)	0	0	0
(Gains) Losses From Experience Adjustments	(2)	10	(2)
(Gains) Losses From Changes in Demographic Assumptions	0	(3)	0
(Gains) Losses From Changes in Financial Assumptions	(57)	(30)	1
Defined Benefit Plan Cost (Recovery)	(44)	(11)	0
Defined Contribution Plan Cost (1)	0	0	0
Total Plan Cost	$ (44)	$ (11)	$ 0

XML

Pensions and Other Post-Employment Benefits - Target Allocation (Details)	Dec. 31, 2022
Canadian Plan | Bottom of range | Equity Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	25.00%
Canadian Plan | Bottom of range | Fixed Income Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	20.00%
Canadian Plan | Bottom of range | Real Estate Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	0.00%
Canadian Plan | Bottom of range | Listed Infrastructure Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	0.00%
Canadian Plan | Bottom of range | Emerging Market Debt Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	0.00%
Canadian Plan | Bottom of range | Cash and Cash Equivalents
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	0.00%
Canadian Plan | Top of range | Equity Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	75.00%
Canadian Plan | Top of range | Fixed Income Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	50.00%
Canadian Plan | Top of range | Real Estate Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	15.00%
Canadian Plan | Top of range | Listed Infrastructure Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	10.00%
Canadian Plan | Top of range | Emerging Market Debt Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	10.00%
Canadian Plan | Top of range | Cash and Cash Equivalents
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	10.00%
US Plan | Bottom of range | Equity Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	21.00%
US Plan | Bottom of range | Fixed Income Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	55.00%
US Plan | Top of range | Equity Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	51.00%
US Plan | Top of range | Fixed Income Funds
Disclosure of defined benefit plans [line items]
Target Asset Allocation Percentage	74.00%

XML

Pensions and Other Post-Employment Benefits - Summary of Fair Value of the Plan Assets (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of defined benefit plans [line items]
Equity Funds	$ 68	$ 77
Fixed Income Funds	50	54
Real Estate Funds	9	9
Listed Infrastructure Funds	7	8
Emerging Market Debt Funds	5	8
Cash and Cash Equivalents	7	2
Non-Invested Assets	1	1
Total Fair Value of DB Pension Plan Assets	$ 147	$ 159

XML

Pensions and Other Post-Employment Benefits - Summary of Principal Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Expenses (Detail) - yr	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Disclosure Of Actuarial Assumptions [Line Items]
Discount Rate	5.12%	2.95%	2.50%
Future Salary Growth Rate	4.05%	4.03%	3.97%
Average Longevity (years)	88.4	88.3	88.3
OPEB
Disclosure Of Actuarial Assumptions [Line Items]
Discount Rate	5.13%	2.98%	2.50%
Future Salary Growth Rate		4.94%	4.94%
Average Longevity (years)	88.4	88.3	88.2
Health Care Cost Trend Rate	5.24%	5.64%	6.00%

XML

Pensions and Other Post-Employment Benefits - Sensitivity of Defined Benefit and OPEB Obligation to Changes in Relevant Actuarial Assumptions (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Discount Rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase	$ (43)	$ (59)
Decrease	51	76
Future Salary Growth Rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase	3	4
Decrease	(3)	(4)
Health Care Cost Trend Rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase	19	26
Decrease	(17)	(20)
One Year Change in Assumed Life Expectancy
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase	10	4
Decrease	$ (10)	$ (4)

XML

Share Capital and Warrants - Narrative (Details) - CAD ($) $ / shares in Units, $ in Millions	2 Months Ended	3 Months Ended								12 Months Ended
	Feb. 13, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Nov. 07, 2022	Nov. 04, 2021
Disclosure of classes of share capital [Line Items]
Maximum percentage of preferred stock upon issuance or outstanding of common stock										20.00%
NCIB, shares redeemed, amount										$ 2,530.0	$ 265.0	$ 0.0
NCIB, reduction to contributed surplus										$ 1,571.0	$ 120.0
Preference shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		36,000,000				36,000,000				36,000,000	36,000,000
Issued capital		$ 519.0				$ 519.0				$ 519.0	$ 519.0
Dividend Rate		5.05%	3.21%	2.35%	1.86%	1.92%	1.84%	1.80%	1.84%
Preference shares | Series 1 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		10,740,000								10,740,000
Dividend Rate										2.58%
Preference shares | Series 1 First Preferred Shares | Government of Canada Bond
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		173.00%								173.00%
Preference shares | Series 2 First Preferred Shares (1)
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		1,260,000								1,260,000
Dividend Rate										5.86%
Preference shares | Series 2 First Preferred Shares (1) | 90-Day Government of Canada Treasury Bills
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		173.00%								173.00%
Preference shares | Series 3 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		10,000,000								10,000,000
Dividend Rate										4.69%
Preference shares | Series 3 First Preferred Shares | Government of Canada Bond
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		313.00%								313.00%
Preference shares | Series 5 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		8,000,000								8,000,000
Dividend Rate										4.59%
Preference shares | Series 5 First Preferred Shares | Government of Canada Bond
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		357.00%								357.00%
Preference shares | Series 7 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		6,000,000								6,000,000
Dividend Rate										3.94%
Preference shares | Series 7 First Preferred Shares | Government of Canada Bond
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		352.00%								352.00%
Preference shares | First Preferred Shares
Disclosure of classes of share capital [Line Items]
Redeemable preferred shares, conversion term										5 years
Redeemable preferred shares, price per share										$ 25.00
Preference shares | Series 1 And 2 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Redeemable preferred shares, conversion term										5 years
Preference shares | Series 3 and 4 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Redeemable preferred shares, conversion term										5 years
Preference shares | Series 5 and 6 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Redeemable preferred shares, conversion term										5 years
Preference shares | Series 7 and 8 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Redeemable preferred shares, conversion term										5 years
Preference shares | Series 1, 3, 5, 7 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Redeemable preferred shares, conversion term										5 years
Preference shares | Series 4 First Preferred Shares | 90-Day Government of Canada Treasury Bills
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		313.00%								313.00%
Preference shares | Series 6 First Preferred Shares | 90-Day Government of Canada Treasury Bills
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		357.00%								357.00%
Preference shares | Series 8 First Preferred Shares | 90-Day Government of Canada Treasury Bills
Disclosure of classes of share capital [Line Items]
Dividend rate, basis spread		352.00%								352.00%
Preference shares | Series 2,4,6,8 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Redeemable preferred shares, price per share										$ 25.50
Second Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		0				0				0	0
Common shares
Disclosure of classes of share capital [Line Items]
NCIB, reduction to contributed surplus										$ 1,571.0	$ 120.0
Purchase of Common Shares under NCIBs										112,489,000	17,026,000
Shares outstanding (in shares)		1,909,190,000				2,001,211,000				1,909,190,000	2,001,211,000	1,228,870,000
Issued capital		$ 16,320.0				$ 17,016.0				$ 16,320.0	$ 17,016.0	$ 11,040.0
Common shares | Original NCIB
Disclosure of classes of share capital [Line Items]
NCIB, shares authorized for repurchase (in shares)														146,500,000
NCIB, shares repurchased, price per share (in CAD per share)										$ 22.49	$ 15.56
NCIB, shares redeemed, amount										$ 2,500.0	$ 265.0
NCIB, reduction to contributed surplus										$ 1,600.0	$ 120.0
Common shares | Renewed NCIB
Disclosure of classes of share capital [Line Items]
NCIB, shares authorized for repurchase (in shares)													136,700,000
Common shares | Renewed NCIB | Potential ordinary share transactions
Disclosure of classes of share capital [Line Items]
NCIB, shares authorized for repurchase (in shares)	123,800,000
NCIB, shares redeemed, amount	$ 36.8
Purchase of Common Shares under NCIBs	1,400,000
Common Share Warrants
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)		55,720,000				65,119,000				55,720,000	65,119,000	0
Issued capital		$ 184.0				$ 215.0				$ 184.0	$ 215.0	$ 0.0
Exercise price of warrants issued (in CAD per share)										$ 6.54
Stock Option Plan
Disclosure of classes of share capital [Line Items]
Shares available for future issuance (in shares)		43,000,000				30,000,000				43,000,000	30,000,000

XML

Share Capital and Warrants - Issued and Outstanding - Common Shares (Detail) - Common shares - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Number of Common Shares
Outstanding, Beginning of Year	2,001,211	1,228,870
Issued Under the Arrangement, Net of Issuance Costs (Note 5)	0	788,518
Issued Upon Exercise of Warrants	9,399	314
Issued Under Stock Option Plans	11,069	535
Purchase of Common Shares under NCIBs	(112,489)	(17,026)
Outstanding, End of Year	1,909,190	2,001,211
Amount
Outstanding, Beginning of Year	$ 17,016	$ 11,040
Issued Under the Arrangement, Net of Issuance Costs (Note 5)	0	6,111
Issued Upon Exercise of Warrants	93	3
Issued Under Stock Option Plans	170	7
Purchase of Common Shares under NCIBs	(959)	(145)
Outstanding, End of Year	$ 16,320	$ 17,016

XML

Share Capital and Warrants - Issued and Outstanding - Preferred Shares (Details) - Preference shares - shares shares in Thousands	3 Months Ended									12 Months Ended
	Mar. 30, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2022
Disclosure of classes of share capital [Line Items]
Dividend Rate		5.05%	3.21%	2.35%	1.86%	1.92%	1.84%	1.80%	1.84%
Shares outstanding (in shares)		36,000				36,000				36,000
Preferred Stock Dividend Transactions
Disclosure of classes of share capital [Line Items]
Dividend Rate	5.86%
Series 1 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Dividend Rate										2.58%
Shares outstanding (in shares)		10,740								10,740
Series 2 First Preferred Shares (1)
Disclosure of classes of share capital [Line Items]
Dividend Rate										5.86%
Shares outstanding (in shares)		1,260								1,260
Series 3 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Dividend Rate										4.69%
Shares outstanding (in shares)		10,000								10,000
Series 5 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Dividend Rate										4.59%
Shares outstanding (in shares)		8,000								8,000
Series 7 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Dividend Rate										3.94%
Shares outstanding (in shares)		6,000								6,000

XML

Share Capital and Warrants - Issued and Outstanding - Warrants (Details) - Common Share Warrants - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Number of Warrants
Outstanding, Beginning of Year	65,119	0
Issued Under the Arrangement, Net of Issuance Costs (Note 5)	0	65,433
Issued Upon Exercise of Warrants	(9,399)	(314)
Outstanding, End of Year	55,720	65,119
Amount
Outstanding, Beginning of Year	$ 215	$ 0
Issued Under the Arrangement, Net of Issuance Costs (Note 5)	0	216
Issued Upon Exercise of Warrants	(31)	(1)
Outstanding, End of Year	$ 184	$ 215

XML

Share Capital and Warrants - Schedule of Paid in Surplus Includes Stock Based Compensation Expense (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of reserves within equity [line items]
Beginning Balance	$ 4,284	$ 4,391
Stock-Based Compensation Expense	373	159	$ 49
Purchase of Common Shares Under NCIBs	(1,571)	(120)
Common Shares Issued on Exercise of Stock Options	(32)	(1)
Ending Balance	2,691	4,284	4,391
NSRs and NCIB
Disclosure of reserves within equity [line items]
Stock-Based Compensation Expense	10	14
Retained Earnings Prior to Ovintiv Split
Disclosure of reserves within equity [line items]
Beginning Balance	4,086	4,086
Purchase of Common Shares Under NCIBs	0	0
Common Shares Issued on Exercise of Stock Options	0	0
Ending Balance	4,086	4,086	4,086
Retained Earnings Prior to Ovintiv Split | NSRs and NCIB
Disclosure of reserves within equity [line items]
Stock-Based Compensation Expense	0	0
Stock-Based Compensation
Disclosure of reserves within equity [line items]
Beginning Balance	318	305
Purchase of Common Shares Under NCIBs	0	0
Common Shares Issued on Exercise of Stock Options	(32)	(1)
Ending Balance	296	318	305
Stock-Based Compensation | NSRs and NCIB
Disclosure of reserves within equity [line items]
Stock-Based Compensation Expense	10	14
Common shares
Disclosure of reserves within equity [line items]
Beginning Balance	120	0
Purchase of Common Shares Under NCIBs	(1,571)	(120)
Common Shares Issued on Exercise of Stock Options	0	0
Ending Balance	1,691	120	$ 0
Common shares | NSRs and NCIB
Disclosure of reserves within equity [line items]
Stock-Based Compensation Expense	$ 0	$ 0

XML

Accumulated Other Comprehensive Income (Loss) - Schedule of Accumulated Other Comprehensive Income (Loss) (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	$ 684	$ 775
Other Comprehensive Income (Loss), Before Tax	811	(82)
Income Tax (Expense) Recovery	(25)	(9)
Ending balance	1,470	684
Pension and Other Post-Retirement Benefits
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	28	(10)
Other Comprehensive Income (Loss), Before Tax	96	47
Income Tax (Expense) Recovery	(25)	(9)
Ending balance	99	28
Private Equity Instruments
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	27	27
Other Comprehensive Income (Loss), Before Tax	2	0
Income Tax (Expense) Recovery	0	0
Ending balance	29	27
Foreign Currency Translation Adjustment
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	629	758
Other Comprehensive Income (Loss), Before Tax	713	(129)
Income Tax (Expense) Recovery	0	0
Ending balance	$ 1,342	$ 629

XML

Stock-Based Compensation Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2022 CAD ($) Plan shares plans $ / shares	Dec. 31, 2021 CAD ($)
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of deferred share unit plans | plans	2
Liabilities from share based payment	$ 162,000,000	$ 317,000,000
Net settlement rights
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Options expiration term	7 years
Weighted average unit fair value of granted	$ 19.94
Weighted average exercise price, exercised (in dollars per share) | $ / shares	$ 12.77
Number of units exercised (in shares) | shares	11,599,000
Cenovus Replacement Stock Options
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Liabilities from share based payment	$ 42,000,000	30,000,000
Cenovus Replacement Stock Options | Settled for common shares
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in shares) | shares	103,000
Weighted average exercise price of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in dollars per share) | $ / shares	$ 14.98
Common shares issued in exercise of other equity instruments (in shares) | shares	81,000
Cenovus Replacement Stock Options | Settled for cash
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of other equity instruments exercised or vested in share-based payment arrangement, settled for cash | shares	6,042,000
Weighted average exercise price, exercised (in dollars per share) | $ / shares	$ 16.57
PSUs
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Liabilities from share based payment	$ 216,000,000	61,000,000
Intrinsic value of vested	$ 0
RSUs
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Award vesting term	3 years
Liabilities from share based payment	$ 109,000,000	53,000,000
Intrinsic value of vested	$ 0
DSUs
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Award vesting term	3 years
Liabilities from share based payment	$ 40,000,000	$ 20,000,000
DSUs | Bottom of range
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of deferred share unit plans | Plan	0
DSUs | Top of range
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of deferred share unit plans | Plan	2
DSUs Option One
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	0.00%
DSUs Option Two
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	25.00%
DSUs Option Three
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	5000.00%
DSUs Option Four
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	7500.00%
Deferred Share Units Option Five
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	100.00%
Later than one year
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of options exercisable	30.00%
3 Years
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of options exercisable	30.00%

XML

Stock-Based Compensation Plans - Summary of Assumptions Used to Determine Fair Value of Options Granted (Detail) - Net settlement rights	12 Months Ended
	Dec. 31, 2022 yr
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Risk-Free Interest Rate	1.84%
Expected Dividend Yield	0.72%
Expected Volatility	24.72%
Expected Life (years)	5.75

XML

Stock-Based Compensation Plans - Summary of Stock Option Activity and Related Information (Detail) shares in Thousands	12 Months Ended
	Dec. 31, 2022 shares $ / shares
Net settlement rights
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of options outstanding, beginning of period (in shares)	27,233
Options granted (in shares)	(2,031)
Options exercised (in shares)	(11,599)
Options forfeited (in shares)	(258)
Options expired (in shares)	(3,058)
Number of options outstanding, ending period (in shares)	14,349
Weighted average exercised price, outstanding, beginning of year (in dollars per share) | $ / shares	$ 13.06
Weighted average exercise price, granted (in dollars per share) | $ / shares	19.94
Weighted average exercise price, exercised (in dollars per share) | $ / shares	12.77
Weighted average exercise price, forfeited (in dollars per share) | $ / shares	9.75
Weighted average exercise price, expired (in dollars per share) | $ / shares	22.25
Weighted average exercised price, outstanding, end of year (in dollars per share) | $ / shares	$ 12.38
Cenovus Replacement Stock Options
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of options outstanding, beginning of period (in shares)	12,256
Options granted (in shares)	(6,145)
Options forfeited (in shares)	(186)
Options expired (in shares)	(2,458)
Number of options outstanding, ending period (in shares)	3,467
Weighted average exercised price, outstanding, beginning of year (in dollars per share) | $ / shares	$ 15.21
Weighted average exercise price, granted (in dollars per share) | $ / shares	16.12
Weighted average exercise price, forfeited (in dollars per share) | $ / shares	15.85
Weighted average exercise price, expired (in dollars per share) | $ / shares	20.59
Weighted average exercised price, outstanding, end of year (in dollars per share) | $ / shares	$ 9.99
PSUs
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share units, outstanding, beginning of year (in shares)	7,163
Granted (in shares)	3,226
Exercised (in shares)	(1,413)
Cancelled (in shares)	(465)
United in lieu of dividends (in shares)	167
Number of share units, outstanding, end of year (in shares)	8,678
RSUs
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share units, outstanding, beginning of year (in shares)	6,025
Granted (in shares)	3,161
Exercised (in shares)	(2,230)
Cancelled (in shares)	(430)
United in lieu of dividends (in shares)	129
Number of share units, outstanding, end of year (in shares)	6,655
DSUs
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share units, outstanding, beginning of year (in shares)	1,256
Granted (in shares)	316
United in lieu of dividends (in shares)	30
Redeemed (in shares)	(257)
Number of share units, outstanding, end of year (in shares)	1,506
DSUs | Director
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Granted (in shares)	161

XML

Stock-Based Compensation Plans - Summary of Options Outstanding and Exercisable by Range of Exercise Price (Detail) shares in Thousands	12 Months Ended
	Dec. 31, 2022 shares $ / shares	Dec. 31, 2021 shares $ / shares
Net settlement rights
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	14,349	27,233
Weighted Average Remaining Contractual Life	4 years 3 months 18 days
Weighted Average Exercise Price	$ 12.38	$ 13.06
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	6,673
Weighted Average Exercise Price	$ 12.42
Net settlement rights | 5.00 to 9.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	5,234
Weighted Average Remaining Contractual Life	4 years 10 months 17 days
Weighted Average Exercise Price	$ 8.76
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	1,474
Weighted Average Exercise Price	$ 8.94
Net settlement rights | 5.00 to 9.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	5.00
Net settlement rights | 5.00 to 9.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 9.99
Net settlement rights | 10.00 to 14.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	6,229
Weighted Average Remaining Contractual Life	3 years 9 months 18 days
Weighted Average Exercise Price	$ 12.01
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	4,280
Weighted Average Exercise Price	$ 12.13
Net settlement rights | 10.00 to 14.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	10.00
Net settlement rights | 10.00 to 14.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 14.99
Net settlement rights | 15.00 to 19.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	2,834
Weighted Average Remaining Contractual Life	4 years 3 months 3 days
Weighted Average Exercise Price	$ 19.71
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	919
Weighted Average Exercise Price	$ 19.36
Net settlement rights | 15.00 to 19.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	15.00
Net settlement rights | 15.00 to 19.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 19.99
Net settlement rights | 20.00 to 24.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	52
Weighted Average Remaining Contractual Life	6 years 8 months 8 days
Weighted Average Exercise Price	$ 22.37
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	0
Weighted Average Exercise Price	$ 0
Net settlement rights | 20.00 to 24.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	20.00
Net settlement rights | 20.00 to 24.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 24.99
Cenovus Replacement Stock Options
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	3,467	12,256
Weighted Average Remaining Contractual Life	1 year 3 months
Weighted Average Exercise Price	$ 9.99	$ 15.21
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	2,079
Weighted Average Exercise Price	$ 14.21
Cenovus Replacement Stock Options | 3.00 to 4.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	2,065
Weighted Average Remaining Contractual Life	1 year 7 months 17 days
Weighted Average Exercise Price	$ 3.54
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	742
Weighted Average Exercise Price	$ 3.54
Cenovus Replacement Stock Options | 3.00 to 4.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	3.00
Cenovus Replacement Stock Options | 3.00 to 4.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 4.99
Cenovus Replacement Stock Options | 5.00 to 9.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	124
Weighted Average Remaining Contractual Life	1 year 4 months 9 days
Weighted Average Exercise Price	$ 6.06
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	59
Weighted Average Exercise Price	$ 6.06
Cenovus Replacement Stock Options | 5.00 to 9.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	5.00
Cenovus Replacement Stock Options | 5.00 to 9.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 9.99
Cenovus Replacement Stock Options | 10.00 to 14.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	14
Weighted Average Remaining Contractual Life	5 months 19 days
Weighted Average Exercise Price	$ 12.88
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	14
Weighted Average Exercise Price	$ 12.88
Cenovus Replacement Stock Options | 10.00 to 14.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	10.00
Cenovus Replacement Stock Options | 10.00 to 14.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 14.99
Cenovus Replacement Stock Options | 15.00 to 19.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	594
Weighted Average Remaining Contractual Life	1 year 14 days
Weighted Average Exercise Price	$ 18.35
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	594
Weighted Average Exercise Price	$ 18.35
Cenovus Replacement Stock Options | 15.00 to 19.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	15.00
Cenovus Replacement Stock Options | 15.00 to 19.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 19.99
Cenovus Replacement Stock Options | 20.00 to 24.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	524
Weighted Average Remaining Contractual Life	2 months 12 days
Weighted Average Exercise Price	$ 21.77
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	524
Weighted Average Exercise Price	$ 21.77
Cenovus Replacement Stock Options | 20.00 to 24.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	20.00
Cenovus Replacement Stock Options | 20.00 to 24.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 24.99
Cenovus Replacement Stock Options | 25.00 to 29.99
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding number (in shares) | shares	146
Weighted Average Remaining Contractual Life	6 months 29 days
Weighted Average Exercise Price	$ 27.88
Number of Stock Options with Associated Net Settlement Rights (in shares) | shares	146
Weighted Average Exercise Price	$ 27.88
Cenovus Replacement Stock Options | 25.00 to 29.99 | Bottom of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	25.00
Cenovus Replacement Stock Options | 25.00 to 29.99 | Top of range
Disclosure of range of exercise prices of outstanding share options [Line Items]
Exercise price of warrants (in dollars per share)	$ 29.99

XML

Stock-Based Compensation Plans - Summary of Stock-Based Compensation (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	$ 373	$ 159	$ 49
Stock-Based Compensation Costs Capitalized	0	8	16
Total Stock-Based Compensation	373	167	65
Stock Options With Associated Net Settlement Rights
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	15	14	11
Cenovus Replacement Stock Options
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	53	26	0
Performance Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	183	56	19
Restricted Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	100	48	23
Deferred Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	$ 22	$ 15	$ (4)

XML

Employee Salaries and Benefit Expenses - Summary of Employee Salaries and Benefit Expenses (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure Of Salaries And Employee Benefits [Abstract]
Salaries, Bonuses and Other Short-Term Employee Benefits	$ 1,246	$ 1,327	$ 605
Post-Employment Benefits	92	89	33
Stock-Based Compensation (Note 34)	373	159	49
Other Incentive Benefits Expense (Recovery)	(9)	201	(4)
Termination Benefits	27	180	9
Employee Salaries and Benefit Expenses	$ 1,729	$ 1,956	$ 692

XML

Related Party Transactions - Summary of Key Management Compensation (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of transactions between related parties [abstract]
Salaries, Director Fees and Other Short-Term Benefits	$ 40	$ 69	$ 21
Post-Employment Benefits	4	4	3
Stock-Based Compensation	140	72	15
Other Incentive Benefits	0	4	1
Termination Benefits	3	3	6
Total compensation paid or payable	$ 187	$ 152	$ 46

XML

Related Party Transactions - Additional Information (Details) - Husky Midstream Limited Partnership - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint venture	35.00%
Revenue from rendering of services, related party transactions	$ 188	$ 243
Purchases of goods, related party transactions	$ 263	$ 284

XML

Financial Instruments - Additional information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / bbl	Aug. 31, 2022 CAD ($)	Jun. 13, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about financial instruments [line items]
Total Debt	$ 8,691			$ 12,385
Cash collateral for risk management contracts price change	$ 211			114
Discounted credit adjusted risk free rate	5.20%
Conoco Phillips Company and certain of its subsidiaries
Disclosure of detailed information about financial instruments [line items]
Proportion of ownership interest in joint operation	5000.00%
Sunrise Oil Sands Partnership
Disclosure of detailed information about financial instruments [line items]
Estimated fair value of contingent payment	$ 419			0
Initial Recognition		$ 600	$ 600
WCS Forward Prices
Disclosure of detailed information about financial instruments [line items]
Average forward price for Western Canadian Select Crude Oil for the remaining term (in CAD per barrel) | $ / bbl	72.79
WTI Option Implied Volatility
Disclosure of detailed information about financial instruments [line items]
Average implied volatility contingent payment percentage	4420.00%
U.S. to Canadian Dollar Foreign Exchange Average Rate Volatility Contingent Payment
Disclosure of detailed information about financial instruments [line items]
Average implied volatility contingent payment percentage	760.00%
Level 2 of fair value hierarchy
Disclosure of detailed information about financial instruments [line items]
Debt, fair value	$ 7,800			$ 13,700

XML

Financial Instruments - Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets (Detail) - Level 3 of fair value hierarchy - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of fair value measurement of assets [Line Items]
Fair value, beginning of year	$ 53	$ 52
Acquisition (Note 5)	0	1
Increase (decrease) in fair value measurement, assets	2	0
Fair value, end of year	$ 55	$ 53

XML

Financial Instruments - Summary of Unrealized Risk Management Positions (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Net Asset (Liability)	$ 46	$ (68)	$ (53)
Power Swap Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Net Asset (Liability)	(6)
Renewable Power Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Net Asset (Liability)	90
Level 2 of fair value hierarchy
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Net Asset (Liability)	(44)	(68)
Level 2 of fair value hierarchy | Commodity price risk
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	93	48
Risk Management Liability	47	116
Risk Management Net Asset (Liability)	46	(68)
Level 2 of fair value hierarchy | Commodity price risk | Crude Oil, Natural Gas, Condensate and Refined Products
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	2	46
Risk Management Liability	40	116
Risk Management Net Asset (Liability)	(38)	(70)
Level 2 of fair value hierarchy | Commodity price risk | Power Swap Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	1	0
Risk Management Liability	7	0
Risk Management Net Asset (Liability)	(6)	0
Level 2 of fair value hierarchy | Commodity price risk | Renewable Power Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	90	0
Risk Management Liability	0	0
Risk Management Net Asset (Liability)	90	0
Level 2 of fair value hierarchy | Currency risk | Exchange Rate Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	0	2
Risk Management Liability	0	0
Risk Management Net Asset (Liability)	$ 0	$ 2

XML

Financial Instruments - Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair value of derivative financial instruments net	$ 46	$ (68)	$ (53)
Level 2 of fair value hierarchy
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair value of derivative financial instruments net	(44)	(68)
Level 3 of fair value hierarchy [member]
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair value of derivative financial instruments net	$ 90	$ 0

XML

Financial Instruments - Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about financial instruments [abstract]
Fair Value of Contracts, Beginning of Year	$ (68)	$ (53)
Acquisition (Note 5)	0	(14)
Change in Fair Value of Contracts in Place at Beginning of Year	(5)	0
Change in Fair Value of Contracts Entered Into During the Year	(1,641)	(995)
Fair Value of Contracts Realized During the Year	1,762	993
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	(2)	1
Fair Value of Contracts, End of Year	$ 46	$ (68)

XML

Financial Instruments - Summary of Offsetting Risk Management Positions (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Gross Amount, Risk Management Asset	$ 153	$ 263
Amount Offset, Risk Management Asset	(60)	(215)
Net Amount per Consolidated Financial Statements, Risk Management Asset	93	48
Gross Amount, Risk Management Liabilities	107	331
Amount Offset, Risk Management Liabilities	(60)	(215)
Net Amount per Consolidated Financial Statements, Risk Management Liabilities	47	116
Gross Amount, Risk Management Net	46	(68)
Amount Offset, Risk Management Net	0	0
Net Amount per Consolidated Financial Statements, Risk Management Net	$ 46	$ (68)

XML

Financial Instruments - Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / bbl $ / $	Dec. 31, 2021 CAD ($) $ / bbl
WCS Forward Prices
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Sensitivity Price Range | $ / bbl	10.00	5.00
Increase in volatility	$ (68)	$ (45)
Decrease in volatility	157	$ 45
WTI Option Implied Volatility
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Increase in volatility	(1)
Decrease in volatility	$ 4
Sensitivity Range	10.00%
Canadian to U.S. Dollar Foreign Exchange Rate Option Implied Volatility
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Increase in volatility	$ 0
Decrease in volatility	$ 0
Sensitivity Range | $ / $	5.00%

XML

Financial Instruments - Summary of Earnings Impact of (Gain) Loss from Risk Management Positions (Detail) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Disclosure of detailed information about financial instruments [line items]
(Gain) Loss on Risk Management		$ 1,636	$ 995	[1]	$ 308	[1]
Net realized loss on crude oil contracts	$ 467
Realized (Gain) Loss
Disclosure of detailed information about financial instruments [line items]
(Gain) Loss on Risk Management		1,762	993		252
Unrealized (Gain) Loss
Disclosure of detailed information about financial instruments [line items]
(Gain) Loss on Risk Management		$ (126)	$ 2		$ 56

[1] See Note 3X for revisions to prior period results.

XML

Risk Management - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)	Oct. 07, 2021 USD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Fair value of derivative financial instruments net	$ 46,000,000		$ (68,000,000)			$ (53,000,000)
Notional value				$ 7,400
Interest rate sensitivity floating rate debt	$ 1,000,000		1,000,000
Percentage of accounts receivable outstanding, less than 60 days	99.00%	99.00%
Target Net Debt to Adjusted EBITDA Ratio	1.0
Cash and cash equivalents	$ 4,524,000,000		2,873,000,000			$ 378,000,000	$ 186,000,000
Debt offering, maximum amount		$ 4,700			$ 5,000
Long-Term Debt
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value	8,537,000,000		12,113,000,000
U.S. Dollar Denominated Unsecured Notes | Long-Term Debt
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value	6,537,000,000	4,827	9,363,000,000	7,385
U.S. Dollar Denominated Unsecured Notes | 3.80% due September 15, 2023 | Long-Term Debt
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value	0	0	146,000,000	115
U.S. Dollar Denominated Unsecured Notes | 4.00% due April 15, 2024 | Long-Term Debt
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value	0	0	341,000,000	269
WRB Refining LP
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Uncommitted demand facilities	190,000,000	140
Uncommitted Demand Facilities
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Uncommitted demand facilities	1,400,000,000
Top of range | Uncommitted Demand Facilities
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Amount of undrawn facilities for general purposes	1,000,000,000
Liquidity risk | Committed Credit Facility
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Uncommitted demand facilities	$ 5,500,000,000
Liquidity risk | Top of range | Base Shelf Prospectus
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Debt offering, maximum amount		4,700
Interest rate risk
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Changes in interest rate percentage	100.00%
Foreign Exchange Rate Contracts
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value		$ 168		$ 144
Interest rate swap contract
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value	$ 0		$ 0
Trade Receivables | Credit risk
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Average expected credit loss rate	0.40%	0.40%	0.10%	0.10%
Trade Receivables | Credit risk | Investment grade counterparties
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Number of days outstanding for accruals, joint operations, trade receivables and net investment in finance leases	60 days	60 days
Trade Receivables | Credit risk | Investment grade counterparties | Bottom of range
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Percent of accounts receivable held with investment grade counterparties	85.00%	85.00%	94.00%	94.00%
Cross Currency Interest Rate Swap
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value	$ 0		$ 0

XML

Risk Management - Net Fair Value of Risk Management Positions (Detail) $ in Millions	Dec. 31, 2022 CAD ($) $ / barrel MMBbls	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Disclosure of Derivative Financial Instruments [Line Items]
Fair value of derivative financial instruments net	$ 46	$ (68)	$ (53)
Power Swap Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Fair value of derivative financial instruments net	(6)
Renewable Power Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Fair value of derivative financial instruments net	$ 90
WTI Fixed – Sell | Crude Oil and Condensate Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volume | MMBbls	3.2
Weighted Average Price | $ / barrel	80.35
Fair value of derivative financial instruments net	$ 1
WTI Fixed – Buy | Crude Oil and Condensate Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volume | MMBbls	2.3
Weighted Average Price | $ / barrel	79.93
Fair value of derivative financial instruments net	$ 0
Other Financial Positions
Disclosure of Derivative Financial Instruments [Line Items]
Fair value of derivative financial instruments net	$ (39)

XML

Risk Management - Net Fair Value of Risk Management Positions (Parenthetical) (Detail) - Fair value derivative financial instruments	12 Months Ended
	Dec. 31, 2022
Bottom of range
Disclosure of Derivative Financial Instruments [Line Items]
Average contract financial term	1 month
Top of range
Disclosure of Derivative Financial Instruments [Line Items]
Average contract financial term	18 months

XML

Risk Management - Impact of Fluctuating Commodity Prices and Interest Rates on Company's Open Risk Management Positions (Detail) $ in Millions	Dec. 31, 2022 $ / barrel	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 MMcf	Dec. 31, 2022 MWh	Dec. 31, 2022 $ / $	Dec. 31, 2022 $ / $	Dec. 31, 2021 CAD ($) $ / barrel $ / $
Commodity price risk | WCS and Condensate Differential Price (1)
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / barrel	2.50						2.50
Increase		$ 13					$ 4
Decrease		(13)					$ (4)
Commodity price risk | Refined Products
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / barrel	10						5.00
Increase		(2)					$ (2)
Decrease		2					$ 2
Commodity price risk | Natural Gas Basis Price
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | MMcf			0.50
Increase		1
Decrease		(1)
Commodity price risk | Power Commodity Price
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | MWh				20.00
Increase		113
Decrease		(113)
Commodity price risk | Crude Oil Contracts
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / barrel	10.00						5.00
Increase		1					$ (225)
Decrease		(1)					$ 225
Commodity price risk | WCS Alberta Differential Price
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / barrel	5.00
Increase		(1)
Decrease		1
Currency risk | U.S. to Canadian Dollar Exchange Rate
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range					0.05	0.05	0.05
Increase		14					$ 11
Decrease		$ (17)					$ (12)

XML

Risk Management - Impact of Fluctuating Commodity Prices and Interest Rates on Company's Open Risk Management Positions (Detail) - Currency risk $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / $	Dec. 31, 2021 CAD ($) $ / $	Dec. 31, 2022 $ / $
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate	$ 246	$ 372
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate	$ (246)	$ (372)
U.S. to Canadian Dollar Exchange Rate
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range	0.05	0.05	0.05

XML

Risk Management - Undiscounted Cash Outflows Relating to Financial Liabilities (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accounts Payable and Accrued Liabilities
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	$ 6,124	$ 6,353
Accounts Payable and Accrued Liabilities | 1 Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	6,124	6,353
Accounts Payable and Accrued Liabilities | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Accounts Payable and Accrued Liabilities | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Accounts Payable and Accrued Liabilities | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Long-Term Debt
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	14,594	19,664
Long-Term Debt | 1 Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	401	561
Long-Term Debt | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	983	1,608
Long-Term Debt | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	2,014	2,603
Long-Term Debt | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	11,196	14,892
Contingent Payments
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	438	238
Contingent Payments | 1 Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	271	238
Contingent Payments | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	167	0
Contingent Payments | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Contingent Payments | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Lease Liabilities
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	4,657	5,073
Lease Liabilities | 1 Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	426	453
Lease Liabilities | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	746	794
Lease Liabilities | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	596	634
Lease Liabilities | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	2,889	3,192
Short-Term Borrowings
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	115	79
Short-Term Borrowings | 1 Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	115	79
Short-Term Borrowings | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Short-Term Borrowings | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Short-Term Borrowings | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	$ 0	$ 0

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Supplementary Cash Flow Information - Summary of Supplementary Cash Flow Information (Detail) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure Of Supplementary Cash Flow Information [Abstract]
Total Current Assets	$ 12,430	$ 11,988
Total Current Liabilities	8,021	7,305
Working Capital	4,409	4,683
Adjusted working capital	4,700	3,800
Assets Held for Sale	0	1,304
Contingent Payments	263	236
Liabilities Related to Assets Held for Sale	$ 0	$ 186

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Supplementary Cash Flow Information - Non-Cash Working Capital (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure Of Supplementary Cash Flow Information [Line Items]
Accounts Receivable and Accrued Revenues	$ 838	$ (953)	$ 77
Income Tax Receivable	(58)	(1)	(12)
Inventories	(143)	(1,646)	450
Accounts Payable and Accrued Liabilities	(524)	1,645	(338)
Income Tax Payable	1,000	87	(17)
Total Change in Non-Cash Working Capital	1,113	(868)	160
Net Change in Non-Cash Working Capital – Operating Activities	575	(1,227)	198
Net Change in Non-Cash Working Capital – Investing Activities	538	359	(38)
Interest Paid	647	811	381
Interest Received	78	24	5
Income Taxes Paid	$ 723	$ 209	$ 18

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Supplementary Cash Flow Information - Summary of Reconciliation of Liabilities to Cash Flows from Financing Activities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Lease Liabilities, Beginning of Year	$ 2,957	$ 1,757
Changes From Financing Cash Flows:
Issuance of Long-Term Debt	0	1,557	$ 1,326
(Repayment) of Long-Term Debt	(4,149)	(2,870)	(112)
Principal Repayment of Leases	(302)	(300)	(197)
Non-Cash Changes:
Lease Additions	25	110
Lease Modifications	83	22
Lease Termination	(5)	(1)
Other inflows (outflows) of cash, classified as financing activities	2	0	0
Lease Liabilities, End of Year	2,836	2,957	1,757
Common shares
Changes From Financing Cash Flows:
Variable dividends paid on common shares	219	0	0
Dividends Payable
Non-Cash Changes:
Ending balance, debt	9
Dividends Payable | Common shares
Changes From Financing Cash Flows:
Dividends paid	(682)	(176)	(77)
Variable dividends paid on common shares	(219)
Non-Cash Changes:
Base Dividends Declared on Common Shares	682	176	77
Dividends Payable | Preference shares
Changes From Financing Cash Flows:
Dividends paid	(26)	(34)
Non-Cash Changes:
Base Dividends Declared on Common Shares	35	34
Short-Term Borrowings
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance, debt	79	121
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	34	(77)	117
Acquisition (Note 5)		40
Non-Cash Changes:
Exchange Rate Movements and Other	2	(5)	4
Ending balance, debt	115	79	121
Long-Term Debt
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance, debt	12,385	7,441	6,699
Changes From Financing Cash Flows:
(Repayment) of Revolving Long-Term Debt		(350)	(220)
Issuance of Long-Term Debt		1,557	1,326
(Repayment) of Long-Term Debt	(4,149)	(2,870)	(112)
Acquisition (Note 5)		6,602
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	(29)	121	(25)
Finance Costs	(28)	(59)	5
Exchange Rate Movements and Other	512	(57)	(232)
Ending balance, debt	8,691	12,385	7,441
Lease Liabilities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Lease Liabilities, Beginning of Year	2,957	1,757	1,916
Changes From Financing Cash Flows:
Principal Repayment of Leases	(302)	(300)	(197)
Acquisition (Note 5)		1,441
Non-Cash Changes:
Lease Additions	25	110	49
Lease Modifications	83	22	(2)
Lease Re-measurements	7	(4)	(2)
Lease Termination	(5)	(1)	(1)
Exchange Rate Movements and Other	71	(10)	(6)
Transfers to liabilities related to assets held for sale		(58)
Lease Liabilities, End of Year	$ 2,836	$ 2,957	$ 1,757

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Commitments and Contingencies - Future Payments for Commitments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and Storage	$ 21,081	$ 21,570
Product purchases	9,358	10,625
Real Estate	856	908
Obligation to Fund Equity-Accounted Affiliate	623	642
Other Long-Term Commitments (4)	1,080	1,101
Total Payments	32,998	34,846
Transportation commitments	$ 9,100	8,100
Transportation commitments subject to regulatory approval or approved but not yet in service term	20 years
1 Year
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and Storage	$ 1,747	1,677
Product purchases	1,626	1,684
Real Estate	48	44
Obligation to Fund Equity-Accounted Affiliate	92	68
Other Long-Term Commitments (4)	381	436
Total Payments	3,894	3,909
2 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and Storage	2,011	1,958
Product purchases	1,509	1,682
Real Estate	50	43
Obligation to Fund Equity-Accounted Affiliate	105	85
Other Long-Term Commitments (4)	90	83
Total Payments	3,765	3,851
3 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and Storage	1,542	1,853
Product purchases	922	1,593
Real Estate	50	52
Obligation to Fund Equity-Accounted Affiliate	96	99
Other Long-Term Commitments (4)	75	72
Total Payments	2,685	3,669
4 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and Storage	1,416	1,488
Product purchases	922	731
Real Estate	50	54
Obligation to Fund Equity-Accounted Affiliate	96	90
Other Long-Term Commitments (4)	74	63
Total Payments	2,558	2,426
5 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and Storage	1,360	1,350
Product purchases	922	731
Real Estate	54	57
Obligation to Fund Equity-Accounted Affiliate	91	90
Other Long-Term Commitments (4)	65	81
Total Payments	2,492	2,309
Thereafter
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and Storage	13,005	13,244
Product purchases	3,457	4,204
Real Estate	604	658
Obligation to Fund Equity-Accounted Affiliate	143	210
Other Long-Term Commitments (4)	395	366
Total Payments	$ 17,604	$ 18,682

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Commitments and Contingencies - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Aug. 31, 2022	Jun. 13, 2022	Dec. 31, 2021
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Contractual commitments	$ 32,998			$ 34,846
Outstanding letters of credit	490			565
HMLP
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Contractual commitments	2,200			2,600
Sunrise Oil Sands Partnership
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Contingent liabilities recognised in business combination	$ 419			$ 0
Initial Recognition		$ 600	$ 600

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Subsequent Events (Details) - CAD ($) $ in Millions		12 Months Ended
	Aug. 08, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Business Combinations [Abstract]
Goodwill		$ 2,923	$ 3,473	$ 2,272
BP-Husky Refining LLC
Business Combinations [Abstract]
Agreement to purchase remaining ownership	50.00%	50.00%