セノバスエナジーの年次報告

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


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


For the fiscal year ended December 31, 2024			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) 766-2000
(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.

1,824,948,627

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

☐

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

☐

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. 333-275322), Form S-8 (File Nos. 333-163397, 333-251886 and 333-283967), 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, 2024.

(b)Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2024.

(c)Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2024.

(d)Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2024.

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, 2024, 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, 2024, 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, 2024, 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, 2024, 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 Jane E. Kinney and Claude Mongeau, 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: Stephen E. Bradley, Jane E. Kinney, Richard J. Marcogliese and Claude Mongeau.

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, 2024, 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, 2024, 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, 2024, 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, 2024, 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 (Chair), Stephen E. Bradley, Richard J. Marcogliese and Claude Mongeau.

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 20, 2025						/s/ Karamjit S. Sandhar
						Name: Karamjit S. Sandhar
						Title: Executive Vice-President & Chief Financial Officer

EXHIBIT INDEX


Exhibits			Documents
97			Clawback Policy
99.1			Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2024.
99.2			Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2024.
99.3			Consolidated Annual Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2024.
99.4			Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2024.
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
104			Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101)

EX-99.1 2 a2024annualinformationform.htm EX-99.1 Document

Exhibit 99.1

Cenovus Energy Inc.

Annual Information Form

For the Year Ended December 31, 2024

February 19, 2025

(Canadian Dollars)


Annual Information Form
For the year ended December 31, 2024


TABLE OF CONTENTS


CORPORATE STRUCTURE						3
GENERAL DEVELOPMENT OF THE BUSINESS						3
DESCRIPTION OF THE BUSINESS						6
BUSINESS SEGMENTS						6
UPSTREAM						8
OIL SANDS						8
CONVENTIONAL						9
OFFSHORE						9
DOWNSTREAM						11
CANADIAN REFINING						11
U.S. REFINING						12
COMPETITIVE CONDITIONS						14
ENVIRONMENTAL PROTECTION						14
CODE OF BUSINESS CONDUCT AND ETHICS						14
EMPLOYEES						15
RISK FACTORS						15
RESERVES DATA AND OTHER OIL AND GAS INFORMATION						15
DISCLOSURE OF RESERVES DATA						15
DEVELOPMENT OF PROVED AND PROBABLE UNDEVELOPED RESERVES						28
SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA						28
OTHER OIL AND GAS INFORMATION						29
DIVIDENDS						37
DESCRIPTION OF CAPITAL STRUCTURE						37
MARKET FOR SECURITIES						41
DIRECTORS AND EXECUTIVE OFFICERS						44
AUDIT COMMITTEE						48
LEGAL PROCEEDINGS AND REGULATORY ACTIONS						50
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS						50
TRANSFER AGENTS AND REGISTRARS						50
MATERIAL CONTRACTS						51
INTERESTS OF EXPERTS						52
ADDITIONAL INFORMATION						53
ACCOUNTING MATTERS						53
ABBREVIATIONS AND CONVERSIONS						53
FORWARD-LOOKING INFORMATION						54
APPENDIX A — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS						57
APPENDIX B — REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION						58
APPENDIX C — AUDIT COMMITTEE MANDATE						59

In this Annual Information Form (“AIF”), dated February 19, 2025, unless otherwise specified or the context otherwise requires, references to “the Company”, “the Corporation”, “Cenovus”, “we”, “us”, or “our”, means Cenovus Energy Inc., and the subsidiaries of, joint arrangements, and partnership interests held directly or indirectly by, Cenovus Energy Inc. All of the information and statements contained in this AIF are made as at February 19, 2025. 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 on 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 2024 Management’s Discussion and Analysis (“annual 2024 MD&A”). This section of the annual 2024 MD&A is incorporated by reference in this AIF, as well as the risk factors as described in other documents the Company files with securities regulatory authorities in Canada and the United States (“U.S.”) from time to time. Additional information about Cenovus, including our annual 2024 MD&A, annual reports and Form 40-F, are available on SEDAR+ at sedarplus.ca, 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, or otherwise referred to in this AIF, does not form part of this AIF unless expressly incorporated by reference herein.


Cenovus Energy Inc. – 2024 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). 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 and Husky Oil Operations Limited, respectively, by way of 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, 2024, are as follows:


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

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

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, 2024, and (ii) less than 10 percent of the Company’s consolidated revenues for the year ended December 31, 2024. In aggregate, Cenovus’s subsidiaries and partnerships not listed above did not exceed 20 percent of the Company’s total consolidated assets as at December 31, 2024, or total consolidated revenues for the year ended December 31, 2024.



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, 5 and 7 are listed on the TSX. We are one of the largest Canadian-based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the largest Canadian-based refiners and upgraders, with downstream operations in Canada and the 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, natural gas and refined petroleum products in Canada and internationally. Our physically and economically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil price differentials and contribute to our net earnings by capturing value from crude oil, natural gas and NGLs production through to the sale of finished products such as transportation fuels.

See the Business Segments section of this AIF for a description of our operations.


Cenovus Energy Inc. – 2024 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:

2022

•Acquisitions.

◦Sunrise. On August 31, 2022, Cenovus closed the acquisition of the remaining 50 percent interest in Sunrise with 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 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 Inc. (“bp”).

•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, final commissioning activities for the restart of the Superior Refinery commenced in advance of crude introduction in the first quarter of 2023. The refinery was taken out of operation in 2018 following an explosion and fire.

•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 Energy Inc. (“Suncor”).

◦Headwater share sale. On June 8, 2022, Cenovus sold its remaining investment in Headwater Exploration Inc. 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 West Texas Intermediate (“WTI”). Given the strength of its balance sheet and liquidity, the Company determined these programs were no longer required to support financial resilience.

•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 environmental, social and governance (“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 $0.420 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. – 2024 Annual Information Form			4

•Renewal of NCIB. On November 7, 2022, the Company received approval from the TSX to renew the Company’s normal course issuer bid (“NCIB”) program 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 112.5 million common shares.

2023

•Jonathan M. McKenzie appointed President & Chief Executive Officer and elected as Director. Effective April 26, 2023, Jonathan M. McKenzie became Cenovus’s President & Chief Executive Officer and was elected as a Director. On the same date, Alexander J. Pourbaix was appointed as Executive Chair of the Board and Claude Mongeau was appointed Lead Independent Director.

•Toledo Refinery acquisition. On February 28, 2023, Cenovus closed the Toledo Acquisition for net proceeds of US$378 million (C$514 million), providing Cenovus with full ownership and operatorship of the refinery and further integrating Cenovus’s heavy oil production and refining capabilities.

•Safe restart of the Toledo and Superior refineries. Following an incident in September 2022 at the Toledo Refinery which resulted in a temporary shut down, it was safely returned to full operations in June 2023. At the Superior Refinery, the Company safely made significant progress towards a return to full operations. The Company introduced crude oil in the first quarter of 2023 and safely restarted the fluid catalytic cracking unit in early October.

•Increased base dividend. On April 26, 2023, Cenovus increased the Company’s base dividend per common share from $0.105 to $0.140, or $0.560 annually, starting in the second quarter of 2023.

•Warrant purchase. On June 14, 2023, Cenovus purchased and cancelled 45.5 million of the Cenovus Warrants, for a total of $711 million. The purchased warrants were paid in full by December 31, 2023.

•Debt reduction. Cenovus purchased US$1.0 billion in principal of certain unsecured notes due between 2029 and 2047.

•Renewal of NCIB. On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 133.2 million common shares from November 9, 2023, to November 8, 2024. For the year ended December 31, 2023, the Company purchased and cancelled 43.6 million common shares.

2024

•Growth projects.

◦SeaRose floating production, storage and offloading (“FPSO”) vessel. Retrofit work on the SeaRose FPSO which commenced early in 2024 was completed. The vessel returned to the field and was reconnected in November. Production is expected to resume late February 2025.

◦West White Rose. Cenovus achieved mechanical completion of the topsides and concrete gravity structure in the fourth quarter. The project is approximately 88 percent complete, and is on track to deliver first oil in 2026.

◦Narrows Lake tie-back. Cenovus reached mechanical completion on the Narrows Lake pipeline to Christina Lake. First oil from Narrows Lake is expected in 2025.

•Achieved credit rating target. In the first quarter of 2024, the Company achieved its mid-BBB credit rating target with all agencies reflecting Cenovus’s debt reduction and financial policy track record.

•Increased base dividend. On May 1, 2024, Cenovus increased the base dividend per common share from $0.140 to $0.180, or $0.720 annually, starting in the second quarter of 2024.

•Variable dividend. On May 1, 2024, in addition to the Company’s base dividend, the Board declared a variable dividend of $0.135 per common share. The variable dividend was paid on May 31, 2024.

•Achieved Net Debt target. On achieving our Net Debt target, in the third quarter Cenovus increased target returns to shareholders, stewarding to 100 percent of Excess Free Funds Flow, over time.

•Renewal of NCIB. On November 7, 2024, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 127.5 million common shares during the period from November 11, 2024, to November 10, 2025. For the year ended December 31, 2024, the Company purchased and cancelled 55.9 million common shares.

•Preferred share redemption. On December 31, 2024, the Company redeemed all 10.0 million of its series 3 first preferred shares at a price of $25.00 per share, for a total of $250 million.


Cenovus Energy Inc. – 2024 Annual Information Form			5



DESCRIPTION OF THE BUSINESS

BUSINESS SEGMENTS

As at December 31, 2024, 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 in Alberta and British Columbia in the Edson, Clearwater and Rainbow Lake operating areas, in addition to the Northern Corridor, which includes Elmworth and Wapiti. The segment also includes 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 the east coast of Canada and the Asia Pacific region, representing China and the equity-accounted investment in Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia.

Downstream Segments

•Canadian Refining, 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. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment also includes the jointly-owned Wood River and Borger refineries, held through WRB, a jointly-owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.


Cenovus Energy Inc. – 2024 Annual Information Form			6

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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.

For the year ended December 31, 2024, consolidated gross sales were $57.7 billion (2023 – $55.5 billion). The following table summarizes products with external sales that exceeded 15 percent of total external sales.


	2024		2023
	External Sales ($ millions)	Percent of External Sales (percent)	External Sales (1) ($ millions)	Percent of External Sales (percent)
Crude Oil	21,711	38	20,661	37
Gasoline	14,221	25	12,897	23
Distillates (2)	12,116	21	11,364	20

(1)Prior period amounts have been revised to align with current year presentation.

(2)Includes diesel and jet fuel.

Principal markets for Cenovus’s crude oil production from the Oil Sands and Conventional segments includes its refining operations in Lloydminster, Alberta and Saskatchewan; Toledo and Lima in Ohio; and Superior, Wisconsin, in addition to sales at the Hardisty and Edmonton terminals in Alberta, the Burnaby terminal in British Columbia, the U.S. Gulf Coast (“USGC”) and PADD II. The Company’s distillates and gasoline production is largely produced in its U.S. Refining segment. Principal markets include the Ohio Valley and the Upper U.S. Midwest. Principal markets for our non-operated assets include the U.S. Midwest, Colorado, Texas and New Mexico.

Crude oil production from Cenovus’s Oil Sands and Conventional segments is distributed through long-term contracts on third-party pipelines to its refinery operations in Lloydminster; through the Edmonton, Hardisty and PADD II terminals for distribution to its U.S. refineries; and through Flanagan South Pipeline, Keystone Pipeline, Trans Mountain Pipeline expansion project and various other pipelines to third-parties at PADD II, the USGC and Canada’s West Coast. See the U.S. Refining section below for details on the distribution of the Company’s distillates and gasoline production.

Physical and Economic Integration

Cenovus’s integrated upstream and downstream operations help to mitigate the impact of volatility in light-heavy crude oil differentials and contribute to the Company’s net earnings by capturing value from crude oil, natural gas and NGLs production through to the sale of finished products such as transportation fuels.

Bitumen production at the Company’s Oil Sands assets is blended with condensate and butane and used as crude oil feedstock by Cenovus’s refining operations. In addition, condensate is extracted from the blended crude oil in the Company’s Canadian Refining segment and sold back to the Oil Sands operations. Cenovus’s U.S. Refining operations have the capability to process heavy crude oil from its Oil Sands segment and Husky Synthetic Blend (“HSB”) produced at the Lloydminster Upgrader.


Cenovus Energy Inc. – 2024 Annual Information Form			7

UPSTREAM

Oil Sands

As at December 31, 2024, Cenovus held bitumen and heavy oil rights of approximately 1.5 million gross acres (1.5 million net acres), and other petroleum and natural gas rights of approximately 2.8 million gross acres (2.6 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 techniques including cold heavy oil production with sand (“CHOPS”), horizontal and multilateral 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.

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 550 metres, using SAGD technology.

Bitumen production at Foster Creek averaged 196.0 thousand barrels per day in 2024 (2023 – 186.3 thousand barrels per day).

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. Any excess power generated is sold into the Alberta power pool.

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 430 metres, using SAGD technology.

Bitumen production at Christina Lake averaged 234.2 thousand barrels per day in 2024 (2023 – 237.4 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. 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 400 metres. 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 oil from Narrows Lake is expected in 2025.

Sunrise

Cenovus has a 100 percent working interest in Sunrise, located approximately 60 kilometres northeast of Fort McMurray, Alberta. Sunrise produces from the McMurray formation, with a reservoir depth of up to 250 metres, using SAGD technology.

Bitumen production at Sunrise averaged 49.6 thousand barrels per day in 2024 (2023 – 48.9 thousand barrels per day).

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.

Bitumen production at Lloydminster thermal averaged 111.5 thousand barrels per day in 2024 (2023 – 104.1 thousand barrels per day).

Lloydminster Conventional Heavy Oil

Lloydminster conventional heavy oil uses a combination of production techniques including CHOPS, horizontal and multilateral wells, and EOR in the Lloydminster region of Alberta and Saskatchewan.

Heavy oil production averaged 17.6 thousand barrels per day in 2024 (2023 – 16.7 thousand barrels per day) and conventional natural gas production averaged 8.9 MMcf per day in 2024 (2023 – 9.6 MMcf per day).


Cenovus Energy Inc. – 2024 Annual Information Form			8

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 Limited holding a 49 percent interest and CK Infrastructure Holdings Limited holding a 16 percent interest. HMLP has its own board of directors and independent financing that supports both growth projects under construction and planned future expansions.

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 third-party owned export pipelines.

The Hardisty terminal acts as the exclusive blending hub for WCS with a total storage capacity of 4.9 million barrels. The Hardisty terminal is 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 the Conventional segment.

Conventional

Cenovus’s Conventional assets include approximately 3.9 million net acres in Alberta and British Columbia with an average working interest of 85 percent. Operating areas include the Edson, Clearwater, Rainbow Lake and the Northern Corridor, which includes Elmworth and Wapiti, with reservoir depths ranging from 1,000 to 3,200 metres targeting formations within the Cretaceous, Jurassic, Triassic and Devonian geological periods focused primarily on the Cardium and Spirit River. Horizontal drilling is primarily used to unlock the vast resource potential in these areas. Cenovus has processing capacity through various operated and non-operated natural gas facilities, in addition to a 50 percent working interest in a 90-megawatt natural-gas fired cogeneration facility along with multiple field facilities, compressor stations and pipelines. In 2024, Cenovus closed a transaction with Athabasca Oil Corporation to establish the jointly-controlled Duvernay Energy Corporation (“Duvernay”), in which it holds 30 percent equity interest. Cenovus’s equity share in the operating area of Duvernay includes an additional 27.7 thousand acres in Alberta.

In 2024, the Company’s net production from the Conventional assets, excluding Duvernay, averaged 4.9 thousand barrels per day of light crude oil, 21.0 thousand barrels per day of NGLs and 563.8 MMcf per day of conventional natural gas (2023 – 5.9 thousand barrels per day, 21.7 thousand barrels per day and 554.1 MMcf per day, respectively).

In 2024, the Company’s equity share of Duvernay production was 0.6 thousand barrels per day of light oil and condensate, 0.1 thousand barrels per day of NGLs and 1.3 MMcf per day of conventional natural gas.

Offshore

Asia Pacific

China

Liwan Gas Project

The Liwan Gas Project is a deepwater gas project offshore China located approximately 300 kilometres southeast of the Hong Kong Special Administrative Region. 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 (“CNOOC”) through subsidiaries.

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 central platform, the Gaolan Onshore Gas Plant (“OSGP”) and a pipeline from the central platform. The OSGP extracts NGLs, and compresses and transports the natural gas to commercial markets in mainland China.

In 2024, the Company’s net production from the Liwan Gas Project was 199.5 MMcf per day of conventional natural gas and 9.3 thousand barrels per day of NGLs (2023 – 190.6 MMcf per day of conventional natural gas and 8.8 thousand barrels per day of NGLs).


Cenovus Energy Inc. – 2024 Annual Information Form			9

Block 29/34

The Company holds a production sharing contract (“PSC”) for Block 29/34 situated in the South China Sea, adjacent to the Liuhua 34-2 Production Area. Cenovus is the operator of the block during the exploration phase, with a 100 percent working interest. In the event of a commercial discovery, CNOOC may assume a working interest of up to 51 percent during the development and production phase by paying its proportionate share of all development costs.

Block 15/33

The Company holds a PSC for Block 15/33 which is located in the Pearl River Mouth Basin of the South China Sea, about 140 kilometres southeast of the Hong Kong Special Administrative Region. Cenovus is the operator of the block with a 100 percent working interest.

Block DW-1, Taiwan Area

The Company and CPC Corporation (a state-owned oil and gas company), 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. The current three-dimensional seismic exploration period expires on December 17, 2027.

Indonesia

Madura Strait

The Company has a 40 percent equity 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 PSC currently operates four producing shallow water fields, namely the BD, MDA, MBH and MAC fields. It also contains shallow water MDK and MBF fields which may be developed in the future depending on gas demand and project economics.

In 2024, the Company’s working interest share of production was 85.8 MMcf per day of conventional natural gas and 1.7 thousand barrels per day of NGLs (2023 – 76.0 MMcf per day and 2.0 thousand barrels per day, respectively).

Liman

Located onshore in East Java, Indonesia, the Company holds a 100 percent working interest in the Liman contract area during the exploration phase.

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 34 percent working interest in the Terra Nova field and Suncor is the operator.

In 2024, the Company’s working interest share of light crude oil production averaged 8.0 thousand barrels per day (2023 – 0.5 thousand barrels per day).

White Rose Field and Satellite Extensions

The White Rose field is located about 350 kilometres 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. Cenovus has a working interest of 60 percent in the main field and 56.375 percent in the satellite extensions. The North Amethyst and South White Rose extensions were developed via subsea tie-back infrastructure which produce back to the SeaRose 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. The West White Rose project is anticipated to have peak production of 80.0 thousand barrels per day (45.0 thousand barrels per day, Cenovus’s working interest share) with first oil expected in 2026.

In 2024, the Company completed refit work at the drydock on the SeaRose FPSO and the vessel was returned to the field and reconnected in November. Commissioning activities and restart operations are taking place in the field and production is expected to resume late February 2025.

In 2024, there was no light crude oil production (2023 – 7.7 thousand barrels per day, Cenovus’s working interest share).


Cenovus Energy Inc. – 2024 Annual Information Form			10

East Coast Exploration

The Company holds working interests ranging from six percent to 100 percent in multiple discovery areas and 30 percent to 72.5 percent in exploration licenses within the Jeanne d’Arc Basin.

DOWNSTREAM

Canadian Refining

The following table summarizes key operational results for the segment (1):


	2024	2023
Operable Capacity (2) (Mbbls/d)	108.0	108.0
Total Processed Inputs (3) (Mbbls/d)	96.6	107.1
Crude Oil Unit Throughput (Mbbls/d)	90.5	100.7
Crude Unit Utilization (4) (percent)	84	93
Total Production (Mbbls/d)	103.1	114.2
Synthetic Crude Oil	41.0	47.6
Asphalt	15.7	15.4
Diesel	10.8	12.9
Other	30.8	33.3
Ethanol	4.8	5.0

(1)Results reflect operations at the Lloydminster Upgrader and the Lloydminster Refinery. Total production includes production from our ethanol plants.

(2)Operable capacity is the capacity based on crude oil throughput (or “throughput”) barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. We previously reported crude oil name plate capacity. See the Abbreviations and Definitions section of the annual 2024 MD&A.

(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

(4)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.

Lloydminster Upgrader

The Lloydminster Upgrader, located in Lloydminster, Saskatchewan, processes blended heavy crude oil feedstock (including bitumen). The feedstocks are received via the Saskatchewan Gathering System and the Cold Lake Gathering System, both of which are owned by HMLP, as well as via the Border Pipeline System owed by Cenovus. The Lloydminster Upgrader produces synthetic crude oil HSB, ultra-low sulphur diesel and other ancillary products. Production is transported via railcar and truck to primary markets in Western and Eastern Canada. Synthetic crude oil is sold into the Alberta market or used as refinery feedstock in the U.S. Refining segment. In addition, the Upgrader recovers condensate from the feedstock for reuse in the Company’s Oil Sands segment and is transported back to field sites via the gathering systems.

Lloydminster Refinery

The Lloydminster Refinery, located in Lloydminster, Alberta, processes blended heavy crude oil into asphalt products used in road construction and maintenance, bulk distillates and industrial products. The feedstocks are received via the Saskatchewan Gathering System. The refined products are transported via railcar and truck to primary markets in Western Canada, the U.S. Upper-Midwest, Rocky Mountain Region and the West Coast. Condensate is recovered from the feedstock for reuse in the Company’s Oil Sands segment and is transported to field sites via the gathering system. Distillates are transferred to the Lloydminster Upgrader and blended into the HSB stream or sold directly 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.

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 and export sales to the U.S., the Company owns an asphalt distribution network composed of four asphalt terminals located in: Kamloops, British Columbia (storage capacity – 45.0 thousand barrels); Edmonton, Alberta (storage capacity – 35.0 thousand barrels); Yorkton, Saskatchewan (storage capacity – 60.0 thousand barrels); and Winnipeg, Manitoba (storage capacity – 115.0 thousand barrels). The Company also owns an emulsion plant located in Saskatoon, Saskatchewan (storage capacity – 5.0 thousand barrels). The Lloydminster Refinery has a working tank capacity of 1.5 million barrels.


Cenovus Energy Inc. – 2024 Annual Information Form			11

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. The crude-by-rail terminal 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.

Total volumes loaded at the Bruderheim Terminal averaged 12.5 thousand barrels per day in 2024 (2023 – 16.1 thousand barrels per day) including crude oil volumes from our Oil Sands segment.

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 name plate capacity of 130 million litres.

The Lloydminster ethanol plant captures carbon dioxide for use in the Company’s Lloydminster conventional heavy oil assets. Ethanol produced at the plant has a low carbon intensity designation. At the Minnedosa ethanol plant, the Company continues to evaluate the viability of a carbon capture and sequestration project to achieve lower carbon intensity ethanol production.

Commercial Fuels Business

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.

The following table shows the number of locations by province as at December 31, 2024:


	British Columbia	Alberta	Saskatchewan	Manitoba	Ontario	Quebec	Nova Scotia	Total
Cardlocks	36	21	4	6	19	1	1	88
Bulk Plants	3	7	2	1	—	—	—	13
Travel Centres	13	16	3	3	19	—	—	54
Total	52	44	9	10	38	1	1	155

U.S. Refining

The following table summarizes key operational results for the segment and includes Cenovus’s 50 percent interest in the non-operated Wood River and Borger refineries:


	2024	2023

Operable Capacity (1) (Mbbls/d)	612.3	612.3
Total processed Inputs (2) (Mbbls/d)	581.4	479.7
Crude Oil Unit Throughput (Mbbls/d)	556.4	459.7
Heavy Crude Oil	219.6	173.9
Light and Medium Crude Oil	336.8	285.8
Crude Unit Utilization (3) (4) (percent)	91	78
Total Production (Mbbls/d)	590.0	485.0
Gasoline	280.5	231.2
Distillates (5)	209.1	167.0
Asphalt	28.3	19.8
Other	72.1	67.0

(1)Operable capacity is the capacity based on throughput barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. We previously reported crude oil name plate capacity. See the Abbreviations and Definitions section of the annual 2024 MD&A.

(2)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

(3)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.

(4)The Superior Refinery’s operable capacity is included in the metrics effective April 1, 2023. The Toledo Refinery includes a weighted average operable capacity in the metrics, as full ownership of the Toledo Refinery was acquired on February 28, 2023.

(5)Includes diesel and jet fuel.


Cenovus Energy Inc. – 2024 Annual Information Form			12

Lima Refinery

The Lima Refinery is located in Lima, Ohio, approximately 150 kilometres northwest of Columbus, Ohio. The refinery processes heavy, light and synthetic crude oil, and has the capability to process HSB produced at the Lloydminster Upgrader and Cold Lake Blend (“CLB”) produced at Foster Creek. The crude oil feedstocks are received via the Mid-Valley and Marathon Pipelines. The Lima Refinery produces low-sulphur gasoline, gasoline blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products. The refined products are transported via the Buckeye, Inland and Energy Transfer Partners pipeline systems, and by railcar to markets in various U.S. states.

Toledo Refinery

On February 28, 2023, Cenovus acquired the remaining 50 percent interest in the Toledo Refinery from bp, giving Cenovus full ownership and operatorship of the refinery, and further integrating Cenovus’s heavy oil production and refining capabilities.

The Toledo Refinery is located near Toledo, Ohio, approximately 210 kilometres north of Columbus, Ohio. The refinery processes heavy, light and high total acid number (“high TAN”) crude oil, and has the capability to process Western Canada Dilbit Blend (“WDB”) produced at Sunrise, Christina Dilbit Blend (“CDB”) produced at Christina Lake and CLB produced at Foster Creek, in addition to other third-party high TAN crude oil such as Access Western Blend (“AWB”). The refinery also processes HSB produced at the Lloydminster Upgrader. The crude oil feedstocks are received via the Mid-Valley, Marathon and Enbridge Mainline Pipelines. The refinery produces gasoline, diesel, jet fuel and other products. The refined products are transported via the Buckeye, Inland and Energy Transfer Partners pipeline systems, and by barge and railcar to markets in various U.S. states.

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 Superior Refinery ramped up operations throughout 2023. In the fourth quarter of 2024, the alkylation unit was commissioned.

The refinery processes heavy, light and synthetic crude oil, including HSB produced at the Lloydminster Upgrader, and has the capability to process various crudes such as CDB, Lloyd Blend (“LLB”) and CLB. The crude oil feedstocks are received via Enbridge’s Canadian mainline systems from Alberta, Canada, and the U.S. pipeline system from the Bakken region in North Dakota, arriving at the Enbridge Superior Terminal adjacent to the Superior Refinery. The refinery produces various grades of asphalt, low-sulphur gasoline, low-sulphur diesel, gasoline blendstocks and other by-products. Refined products are transported via the Magellan Pipeline system south to the Minneapolis market and to local markets via trucks that are loaded at the Superior Terminal. Asphalt is loaded at the Superior rail and truck loading facilities, and transported to markets in various U.S. states.

Non-Operated Refineries

Wood River Refinery

Cenovus has a 50 percent interest in the Wood River Refinery 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 refinery also has the capability to process CDB produced at Christina Lake. 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.

Borger Refinery

Cenovus has a 50 percent interest in the Borger Refinery located in Borger, Texas, approximately 80 kilometres northeast 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.

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 2.5 million barrels. The Company also markets asphalt from independently operated terminals located in the states of Minnesota, Wisconsin, Ohio and Colorado.


Cenovus Energy Inc. – 2024 Annual Information Form			13

COMPETITIVE CONDITIONS

All aspects of the energy industry are highly competitive. For further information on the competitive conditions affecting Cenovus, refer to the section entitled Risk Management and Risk Factors in the Company’s annual 2024 MD&A, which section is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.

ENVIRONMENTAL PROTECTION

All phases of our upstream and downstream operations, including the marketing of Cenovus’s production and third-party commodity traded volumes, are subject to environmental regulation pursuant to a variety of federal, provincial, territorial, state and regional 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 2024 MD&A, which section is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.

CODE OF BUSINESS CONDUCT AND ETHICS

Cenovus’s Code of Business Conduct & Ethics (the “Code”) is an expression of the Company’s purpose and values and is endorsed by the Board of Directors, Cenovus’s highest level of governance. It has been designed to provide staff (i.e., employees and contractors) with the tools and principles needed to conduct business in a safe, legal and ethical manner, and helps the Company integrate environmental, social and governance considerations into its business plans. The Code applies to everyone working on behalf of Cenovus in all locations where the Company conducts business. Each year all staff are asked to review the Code, confirm they understand their responsibilities and commit to the Code requirements. Cenovus suppliers should review the Code and align with the principles and guidance it provides.

The Code uses plain language, includes a message from Cenovus’s President & Chief Executive Officer and provides 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.

In addition to their review and commitment of the Code, Cenovus’s directors and staff are regularly required to review and commit to other key policies and standards. Quarterly ethics and compliance training is delivered to all staff. Stakeholders and staff are encouraged to report any business conduct concerns, including violations of applicable laws or any Cenovus policy, through the Company’s anonymous Integrity Helpline. Staff may also report any such concerns to their supervisor, a human resources business partner or a member of the Investigations Committee.

Additional Policy Information

In addition to the Code, Cenovus has established other policies including the Sustainability, Human Rights and Indigenous Relations policies, and practices that relate to environmental or social aspects of Cenovus’s business.

The 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 governance and leadership, people, environment, stakeholder engagement, Indigenous reconciliation, and community involvement and investment. It sets the frameworks for Cenovus’s commitment to providing a safe and inclusive workplace, investing in and partnering with local and Indigenous communities, continuously improving operating practices, investing in technology and collaborating with third parties to find innovative solutions to minimize Cenovus’s environmental impact and maximize business value.

The Human Rights Policy formalizes our commitment to human rights, guided by the principles of the Universal Declaration of Human Rights, reflects our values and behaviours and further supports the sustainable operation of our business. This policy outlines the Company’s commitment to fostering an environment where human rights are upheld and individual dignity is preserved. It also highlights the Company’s recognition of the fundamental importance of human rights for its employees, stakeholders and communities in which Cenovus operates.

The Indigenous Relations Policy aims to ensure Indigenous relations across the Company are supported by a consistent approach based on respect, honesty and integrity. This policy outlines our commitment to the inclusion of Indigenous peoples in our business, in line with our commitment to reconciliation and the principles of the United Nations Declaration on the Rights of Indigenous Peoples.

Cenovus’s directors, management and staff are periodically required to complete policy training and review and commit to the Sustainability, Human Rights and Indigenous Relations policies and other key policies and standards. The aforementioned policies are accessible on the Company’s website at cenovus.com as is Cenovus’s annual Corporate Social Responsibility (“CSR”) report. The CSR report outlines the progress Cenovus has made towards Indigenous reconciliation and inclusion & diversity targets, as well as information about safety performance and approach to governance.

This report differs from previous Environmental, Social and Governance (“ESG”) reports in that it does not include information regarding Cenovus’s environmental performance and plans due to recent changes to Canada’s Competition Act.


Cenovus Energy Inc. – 2024 Annual Information Form			14

EMPLOYEES

The following table summarizes Cenovus’s full-time equivalent (“FTE”) employees as at December 31, 2024:


			2024
Upstream Operations			2,958
Downstream Operations			2,366
Corporate (1)			1,826
Total FTE Employees			7,150

(1) Includes employees within Corporate and Operations Services, Finance and Risk, People Services, Sustainability and Stakeholder Engagement, Corporate Development 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 2024 MD&A, which is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca 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 2024 MD&A, which is incorporated by reference into this AIF and is available on SEDAR+ at sedarplus.ca 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, 2024, 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”), composed of a majority 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 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 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 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 2024 MD&A, which is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.

Cenovus’s reserves data and other oil and gas information contained in this AIF is dated February 18, 2025, with an effective date of December 31, 2024. McDaniel’s and GLJ’s preparation dates of the information are January 23, 2025, and January 3, 2025, respectively.

Disclosure of Reserves 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, as well as 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. – 2024 Annual Information Form			15

Additional Notes to 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 (heavy crude oil represents less than one percent of bitumen on a gross total proved plus probable basis and shale gas represents less than one percent of conventional natural gas on a gross total proved plus probable basis).

•Indonesia includes values attributable to Cenovus’s 40 percent equity interest in HCML.

•Unless otherwise indicated, Canada includes values attributable to Cenovus’s 30 percent equity interest in Duvernay. Cenovus’s proportionate share of Duvernay reserves accounts for less than one percent of gross total proved plus probable reserves.

•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.

•Reserves data tables may not sum due to rounding.

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.

Future net revenue is a forecast of revenue, estimated using forecast prices and costs, from the development and production of reserves minus the associated royalties, operating costs, development costs, and abandonment and reclamation costs. It does not include costs related to interest, general and administrative expenses or risk management activities. Future net revenue is presented on a before and after tax basis.

Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as at 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. – 2024 Annual Information Form			16

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 forecast is dated January 1, 2025. 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 2024, see the Production History and Per-Unit Results section in this AIF.


	Crude Oil and NGLs (1)					Natural Gas (2)
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 (US$/Mcf)	Indonesia (US$/Mcf)	Inflation Rate (%/year)	Exchange Rate (US$/C$)
2025	71.58	94.79	82.69	100.14	75.58	2.36	8.61	7.34	0.0	0.7117
2026	74.48	97.04	84.27	100.72	78.51	3.33	8.94	7.42	2.0	0.7283
2027	75.81	97.37	83.81	100.24	79.89	3.48	9.27	7.54	2.0	0.7433
2028	77.66	99.80	85.70	102.73	81.82	3.69	9.46	7.67	2.0	0.7433
2029	79.22	101.79	87.45	104.79	83.46	3.76	9.47	7.76	2.0	0.7433
2030	80.80	103.83	89.25	106.86	85.13	3.83	9.30	7.91	2.0	0.7433
2031	82.42	105.91	91.04	109.01	86.84	3.91	9.41	8.04	2.0	0.7433
2032	84.06	108.03	92.85	111.19	88.57	3.99	10.15	8.11	2.0	0.7433
2033	85.74	110.19	94.71	113.42	90.31	4.07	10.54	—	2.0	0.7433
2034	87.46	112.39	96.61	115.69	92.09	4.15	—	—	2.0	0.7433
2035	89.21	114.64	98.54	118.00	93.93	4.23	—	—	2.0	0.7433
2036+	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	—	—	2.0	0.7433

(1)Selected market benchmark prices are used to estimate the FNR related to the Cenovus’s bitumen, light and medium oil and NGLs production.

(2)Selected market benchmark prices, and prices derived from the natural gas sales agreements in China and Indonesia, are used to estimate the FNR related to the Cenovus’s conventional natural gas production.


Cenovus Energy Inc. – 2024 Annual Information Form			17

Summary of Oil and Gas Reserves as at December 31, 2024


Gross Reserves	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (Bcf)	Total (MMBOE)
Canada
Proved
Developed Producing	916	26	42	1,144	1,175
Developed Non-Producing	27	2	2	44	38
Undeveloped	4,237	63	12	371	4,374
Total Proved	5,179	91	57	1,560	5,587
Probable	2,500	77	34	942	2,767
Total Proved Plus Probable	7,679	168	90	2,501	8,354

China
Proved
Developed Producing	—	—	9	236	49
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	9	236	49
Probable	—	—	3	83	17
Total Proved Plus Probable	—	—	12	319	65

Indonesia
Proved
Developed Producing	—	—	3	154	29
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	3	154	29
Probable	—	—	1	47	9
Total Proved Plus Probable	—	—	4	200	38

Total Company
Proved
Developed Producing	916	26	55	1,534	1,252
Developed Non-Producing	27	2	2	44	38
Undeveloped	4,237	63	12	371	4,374
Total Proved	5,179	91	69	1,950	5,664
Probable	2,500	77	37	1,071	2,793
Total Proved Plus Probable	7,679	168	107	3,021	8,457


Cenovus Energy Inc. – 2024 Annual Information Form			18


Net Reserves	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (Bcf)	Total (MMBOE)
Canada
Proved
Developed Producing	684	23	35	1,066	921
Developed Non-Producing	19	1	1	40	29
Undeveloped	3,168	61	10	340	3,295
Total Proved	3,871	86	47	1,446	4,245
Probable	1,799	59	27	857	2,028
Total Proved Plus Probable	5,671	145	74	2,303	6,273

China
Proved
Developed Producing	—	—	8	224	46
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	8	224	46
Probable	—	—	2	78	15
Total Proved Plus Probable	—	—	11	302	61

Indonesia
Proved
Developed Producing	—	—	2	109	20
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	2	109	20
Probable	—	—	—	26	4
Total Proved Plus Probable	—	—	2	135	24

Total Company
Proved
Developed Producing	684	23	45	1,399	986
Developed Non-Producing	19	1	1	40	29
Undeveloped	3,168	61	10	340	3,295
Total Proved	3,871	86	57	1,779	4,311
Probable	1,799	59	30	961	2,048
Total Proved Plus Probable	5,671	145	87	2,740	6,359


Cenovus Energy Inc. – 2024 Annual Information Form			19

Summary of Net Present Value of Future Net Revenue as at December 31, 2024


	Discounted at % per year					Unit Value Discounted at 10% (1)
Before Income Taxes ($ millions)	0%	5%	10%	15%	20%	$/BOE
Canada
Proved
Developed Producing	26,905	27,711	25,706	23,615	21,759	27.91
Developed Non-Producing	1,113	894	739	626	540	25.49
Undeveloped	160,352	74,766	41,659	26,338	18,122	12.64
Total Proved	188,370	103,371	68,104	50,579	40,421	16.04
Probable	138,951	41,728	19,680	12,563	9,330	9.70
Total Proved Plus Probable	327,321	145,099	87,784	63,141	49,751	13.99

China
Proved
Developed Producing	2,504	2,268	2,073	1,910	1,773	45.56
Developed Non-Producing	—	—	—	—	—	—
Undeveloped	—	—	—	—	—	—
Total Proved	2,504	2,268	2,073	1,910	1,773	45.56
Probable	917	730	594	492	414	38.43
Total Proved Plus Probable	3,421	2,998	2,667	2,402	2,187	43.75

Indonesia
Proved
Developed Producing	549	474	416	370	333	20.85
Developed Non-Producing	—	—	—	—	—	—
Undeveloped	—	—	—	—	—	—
Total Proved	549	474	416	370	333	20.85
Probable	220	178	147	124	106	32.80
Total Proved Plus Probable	769	652	563	494	439	23.04

Total Company
Proved
Developed Producing	29,958	30,453	28,195	25,896	23,865	28.58
Developed Non-Producing	1,113	894	739	626	540	25.49
Undeveloped	160,352	74,766	41,659	26,338	18,122	12.64
Total Proved	191,423	106,113	70,593	52,859	42,527	16.38
Probable	140,087	42,636	20,421	13,179	9,851	9.97
Total Proved Plus Probable	331,510	148,749	91,015	66,038	52,378	14.31

(1)Unit values have been calculated using Cenovus’s net reserves.


Cenovus Energy Inc. – 2024 Annual Information Form			20


	Discounted at % per year
After Income Taxes (1) ($ millions)	0%	5%	10%	15%	20%
Canada
Proved
Developed Producing	20,797	22,321	20,862	19,200	17,691
Developed Non-Producing	913	726	595	500	429
Undeveloped	123,298	56,885	31,322	19,558	13,289
Total Proved	145,009	79,932	52,778	39,258	31,408
Probable	106,392	31,678	14,900	9,505	7,054
Total Proved Plus Probable	251,400	111,610	67,678	48,763	38,462

China
Proved
Developed Producing	1,943	1,757	1,604	1,476	1,368
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	1,943	1,757	1,604	1,476	1,368
Probable	694	552	448	370	311
Total Proved Plus Probable	2,637	2,309	2,052	1,846	1,679

Indonesia
Proved
Developed Producing	375	327	290	260	236
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	375	327	290	260	236
Probable	138	112	92	78	67
Total Proved Plus Probable	513	439	382	338	303

Total Company
Developed Producing	23,115	24,405	22,755	20,936	19,295
Developed Non-Producing	913	726	595	500	429
Undeveloped	123,298	56,885	31,322	19,558	13,289
Total Proved	147,327	82,016	54,672	40,994	33,013
Probable	107,224	32,342	15,440	9,953	7,431
Total Proved Plus Probable	254,551	114,358	70,112	50,947	40,444

(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 legal entity level, which may be significantly different. For information about existing tax pools, please see Cenovus’s Consolidated Financial Statements for the year ended December 31, 2024.


Cenovus Energy Inc. – 2024 Annual Information Form			21

Total Undiscounted Future Net Revenue as at December 31, 2024


($ 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	476,261	118,682	112,244	45,299	11,665	188,370	43,362	145,009
Total Proved Plus Probable	793,327	205,519	173,785	73,979	12,723	327,321	75,920	251,400

China
Total Proved	3,829	287	830	148	60	2,504	561	1,943
Total Proved Plus Probable	5,115	384	1,094	154	62	3,421	783	2,637

Indonesia
Total Proved	1,957	639	723	—	46	549	174	375
Total Proved Plus Probable	2,548	934	799	—	47	769	255	513

Total Company
Total Proved	482,047	119,608	113,796	45,447	11,771	191,423	44,097	147,327
Total Proved Plus Probable	800,989	206,836	175,678	74,132	12,832	331,510	76,959	254,551

(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.

Future Net Revenue by Product Type as at December 31, 2024


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	66,045	17.06
	Light and Medium Oil (2)	1,392	10.58
	Conventional Natural Gas (3)	3,155	10.26
	Total	70,593	16.38
Total Proved Plus	Bitumen	82,097	14.48
Probable	Light and Medium Oil (2)	4,033	19.02
	Conventional Natural Gas (3)	4,884	10.26
	Total	91,015	14.31

(1)Unit values have been calculated using Cenovus’s net reserves.

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

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


Cenovus Energy Inc. – 2024 Annual Information Form			22

Future Development Costs

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


($ millions)	2025	2026	2027	2028	2029	Remainder	Total
Canada
Total Proved	3,439	1,831	2,051	1,950	2,132	33,896	45,299
Total Proved Plus Probable	3,585	1,999	2,053	2,143	2,130	62,068	73,979

China
Total Proved	62	70	5	5	6	—	148
Total Proved Plus Probable	62	70	5	5	6	6	154

Indonesia
Total Proved	—	—	—	—	—	—	—
Total Proved Plus Probable	—	—	—	—	—	—	—

Total Company
Total Proved	3,501	1,901	2,057	1,956	2,138	33,896	45,447
Total Proved Plus Probable	3,647	2,069	2,058	2,149	2,136	62,074	74,132

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. – 2024 Annual Information Form			23

Reserves Reconciliation as at December 31, 2024


Gross Reserves, Total Proved	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (Bcf)	Total (MMBOE)
Canada
As at December 31, 2023	5,411	38	60	1,622	5,779
Extensions and Improved Recovery	146	54	4	160	230
Discoveries	—	—	—	—	—
Technical Revisions	(156)	(1)	3	17	(152)
Economic Factors	—	—	(1)	(15)	(3)
Acquisitions	—	8	1	19	13
Dispositions	—	(2)	(3)	(31)	(10)
Production (1)	(223)	(5)	(8)	(212)	(271)
As at December 31, 2024	5,179	91	57	1,560	5,587

China
As at December 31, 2023	—	—	10	262	53
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	3	48	11
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(3)	(73)	(16)
As at December 31, 2024	—	—	9	236	49

Indonesia
As at December 31, 2023	—	—	4	178	33
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	—	7	1
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(1)	(31)	(6)
As at December 31, 2024	—	—	3	154	29

Total Company
As at December 31, 2023	5,411	38	74	2,062	5,866
Extensions and Improved Recovery	146	54	4	160	230
Discoveries	—	—	—	—	—
Technical Revisions	(156)	(1)	6	72	(139)
Economic Factors	—	—	(1)	(15)	(3)
Acquisitions	—	8	1	19	13
Dispositions	—	(2)	(3)	(31)	(10)
Production (1)	(223)	(5)	(12)	(316)	(292)
As at December 31, 2024	5,179	91	69	1,950	5,664


Cenovus Energy Inc. – 2024 Annual Information Form			24


Gross Reserves, Probable	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (Bcf)	Total (MMBOE)
Canada
As at December 31, 2023	2,487	125	36	975	2,812
Extensions and Improved Recovery	85	(54)	4	134	57
Discoveries	—	—	—	—	—
Technical Revisions	(73)	(1)	(6)	(165)	(107)
Economic Factors	—	—	—	(5)	(1)
Acquisitions	—	6	1	14	10
Dispositions	—	(1)	(1)	(11)	(3)
Production (1)	—	—	—	—	—
As at December 31, 2024	2,500	77	34	942	2,767

China
As at December 31, 2023	—	—	2	76	15
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	—	6	1
Economic Factors	—	—	—	1	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	—	—
As at December 31, 2024	—	—	3	83	17

Indonesia
As at December 31, 2023	—	—	1	49	9
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	—	(2)	(1)
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	—	—
As at December 31, 2024	—	—	1	47	9

Total Company
As at December 31, 2023	2,487	125	40	1,100	2,836
Extensions and Improved Recovery	85	(54)	4	134	57
Discoveries	—	—	—	—	—
Technical Revisions	(73)	(1)	(6)	(161)	(106)
Economic Factors	—	—	—	(4)	(1)
Acquisitions	—	6	1	14	10
Dispositions	—	(1)	(1)	(11)	(3)
Production (1)	—	—	—	—	—
As at December 31, 2024	2,500	77	37	1,071	2,793


Cenovus Energy Inc. – 2024 Annual Information Form			25


Gross Reserves, Total Proved Plus Probable	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (Bcf)	Total (MMBOE)
Canada
As at December 31, 2023	7,899	163	96	2,598	8,591
Extensions and Improved Recovery	231	—	7	294	287
Discoveries	—	—	—	—	—
Technical Revisions	(229)	(2)	(3)	(149)	(259)
Economic Factors	1	—	(1)	(20)	(4)
Acquisitions	—	15	2	33	22
Dispositions	—	(2)	(4)	(42)	(13)
Production (1)	(223)	(5)	(8)	(212)	(271)
As at December 31, 2024	7,679	168	90	2,501	8,354

China
As at December 31, 2023	—	—	12	337	68
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	3	54	12
Economic Factors	—	—	—	1	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(3)	(73)	(16)
As at December 31, 2024	—	—	12	319	65

Indonesia
As at December 31, 2023	—	—	5	226	43
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	—	5	1
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(1)	(31)	(6)
As at December 31, 2024	—	—	4	200	38

Total Company
As at December 31, 2023	7,899	163	114	3,162	8,702
Extensions and Improved Recovery	231	—	7	294	287
Discoveries	—	—	—	—	—
Technical Revisions	(229)	(2)	—	(90)	(246)
Economic Factors	1	—	(1)	(19)	(3)
Acquisitions	—	15	2	33	22
Dispositions	—	(2)	(4)	(42)	(13)
Production (1)	(223)	(5)	(12)	(316)	(292)
As at December 31, 2024	7,679	168	107	3,021	8,457

(1)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 its conventional natural gas production provided to FCCL for steam generation, but does not include royalty interest production.


Cenovus Energy Inc. – 2024 Annual Information Form			26

The following developments occurred in 2024 compared with 2023:

•Bitumen gross total proved and gross total proved plus probable reserves decreased by 232 million barrels and 220 million barrels, respectively. The changes were due to current year production and negative technical revisions resulting from recovery factor changes at Christina Lake and Foster Creek, and negative technical revisions resulting from updates to the Sunrise and Lloydminster thermal development plans. These reductions were partially offset by extensions due to continuing development of, and updates to development plans for, the Oil Sands segment, and technical revisions due to improvements to recovery performance at Sunrise and Lloydminster thermal.

•Light and medium oil gross total proved and gross total proved plus probable reserves increased by 53 million barrels and five million barrels, respectively. The changes were due to extensions as a result of continuing development of the West White Rose project and the acquisition of the equity interest in Duvernay. These increases were partially offset by current year production and dispositions in the Conventional segment.

•NGLs gross total proved and gross total proved plus probable reserves decreased by five million barrels and seven million barrels, respectively. The changes were due to current year production, negative technical revisions due to updates to the Conventional segment development plans and dispositions in the Conventional segment. These reductions were partially offset by extensions due to updates to the Conventional segment development plans, technical revisions due to improvements to recovery performance for the Conventional segment and the Asia Pacific region, and the acquisition of the equity interest in Duvernay.

•Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 112 billion cubic feet and 141 billion cubic feet, respectively. The changes were due to current year production, negative technical revisions due to updates to the Conventional segment development plans and dispositions in the Conventional segment. These reductions were partially offset by extensions due to updates to the Conventional segment development plans, technical revisions due to increases to original natural gas in place volumes for the Asia Pacific region and the acquisition of the equity interest in Duvernay.

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 (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas (Bcf)		Total (MMBOE)
	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total
2022	313	4,442	2	4	3	13	158	382	344	4,523
2023	105	4,316	1	5	2	12	64	347	119	4,390
2024	94	4,237	61	63	3	12	101	371	175	4,374

Probable Undeveloped (Gross Reserves)


	Bitumen (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas (Bcf)		Total (MMBOE)
	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total	First Attributed	Total
2022	633	2,281	1	116	4	19	186	513	669	2,502
2023	84	2,320	4	119	4	21	106	561	109	2,553
2024	100	2,330	6	70	6	20	187	569	143	2,515


Cenovus Energy Inc. – 2024 Annual Information Form			27

Development of Proved and Probable Undeveloped Reserves

Bitumen

Cenovus’s bitumen reserves are entirely within the Oil Sands segment. Gross proved undeveloped bitumen reserves of 4,237 million barrels account for approximately 82 percent of the Company’s total gross proved bitumen reserves. Of Cenovus’s 2,500 million barrels of gross probable bitumen reserves, 2,330 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 generation facility 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 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 capacity 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 tie-back into the Christina Lake plant. First oil from Narrows Lake is expected in 2025. The forecasted production of Cenovus’s proved and proved plus probable SAGD bitumen reserves extends approximately 41 years and 50 years, respectively. Production of the current proved developed portion is estimated to take approximately 19 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’s 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 proved and probable undeveloped reserves attributed to the West White Rose project are currently scheduled to be on stream in 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 2024 MD&A, which is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.


Cenovus Energy Inc. – 2024 Annual Information Form			28

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, 2024:

Producing Wells


	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Canada
Oil Sands (1)	2,514	2,417	298	280	2,812	2,697
Conventional (2) (3)	611	442	3,870	3,000	4,481	3,442
Offshore – Atlantic (4)	37	17	—	—	37	17
	3,162	2,876	4,168	3,280	7,330	6,156
International
Offshore – China (5)	—	—	17	10	17	10
Offshore – Indonesia (3) (5)	—	—	14	6	14	6
	—	—	31	16	31	16
Total	3,162	2,876	4,199	3,296	7,361	6,172

(1)Includes 1,752 gross producing wells (1,663 net producing wells) located in Alberta and 1,060 gross producing wells (1,034 net producing wells) located in Saskatchewan.

(2)Includes 4,011 gross producing wells (3,048 net producing wells) located in Alberta and 470 gross producing wells (394 net producing wells) located in British Columbia.

(3)Conventional includes values attributable to Cenovus’s 30 percent equity interest in Duvernay. Indonesia includes values attributable to Cenovus’s 40 percent equity interest in HCML.

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

(5)All producing Offshore – China wells are located in the South China Sea. Indonesia wells are located in the Madura Strait BD, MDA, MBH and MAC fields.

Non-Producing Wells (1)


	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Canada
Oil Sands (2)	6,077	5,820	664	603	6,741	6,423
Conventional (3)	513	446	1,448	1,144	1,961	1,590
Offshore – Atlantic (4)	4	2	—	—	4	2
	6,594	6,268	2,112	1,747	8,706	8,015
International
Offshore – China	—	—	—	—	—	—
Offshore – Indonesia	—	—	—	—	—	—
	—	—	—	—	—	—
Total	6,594	6,268	2,112	1,747	8,706	8,015

(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)Includes 1,969 gross non-producing wells (1,828 net non-producing wells) located in Alberta and 4,772 gross non-producing wells (4,595 net non-producing wells) located in Saskatchewan.

(3)Includes 1,832 gross non-producing wells (1,491 net non-producing wells) located in Alberta; 99 gross non-producing wells (71 net non-producing wells) located in British Columbia; 28 gross non-producing wells (26 net non-producing wells) located in Saskatchewan, and 2 gross non-producing wells (2 net non-producing wells) in Manitoba.

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


Cenovus Energy Inc. – 2024 Annual Information Form			29

Exploration and Development Activity

The following tables summarize Cenovus’s gross and net interest in wells drilled in 2024:


					Offshore
	Oil Sands (1) (2)		Conventional (1) (3) (4)		Atlantic (1)		China		Indonesia (4)		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Crude Oil	388	388	17	12	—	—	—	—	—	—	405	400
Natural Gas	—	—	29	24	—	—	1	1	—	—	30	25

Total	388	388	46	36	—	—	1	1	—	—	435	425

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

(2)Seven service wells and 28 exploration wells were drilled in the Oil Sands Segment in 2024.

(3)Two exploration wells were drilled in the Conventional segment in 2024.

(4)Conventional includes values attributable to Cenovus’s 30 percent equity interest in Duvernay. Indonesia includes values attributable to Cenovus’s 40 percent equity interest in HCML.

During the year ended December 31, 2024, the Company drilled 146 gross stratigraphic test wells (146 net wells) and 112 gross observation wells (112 net wells) in the Oil Sands segment. SAGD well pairs are counted as a single oil producing well in the table above. During the year ended December 31, 2024, 130 gross SAGD well pairs were drilled (130 net well pairs).

No stratigraphic test wells were drilled in the Conventional segment in 2024.

In 2024, the Company drilled, abandoned and plugged one gross exploration well in China based on dry hole well results.

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, Sunrise and Lloydminster thermal, and the production and de-risking resource potential of the Conventional properties.

Properties With No Attributed Reserves

The following table summarizes Cenovus’s unproved acreage as at December 31, 2024:


(thousands of acres)	Gross	Net

Canada (1)	9,001	7,507
China	1,923	1,439
Indonesia (1)	616	247
Total	11,540	9,193

(1)Canada includes values attributable to Cenovus’s 30 percent equity interest in Duvernay. Indonesia includes values attributable to Cenovus’s 40 percent equity interest in HCML.

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 212,533 unproved net acres in Canada that could potentially expire by December 31, 2025, which relate entirely to Crown and freehold properties. There are no expiries for China or Indonesia within the next year.

The Company has a liability of approximately $9 million related to exploration licenses in the Atlantic region. The Company has commitments totalling approximately $36 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. – 2024 Annual Information Form			30

Additional Information Concerning Abandonment and Reclamation Costs

The estimated total future abandonment and reclamation costs for surface and subsea 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 $6.5 billion (approximately $2.7 billion, discounted at 10 percent) as at December 31, 2024, of which the Company expects to pay $704 million in the next three years. Estimated future abandonment and reclamation costs and payment excludes results attributed to Cenovus’s 30 percent equity interest in Duvernay and 40 percent equity interest in HCML as such values are immaterial.

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, 2024, $241 million (December 31, 2023 – $211 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 $11.8 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 2025 guidance dated December 11, 2024, and available on the Company’s website at cenovus.com, the Company expects to pay cash taxes of $1.4 billion to $1.6 billion in 2025. 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 (1)	China	Indonesia (1)	2024
Acquisitions
Unproved	7	—	—	7
Proved	15	—	—	15
Total Acquisitions	22	—	—	22
Exploration Costs	27	38	—	65
Development Costs	4,205	30	(5)	4,230
Total Costs Incurred	4,254	68	(5)	4,317


($ millions)	Canada	China	Indonesia (1)	2023
Acquisitions
Unproved	31	—	—	31
Proved	11	—	—	11
Total Acquisitions	42	—	—	42
Exploration Costs	80	4	—	84
Development Costs	3,389	3	14	3,406
Total Costs Incurred	3,511	7	14	3,532

(1)Canada includes values attributable to Cenovus’s 30 percent equity interest in Duvernay. Indonesia includes values attributable to Cenovus’s 40 percent equity interest in HCML.

Forward Contracts

Cenovus may use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates. The Company may also enter into arrangements, such as renewable power contracts or power swaps, to manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions. A description of such instruments is provided in the notes to the Company’s Consolidated Financial Statements for the year ended December 31, 2024.


Cenovus Energy Inc. – 2024 Annual Information Form			31

Production Estimates

The following table summarizes the 2025 estimated gross production of Cenovus’s gross reserves for all properties held on December 31, 2024, 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 (1)
Bitumen (Mbbls/d) (2)	627.3	668.1
Light and Medium Oil (Mbbls/d)	20.2	22.5
NGLs (Mbbls/d)	21.1	23.1
Conventional Natural Gas (MMcf/d)	577.3	632.7
Total (3) (MBOE/d)	764.9	819.2

China


NGLs (Mbbls/d)	7.8	8.3
Conventional Natural Gas (MMcf/d)	176.2	187.9
Total (3) (MBOE/d)	37.2	39.6

Indonesia (1)


NGLs (Mbbls/d)	1.6	1.9
Conventional Natural Gas (MMcf/d)	75.7	84.4
Total (3) (MBOE/d)	14.2	15.9

Total Company
Bitumen (Mbbls/d) (2)	627.3	668.1
Light and Medium Oil (Mbbls/d)	20.2	22.5
NGLs (Mbbls/d)	30.5	33.3
Conventional Natural Gas (MMcf/d)	829.3	905.1
Total (MBOE/d) (2) (3)	816.3	874.8

(1)Canada includes values attributable to Cenovus’s 30 percent equity interest in Duvernay. Indonesia includes values attributable to Cenovus’s 40 percent equity interest in HCML.

(2)Includes Foster Creek production of 199.2 thousand barrels per day for total proved and 213.8 thousand barrels per day for total proved plus probable, and includes Christina Lake production of 252.8 thousand barrels per day for total proved and 265.0 thousand barrels per day for total proved plus probable.

(3)Reserves data may not sum due to rounding.


Cenovus Energy Inc. – 2024 Annual Information Form			32

Production History and Per-Unit Results


	2024	Q4	Q3	Q2	Q1
Canada (1)
Bitumen

Foster Creek	196.0	195.2	198.0	195.0	196.0
Christina Lake	234.2	251.4	211.8	237.1	236.5
Sunrise	49.6	53.1	50.4	46.1	48.8
Lloydminster Thermal	111.5	108.9	109.4	113.5	114.1
Lloydminster Conventional Heavy Oil	17.6	18.0	16.3	18.1	17.9
Total Bitumen (2) (Mbbls/d)	608.9	626.6	585.9	609.8	613.3

Light and Medium Oil (Mbbls/d)	12.9	12.3	13.6	13.5	12.5
NGLs (Mbbls/d)	21.0	19.7	21.1	21.4	22.0
Conventional Natural Gas (MMcf/d)	574.9	572.3	565.2	589.9	572.4
Total (2) (MBOE/d)	738.6	753.9	714.8	743.0	743.2

China
NGLs (Mbbls/d)	9.3	9.1	8.8	9.8	9.5
Conventional Natural Gas (MMcf/d)	199.5	200.8	190.2	202.5	204.7
Total (MBOE/d)	42.6	42.6	40.5	43.5	43.7

Indonesia
NGLs (Mbbls/d)	1.7	2.9	1.1	1.8	0.9
Conventional Natural Gas (MMcf/d)	85.8	100.2	89.2	74.8	78.7
Total (MBOE/d)	16.0	19.6	16.0	14.3	14.0

Total Company (1)
Bitumen (2) (Mbbls/d)	608.9	626.6	585.9	609.8	613.3

Light and Medium Oil (Mbbls/d)	12.9	12.3	13.6	13.5	12.5
NGLs (Mbbls/d)	32.0	31.7	31.0	33.0	32.4
Conventional Natural Gas (MMcf/d)	860.2	873.3	844.6	867.2	855.8
Total (2) (MBOE/d)	797.2	816.0	771.3	800.8	800.9

(1)Excludes production and per-unit results attributable to Cenovus’s 30 percent equity interest in Duvernay as such values are immaterial.

(2)Includes bitumen and heavy crude oil.

Netbacks

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. Our Netback calculation is substantially aligned with the definition found in the COGE Handbook. Netback is defined as gross sales less royalties, transportation and blending, and operating expenses. 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. Condensate or butane (diluent) is blended with crude oil to transport it to market. In March 2024, modifications were made to our Netback definition to enhance the clarity of certain costs captured in this metric. These modifications resulted in minor adjustments that are captured in the Netback calculation on a prospective basis.

Realized Sales Price contains a non-GAAP measure. It includes our gross sales, purchased diluent costs and profit from optimization activities, such as cogeneration, third-party processing and trading. Offshore and Asia Pacific Per-Unit Operating Expenses contain non-GAAP measures. Offshore and Asia Pacific operating expenses, as used in the basis of our Netback calculation, reflect our 40 percent equity interest in HCML. The HCML joint venture is accounted for using the equity method in the Consolidated Financial Statements. Netback per barrel of oil equivalent contains a non-GAAP measure. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Per-unit measures are divided by sales volumes.

These Netbacks have been described and presented in this AIF 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 International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”). For further information on these measures, readers should refer to the section entitled Specified Financial Measures Advisory located in the Company’s annual 2024 MD&A, which is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.


Cenovus Energy Inc. – 2024 Annual Information Form			33


Canada (1)	2024	Q4	Q3	Q2	Q1
Foster Creek Bitumen ($/bbl)
Sales Price	84.49	85.87	84.72	90.89	76.80
Royalties	17.03	16.73	18.63	16.08	16.61
Transportation and Blending	13.57	16.61	12.90	14.69	10.25
Operating Expenses	9.87	9.60	9.01	10.06	10.81
Netback	44.02	42.93	44.18	50.06	39.13

Christina Lake Bitumen ($/bbl)
Sales Price	75.74	72.86	79.54	84.93	66.90
Royalties	18.86	20.14	19.91	20.17	15.40
Transportation and Blending	6.53	6.08	7.63	7.16	5.40
Operating Expenses	8.63	8.25	9.33	8.49	8.51
Netback	41.72	38.39	42.67	49.11	37.59

Sunrise Bitumen ($/bbl)
Sales Price	86.07	79.30	83.02	94.47	88.36
Royalties	4.26	3.86	4.72	5.53	2.62
Transportation and Blending	16.07	12.32	15.36	18.71	18.51
Operating Expenses	14.36	14.84	12.97	13.17	17.02
Netback	51.38	48.28	49.97	57.06	50.21

Lloydminster Bitumen (2) ($/bbl)
Sales Price	79.65	75.16	80.67	89.90	72.71
Royalties	8.84	10.15	11.23	9.42	4.58
Transportation and Blending	3.95	3.71	3.63	4.55	3.89
Operating Expenses	17.52	17.32	16.91	17.81	18.05
Netback	49.34	43.98	48.90	58.12	46.19

Total Bitumen (2) ($/bbl)

Sales Price	80.20	77.83	81.77	88.76	72.79
Royalties	14.92	15.64	16.26	15.21	12.60
Transportation and Blending	9.00	9.31	9.18	9.98	7.54
Operating Expenses	11.40	11.10	11.17	11.47	11.86
Netback	44.88	41.78	45.16	52.10	40.79








Light and Medium Oil ($/bbl)
Sales Price	103.15	97.71	101.57	108.98	99.12
Royalties	8.64	9.40	9.64	5.66	12.86
Transportation and Blending	6.89	7.45	6.59	7.40	5.55
Operating Expenses	65.05	69.32	58.91	61.62	75.24
Netback	22.57	11.54	26.43	34.30	5.47

Conventional Natural Gas (3) ($/Mcf)
Sales Price	2.51	2.74	1.53	1.77	4.00
Royalties	0.02	0.02	(0.04)	0.02	0.07
Transportation and Blending	0.61	0.60	0.63	0.62	0.60
Operating Expenses	2.00	1.82	2.13	1.87	2.18
Netback	(0.12)	0.30	(1.19)	(0.74)	1.15

NGLs (4) ($/bbl)
Sales Price	54.62	50.64	53.77	56.29	57.40
Royalties	4.35	2.43	3.82	5.40	5.57
Transportation and Blending	9.24	9.07	9.68	10.51	7.74
Operating Expenses	12.03	10.91	12.78	11.26	13.06
Netback	29.00	28.23	27.49	29.12	31.03

(1)Excludes production and per-unit results attributable to Cenovus’s 30 percent equity interest in Duvernay as such values are immaterial.

(2)Includes bitumen and heavy crude oil.

(3)Includes natural gas volumes used for internal consumption by the Oil Sands segment.

(4)Includes butane and condensate used for internal consumption by the Oil Sands segment.


Cenovus Energy Inc. – 2024 Annual Information Form			34


China	2024	Q4	Q3	Q2	Q1
Conventional Natural Gas ($/Mcf)
Sales Price	12.66	12.92	12.68	12.59	12.46
Royalties	0.67	0.68	0.67	0.67	0.66
Transportation and Blending	—	—	—	—	—
Operating Expenses	1.27	1.46	1.37	1.21	1.05
Netback	10.72	10.78	10.64	10.71	10.75

NGLs ($/bbl)
Sales Price	95.64	90.91	96.60	99.65	95.20
Royalties	13.95	14.28	14.50	13.78	13.30
Transportation and Blending	—	—	—	—	—
Operating Expenses	7.58	8.77	8.14	7.24	6.27
Netback	74.11	67.86	73.96	78.63	75.63


Indonesia	2024	Q4	Q3	Q2	Q1
Conventional Natural Gas ($/Mcf)
Sales Price	8.63	8.97	8.60	8.67	8.21
Royalties	0.68	1.35	0.49	0.54	0.17
Transportation and Blending	—	—	—	—	—
Operating Expenses	1.84	1.87	1.83	1.64	2.01
Netback	6.11	5.75	6.28	6.49	6.03

NGLs ($/bbl)
Sales Price	108.19	101.42	111.68	117.32	107.19
Royalties	52.99	52.25	53.07	56.89	47.48
Transportation and Blending	—	—	—	—	—
Operating Expenses	9.93	10.69	10.83	8.49	9.21
Netback	45.27	38.48	47.78	51.94	50.50


Cenovus Energy Inc. – 2024 Annual Information Form			35


Total Company (1)	2024	Q4	Q3	Q2	Q1
Bitumen (2) ($/bbl)
Sales Price	80.20	77.83	81.77	88.76	72.79
Royalties	14.92	15.64	16.26	15.21	12.60
Transportation and Blending	9.00	9.31	9.18	9.98	7.54
Operating Expenses	11.40	11.10	11.17	11.47	11.86
Netback	44.88	41.78	45.16	52.10	40.79








Light and Medium Oil ($/bbl)
Sales Price	103.15	97.71	101.57	108.98	99.12
Royalties	8.64	9.40	9.64	5.66	12.86
Transportation and Blending	6.89	7.45	6.59	7.40	5.55
Operating Expenses	65.05	69.32	58.91	61.62	75.24
Netback	22.57	11.54	26.43	34.30	5.47

Conventional Natural Gas (3) ($/Mcf)
Sales Price	5.51	5.84	4.83	4.93	6.45
Royalties	0.24	0.33	0.18	0.22	0.22
Transportation and Blending	0.40	0.39	0.42	0.42	0.40
Operating Expenses	1.81	1.74	1.93	1.70	1.89
Netback	3.06	3.38	2.30	2.59	3.94

NGLs (4) ($/bbl)
Sales Price	69.39	66.87	68.08	72.56	69.92
Royalties	9.73	10.42	8.68	10.77	9.03
Transportation and Blending	6.07	5.63	6.57	6.81	5.25
Operating Expenses	10.63	10.28	11.39	9.91	10.96
Netback	42.96	40.54	41.44	45.07	44.68

(1)Excludes production and per-unit results attributable to Cenovus’s 30 percent equity interest in Duvernay as such values are immaterial.

(2)Includes bitumen and heavy crude oil.

(3)Includes natural gas volumes used for internal consumption by the Oil Sands segment.

(4)Includes butane and condensate used for internal consumption by the Oil Sands segment.


Cenovus Energy Inc. – 2024 Annual Information Form			36



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 February 19, 2025, the Company’s Board declared a first quarter base dividend of $0.180 per common share, payable on March 31, 2025, to common shareholders of record as at March 14, 2025.

On February 19, 2025, the Company’s Board declared first quarter dividends for Cenovus’s preferred shares, payable on March 31, 2025, in the amount of $6 million, to preferred shareholders of record as at March 14, 2025.

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


($ per share)	2024	2023	2022
Base Dividends	0.680	0.525	0.350
Variable Dividends	0.135	—	0.114

Cenovus declared the following dividends on the first preferred shares over the last three years ended December 31:


($ per share)	2024	2023 (1)	2022 (2)
Series 1 First Preferred Shares	0.644	0.644	0.644
Series 2 First Preferred Shares	1.626	1.584	0.781
Series 3 First Preferred Shares (3)	1.172	1.172	1.172
Series 5 First Preferred Shares	1.148	1.148	1.148
Series 7 First Preferred Shares	0.984	0.984	0.984

(1)The preferred shares dividends declared on November 1, 2023, were paid on January 2, 2024.

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

(3)On December 31, 2024, the Company exercised its right to redeem all series 3 preferred shares.

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 2024 MD&A, which is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca 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 authorized the issuance of series 1, 2, 3, 4, 5, 6, 7 and 8 first preferred shares.

There are no series 3, 4, 6 or 8 first preferred shares outstanding and no second preferred shares outstanding. As at December 31, 2024, the Company had the following common shares, Cenovus Warrants and first preferred shares outstanding:


			Units Outstanding (thousands)
Common Shares			1,825,038
Cenovus Warrants			3,643

Series 1 First Preferred Shares			10,740
Series 2 First Preferred Shares			1,260

Series 5 First Preferred Shares			8,000
Series 7 First Preferred Shares			6,000

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.


Cenovus Energy Inc. – 2024 Annual Information Form			37

Normal Course Issuer Bid

On November 7, 2024, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 127.5 million common shares from November 11, 2024, to November 10, 2025.

For the year ended December 31, 2024, the Company purchased and cancelled 55.9 million common shares (December 31, 2023 – 43.6 million) through the NCIB. The shares were purchased at a volume weighted average price of $25.38 per common share (December 31, 2023 – $24.32) for a total of $1.4 billion (December 31, 2023 – $1.1 billion).

From January 1, 2025, to February 14, 2025, the Company purchased an additional 1.5 million common shares for $32 million. As at February 14, 2025, the Company can further purchase up to 124.9 million common shares under the 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, 2024	Dividend Reset Date	Dividend Rate (percent)	Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	10,740
Series 2 First Preferred Shares (1)	Quarterly	5.21	1,260

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 6.77 percent from December 31, 2023, to March 30, 2024, 6.71 percent from March 31, 2024, to June 29, 2024, 6.60 percent from June 30, 2024, to September 29, 2024 and 5.94 percent from September 30, 2024, to December 30, 2024.

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 should the Company elect to not redeem the shares. On March 31, 2026, and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares (if any) will have such option to convert their shares into the other series. On December 31, 2024, the Company redeemed all series 3 preferred shares. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares (if any) 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 (if any) 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. For the series 1, 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), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, 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), 3.57 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 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, 2024.

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.


Cenovus Energy Inc. – 2024 Annual Information Form			38

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 sedarplus.ca 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 2024 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 2027 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 1, 2024, and is available on SEDAR+ at sedarplus.ca 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 2024 MD&A, which section is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.

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”)

Morningstar

DBRS

(“DBRS”)

Fitch

Ratings Inc.

(“Fitch”)

Senior Unsecured Long-Term Notes

BBB

Baa2

BBB(high)

BBB

Outlook/Trend

Stable

Positive

Stable

Series 1 First Preferred Shares

P-3(High)

—

Pfd-3 (high)

—

Series 2 First Preferred Shares

P-3(High)

—

Pfd-3 (high)

—

Series 5 First Preferred Shares

P-3(High)

—

Pfd-3 (high)

—

Series 7 First Preferred Shares

P-3(High)

—

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.


Cenovus Energy Inc. – 2024 Annual Information Form			39

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. Ratings from AA to CCC may be modified by the addition of a “+” or a “-”. 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. The opinion reflects S&P’s view of the issuer’s capacity and willingness to meet its financial commitments as they come due. 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(High) 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 Positive outlook indicates a higher 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 are of adequate credit quality; however, 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 Pfd-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.

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. 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 Stable Rating Outlook indicates a low likelihood of rating change over a one- to two-year period.


Cenovus Energy Inc. – 2024 Annual Information Form			40

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 2024:


	TSX				NYSE
	Price Range ($ per share)			Volume (1) (thousands)	Price Range (US$ per share)			Volume (2) (thousands)
	High	Low	Close		High	Low	Close
January	22.89	19.82	21.78	219,240	17.19	14.69	16.18	242,698
February	24.34	20.95	23.65	165,199	17.99	15.48	17.43	231,572
March	27.21	23.49	27.08	217,875	20.05	17.41	19.99	245,371
April	29.96	26.90	28.28	207,404	21.90	19.83	20.56	212,394
May	28.82	27.00	28.41	245,073	21.08	19.78	20.82	141,996
June	28.41	24.79	26.89	263,307	20.86	18.03	19.66	140,173
July	28.39	26.20	27.82	146,253	20.75	19.22	20.13	136,452
August	28.05	24.41	24.99	193,400	20.40	17.03	18.54	165,382
September	24.60	21.56	22.62	296,764	18.19	15.83	16.73	180,997
October	25.31	21.93	22.39	187,507	18.61	15.73	16.07	180,674
November	22.95	21.35	22.18	205,578	16.46	15.27	15.77	172,370
December	22.48	20.42	21.79	171,851	15.98	14.20	15.15	143,698

(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. The Series 1 First Preferred Shares, Series 2 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.E and CVE.PR.G, respectively.

The share price trading range and volume of the Cenovus Warrants traded on the TSX and the NYSE in 2024 are provided below:


	TSX				NYSE
	Price Range ($ per share)			Volume (1) (thousands)	Price Range (US$ per share)			Volume (2) (thousands)
	High	Low	Close		High	Low	Close
January	16.21	13.35	15.34	161	12.08	10.01	11.52	22
February	17.62	14.42	17.13	215	13.20	10.88	12.50	50
March	20.60	15.91	20.51	200	15.12	12.75	15.00	30
April	23.29	20.69	21.90	398	17.00	15.24	16.03	131
May	22.24	20.53	21.83	243	16.14	14.15	15.92	34
June	21.23	17.21	20.44	454	14.98	13.27	14.85	28
July	21.86	19.40	21.19	103	15.84	14.05	15.15	28
August	20.88	17.20	18.55	142	15.17	11.85	13.65	43
September	18.00	15.25	16.10	108	13.15	11.25	11.78	19
October	18.69	15.39	15.80	161	13.73	11.10	11.31	17
November	16.58	14.84	15.55	126	12.58	10.66	11.00	75
December	16.00	14.00	15.24	246	11.24	9.82	10.59	82

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

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


Cenovus Energy Inc. – 2024 Annual Information Form			41

The share price trading range and volume of the Series 1 First Preferred Shares traded on the TSX in 2024 are provided below:


	Price Range ($ per share)			Volume (1) (thousands)
	High	Low	Close
January	15.65	13.98	15.65	34
February	15.50	15.00	15.04	350
March	17.35	15.14	16.59	1,298
April	18.38	16.84	17.25	680
May	17.71	16.71	17.53	230
June	17.95	15.80	17.95	118
July	18.00	17.32	17.48	161
August	18.26	17.00	18.09	61
September	18.18	17.19	17.70	78
October	18.57	17.14	17.81	125
November	21.31	17.52	20.98	209
December	21.55	20.33	21.55	66

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

The share price trading range and volume of the Series 2 First Preferred Shares traded on the TSX in 2024 are provided below:


	Price Range ($ per share)			Volume (1) (thousands)
	High	Low	Close
January	16.46	14.93	16.46	123
February	16.95	16.46	16.61	34
March	18.40	16.75	18.35	40
April	19.42	18.27	18.50	53
May	19.20	18.41	19.15	14
June	19.17	17.25	18.10	106
July	18.78	18.02	18.73	22
August	19.55	18.56	19.12	13
September	19.25	18.35	18.90	8
October	19.72	18.51	19.25	43
November	21.95	18.93	21.20	27
December	21.93	20.67	20.67	5

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

The share price trading range and volume of the Series 3 First Preferred Shares traded on the TSX in 2024, prior to their redemption on December 31, 2024, are provided below:


	Price Range ($ per share)			Volume (1) (thousands)
	High	Low	Close
January	22.50	21.30	22.30	622
February	23.16	22.40	23.05	475
March	23.82	22.95	23.75	357
April	24.05	23.55	24.00	540
May	24.47	23.97	24.16	217
June	24.15	23.00	23.99	555
July	24.04	23.76	23.87	127
August	24.29	23.76	24.20	339
September	24.25	23.61	23.94	508
October	24.50	23.60	24.50	135
November	25.21	24.42	25.21	375
December	25.25	24.95	24.99	1,021

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


Cenovus Energy Inc. – 2024 Annual Information Form			42

The share price trading range and volume of the Series 5 First Preferred Shares traded on the TSX in 2024 are provided below:


	Price Range ($ per share)			Volume (1) (thousands)
	High	Low	Close
January	23.64	22.45	23.20	300
February	23.87	23.03	23.65	474
March	23.90	23.25	23.62	163
April	24.00	23.58	23.95	290
May	24.48	23.85	24.41	124
June	24.14	23.05	24.14	334
July	24.34	23.50	24.15	183
August	24.35	23.78	24.15	125
September	24.29	23.74	23.97	73
October	24.42	23.90	24.42	415
November	25.17	24.28	25.00	155
December	25.00	24.64	24.90	320

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

The share price trading range and volume of the Series 7 First Preferred Shares traded on the TSX in 2024 are provided below:


	Price Range ($ per share)			Volume (1) (thousands)
	High	Low	Close
January	22.75	22.09	22.25	61
February	22.81	22.30	22.80	177
March	22.98	22.61	22.95	189
April	23.33	22.87	23.33	129
May	23.97	23.30	23.87	164
June	23.81	22.51	23.76	66
July	24.00	23.60	23.94	69
August	24.15	23.70	24.15	107
September	24.15	23.45	23.83	77
October	24.09	23.55	24.09	255
November	25.06	24.01	24.90	125
December	24.90	24.56	24.75	149

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


Cenovus Energy Inc. – 2024 Annual Information Form			43



DIRECTORS AND EXECUTIVE OFFICERS

Directors

The term of each director is from the effective date of their election or appointment until the end of the next annual general meeting or until a successor is duly elected or appointed. The following individuals are the directors of Cenovus:


Name and Residence	Date Elected or Appointed as Director, Independence Status and Committee Membership	Principal Occupation During the Past Five Years

Stephen E. Bradley Smerillo, Italy	May 1, 2024 Independent Audit SSR	Mr. Bradley is a director of CK Asset Holdings Limited, a publicly traded global property investment, development, management and utility infrastructure company, since November 2020; and a director of Power Assets Holdings Limited, a publicly traded global energy investment company, since May 2022. Mr. Bradley was a director of CNEx (Shanghai International Money Broking Co.), a private broking and information services company from November 2020 to July 2024, and a director of Husky from July 2010 to December 2020, prior to combining with Cenovus in January 2021.

Keith M. Casey San Antonio, Texas United States	April 29, 2020 Independent SSR HRC (1)	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 served as Executive Vice-President Commercial and Value Chain, from August 2016 to October 2018; and Executive Vice-President, Operations from May 2014 to August 2016 with Andeavor Corporation, formerly known as Tesoro Corporation, an integrated petroleum refining, logistics, and marketing company.

Michael J. Crothers Calgary, Alberta Canada	November 1, 2023 Independent Governance HRC (1)	Mr. Crothers is a Director of Keyera Corp., a publicly traded integrated energy infrastructure company, since June 2021. Mr. Crothers served as President and Country Chair for Shell Canada Limited, a public global energy and petrochemical company, from December 2015 to May 2021; and as Vice President Canada Integrated Gas from December 2017 to May 2021. Mr. Crothers also serves as Chair of the Board of Directors of Northern RNA, a private life sciences company, since April 2021, and was a Director of Convrg Innovations Inc., formerly Westgen Technologies, a private clean tech company, from August 2022 to May 2024.

James D. Girgulis Luxembourg Grand-Duchy of Luxembourg	November 1, 2023 Non-Independent (2) SSR	Mr. Girgulis is Managing Director of Hutchison Whampoa Europe Investments S.à r.l., a private investment company, and Managing Director of CK Hutchison Group Telecom Finance S.A., a public limited company, both since January 2023. From April 2022 to January 2023, Mr. Girgulis was Managing Director of CK Hutchison Networks Europe Investments S.à r.l., a private investment company. From April 2021 to March 2022, Mr. Girgulis was Special Advisor to the Executive at Cenovus following Cenovus's combination with Husky in January 2021. Mr. Girgulis was Senior Vice-President, General Counsel & Secretary of Husky, a public integrated energy company, from April 2012 to March 2021.

Jane E. Kinney Toronto, Ontario Canada	April 24, 2019 Independent Audit SSR	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 July 2021. Ms. Kinney was appointed Vice Chair, Leadership Team Member of Deloitte LLP Canada (“Deloitte”), an audit and consulting firm, in June 2010 and served in this role until her retirement in June 2019.

Eva L. Kwok Vancouver, British Columbia Canada	January 1, 2021 Independent Governance	Mrs. Kwok is Chair, a director and Chief Executive Officer of Amara Holdings Inc., a private investment holding company, since November 2010. Mrs. Kwok is also a director of CK Life Sciences Int’l., (Holdings) Inc., a publicly traded nutraceutical, pharmaceutical and agriculture-related company, since June 2002; CK Infrastructure Holdings Limited, a publicly traded global infrastructure investment and development company, since September 2004; CK Asset Holdings Limited, a publicly traded global property investment, development, management and utility infrastructure company, since May 2022; and was a director of Husky, from August 2000 until March 2021, prior to Husky’s amalgamation with Cenovus.


Cenovus Energy Inc. – 2024 Annual Information Form			44


Name and Residence	Date Elected or Appointed as Director, Independence Status and Committee Membership	Principal Occupation During the Past Five Years

Melanie A. Little Alpharetta, Georgia United States	January 1, 2023 Independent SSR HRC (1)	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. 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 acquired by ONEOK in September 2023, 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. Ms. Little served as a director of Diversified Energy Company plc, a public oil and gas producer, from December 2019 to December 2022.

Richard J. Marcogliese Alamo, California United States	April 27, 2016 Independent Audit SSR	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.

Jonathan M. McKenzie Calgary, Alberta Canada	April 26, 2023 Non-Independent (3)	Mr. McKenzie was appointed President & Chief Executive Officer of Cenovus effective April 26, 2023. From January 2021 to April 2023, Mr. McKenzie was Executive Vice-President & Chief Operating Officer of Cenovus; and from May 2018 to January 2021, Mr. McKenzie was Executive Vice-President and Chief Financial Officer of Cenovus.

Claude Mongeau Montreal, Quebec Canada	December 1, 2016 Independent Audit Governance	Mr. Mongeau was appointed Lead Independent Director of Cenovus effective April 26, 2023. Mr. Mongeau is a director of The Toronto-Dominion Bank, an international financial institution, since March 2015; and is Board Chair, since May 2024, and a director since September 2019, of Norfolk Southern Corporation, a publicly traded North American rail transportation provider. Mr. Mongeau served as a director of TELUS Corporation, a publicly traded telecommunications company, from May 2017 to August 2019.

Alexander J. Pourbaix Calgary, Alberta Canada	November 6, 2017 Non-Independent (3)	Mr. Pourbaix was appointed Executive Chair of the Board of Cenovus effective April 26, 2023. Mr. Pourbaix served as President & Chief Executive Officer of Cenovus from November 2017 to April 2023; and is a director of NRG Energy, Inc., a publicly traded energy and home services company, since November 2023; and 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.

Frank J. Sixt Hong Kong Special Administrative Region	January 1, 2021 Independent Governance	Mr. Sixt is an Executive Director, Group Co-Managing Director and Group Finance Director since April 2024, and was Executive Director, Group Finance Director and Deputy Managing Director from June 2015 to March 2024, 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, since December 1999; an Executive Director of CK Infrastructure Holdings Limited, a publicly traded global infrastructure investment and development company, since May 1996; a Non-Executive Director of TPG Telecom Limited since May 2001, and Chairman since December 2023, and a Director, since January 1998, of Hutchison Telecommunications (Australia) Limited, both publicly traded telecommunications service provider companies; and an Alternate Director to a Director of HK Electric Investments Manager Limited as the trustee-manager of HK Electric Investments, a publicly traded power industry focused trust, since June 2015. Mr. Sixt was a Commissioner of PT Indosat Tbk, a publicly traded telecommunications service provider, from January 2022 to September 2023. Mr. Sixt was a director of Husky, from August 2000 until March 2021, prior to Husky’s amalgamation with Cenovus.


Cenovus Energy Inc. – 2024 Annual Information Form			45


Name and Residence	Date Elected or Appointed as Director, Independence Status and Committee Membership	Principal Occupation During the Past Five Years

Rhonda I. Zygocki Friday Harbor, Washington United States	April 27, 2016 Independent Governance HRC (1)	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)Human Resources and Compensation Committee (“HRC”).

(2)Until March 31, 2025, Mr. Girgulis will be considered non-independent pursuant to Canadian securities laws due to his past consulting work as Special Advisor to the Executive at Cenovus until March 31, 2022, following the company’s combination with Husky. Accordingly, Mr. Girgulis is expected to be considered independent effective from April 1, 2025.

(3)As officers and non-independent directors, Messrs. McKenzie and Pourbaix are not members of any of the committees of Cenovus’s Board.

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			Executive Chair of the Board Mr. Pourbaix’s biographical information is included under “Directors”.

Jonathan M. McKenzie Calgary, Alberta Canada			President & Chief Executive Officer Mr. McKenzie’s biographical information is included under “Directors”.

Karamjit S. Sandhar Calgary, Alberta Canada			Executive Vice-President & Chief Financial Officer Mr. Sandhar was appointed Executive Vice-President & Chief Financial Officer, effective September 1, 2023. From January 2021 to August 2023, Mr. Sandhar was Executive Vice-President, Strategy & Corporate Development; from January 2020 to January 2021, Mr. Sandhar was Senior Vice-President, Conventional; and Senior Vice-President, Deep Basin 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.

Keith A. Chiasson (1) Calgary, Alberta Canada			Executive Vice-President & Chief Operating Officer Mr. Chiasson was appointed Executive Vice-President & Chief Operating Officer effective September 1, 2023. From March 2019 to August 2023, Mr. Chiasson was Executive Vice-President, Downstream and from December 2017 to February 2019, Mr. Chiasson was Senior Vice-President, Downstream.

Rhona M. DelFrari (2) Calgary, Alberta Canada			Chief Sustainability Officer & Executive Vice-President, Stakeholder Engagement Ms. DelFrari was appointed Chief Sustainability Officer & Executive Vice-President, Stakeholder Engagement effective March 1, 2023. From January 2021 to February 2023, Ms. DelFrari was Chief Sustainability Officer & Senior Vice-President, Stakeholder Engagement; and from October 2019 to December 2020, Ms. DelFrari was Vice-President, Sustainability & Engagement. On May 1, 2024, Ms. DelFrari commenced a one year sabbatical and Mr. Lawson was appointed Acting Chief Sustainability Officer.

Doreen A. Cole (3) Calgary, Alberta Canada			Executive Vice-President, Downstream Ms. Cole was appointed Executive Vice-President, Downstream effective September 1, 2023. From September 2021 to August 2023, Ms. Cole was Senior Vice-President, Downstream Manufacturing. From December 2017 to July 2021, Ms. Cole was Managing Director of The Syncrude Project, an oil sands joint venture project.

P. Andrew Dahlin (1) Calgary, Alberta Canada			Executive Vice-President, Natural Gas & Technical Services Mr. Dahlin was appointed Executive Vice-President, Natural Gas & Technical Services, effective September 1, 2023. From March 2022 to August 2023, Mr. Dahlin was Executive Vice-President, Corporate & Operations Services; and from January 2021 to February 2022, Mr. Dahlin was Executive Vice-President, Safety & Operations Technical Services. From November 2020 to January 2021, Mr. Dahlin was Executive Vice-President, Downstream & Midstream of Husky; from May 2020 to November 2020, Mr. Dahlin was Executive Vice President, Western Canada Upstream of Husky; and from May 2018 to April 2020, Mr. Dahlin was Senior Vice President, Heavy Oil & Oil Sands of Husky Oil Operations Limited.


Cenovus Energy Inc. – 2024 Annual Information Form			46


Name and Residence			Office Held and Principal Occupation During the Past Five Years

Geoffrey T. Murray Calgary, Alberta Canada			Executive Vice-President, Commercial Mr. Murray was appointed Executive Vice-President, Commercial effective May 1, 2024. Mr. Murray was Senior Vice-President, Commercial August 2023 to May 2024; from January 2021 to August 2023, Mr. Murray was Senior Vice-President, Downstream Marketing, Strategy and Business Development; and from September 2019 to January 2021, Mr. Murray was Vice-President, Downstream Assets.

Norrie C. Ramsay (4) Calgary, Alberta Canada			Executive Vice-President, Upstream – Thermal & Atlantic Offshore Dr. Ramsay was appointed Executive Vice-President, Upstream – Thermal & Atlantic Offshore effective July 31, 2024. Dr. Ramsay was Executive Vice-President, Upstream – Thermal & Offshore April 2024 to July 2024; from January 2021 to April 2024, Dr. Ramsay was Executive Vice-President, Upstream – Thermal, Major Projects & Offshore; from January 2020 to December 2020, Dr. Ramsay was Executive Vice-President, Upstream; and from December 2019 to January 2020, Dr. Ramsay was Executive Vice-President. From September 2015 to November 2019, Dr. Ramsay was Senior Vice-President at TC Energy.

Jeffery G. Lawson (2) Calgary, Alberta Canada			Senior Vice-President, Corporate Development & Acting Chief Sustainability Officer Mr. Lawson was appointed Senior Vice-President, Corporate Development & Acting Chief Sustainability Officer effective May 1, 2024. Mr. Lawson was appointed Acting Chief Sustainability Officer when Ms. DelFrari commenced her sabbatical. Mr. Lawson was Senior Vice-President, Corporate Development from December 2022 to May 2024. From October 2018 to December 2022, Mr. Lawson was Managing Director, Corporate Finance at Peters & Co. Limited.

Gary F. Molnar (5) Calgary, Alberta Canada			Senior Vice-President, Legal, General Counsel & Corporate Secretary Mr. Molnar was appointed Senior Vice-President Legal, General Counsel & Corporate Secretary effective January 1, 2021. From December 2015 to December 2020, Mr. Molnar was Vice-President, Legal, Assistant General Counsel & Corporate Secretary.

Susan M. Anderson (5) (6) Calgary, Alberta Canada			Senior Vice-President, People Services Ms. Anderson was appointed Senior Vice-President, People Services effective March 1, 2022. From January 2021 to February 2022, Ms. Anderson was Vice-President, Supply Chain Management. From November 2017 to January 2021, Ms. Anderson was Vice-President and Chief Procurement Officer of Husky.

(1)Mr. Chiasson announced his retirement and, effective March 1, 2025, Mr. Andrew Dahlin will be appointed Executive Vice President & Chief Operating Officer.

(2)Ms. DelFrari elected not to return from sabbatical. Effective March 1, 2025, Mr. Jeffery Lawson will be appointed Executive Vice-President, Corporate Development & Chief Sustainability Officer.

(3)Ms. Cole announced her retirement and, effective March 1, 2025, Mr. Eric Zimpfer will be the new Head of Downstream.

(4)Mr. Ramsay announced his retirement and, effective March 1, 2025, Mr. John Soini will be appointed Executive Vice-President, Upstream – Thermal & Atlantic Offshore.

(5)Mr. Molnar announced his retirement and, effective March 1, 2025, Ms. Susan Anderson will be appointed Senior Vice-President, Legal, General Counsel & Corporate Secretary.

(6)Ms. Candace Newman will be appointed Senior Vice-President, People Services, effective March 1, 2025.

As of December 31, 2024, all of Cenovus’s directors and executive officers, as a group, beneficially owned or exercised control or direction over, directly or indirectly, 2,409,960 common shares or approximately 0.13 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.


Cenovus Energy Inc. – 2024 Annual Information Form			47

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

(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: Jane E. Kinney and Claude Mongeau. 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.

Jane E. Kinney (Audit Committee Chair)

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.

Stephen E. Bradley

Mr. Bradley holds a Bachelor of Arts degree from Balliol College, Oxford University, a post-graduate diploma from Fudan University, Shanghai and is a member of the Hong Kong Securities and Investment Institute. Mr. Bradley is a director of CK Asset Holdings Limited, a publicly traded global investment, development, management and utility infrastructure company, since November 2020; a director of Power Assets Holdings Limited, a publicly traded global energy investment company, since May 2022; and was a director of CNex (Shanghai International Money Broking Co.), a private broking and information services company, from November 2020 to July 2024.

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 and a member of the Audit Committee 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. – 2024 Annual Information Form			48

Claude Mongeau

Mr. Mongeau holds a Master’s in Business Administration degree from McGill University and has received honorary doctorate degrees from Saint Mary’s University and the University of Windsor. 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.

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 Chair 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, 2024 and 2023:


($ thousands)	2024	2023
Audit Fees (1)	4,809	4,423
Audit-Related Fees (2)	646	655
Tax Fees (3)	103	137
All Other Fees (4)	165	120
Total	5,723	5,335

(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 ESG disclosures, prospectuses and participation fees levied by the Canadian Public Accountability Board.

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

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


Cenovus Energy Inc. – 2024 Annual Information Form			49



LEGAL PROCEEDINGS AND REGULATORY ACTIONS

During the year ended December 31, 2024, 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, 2024, 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.



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 150 Royall St., Suite 101 Canton, MA 02021 U.S.
Tel: 1-866-332-8898 Website: www.investorcentre.com/cenovus


Cenovus Energy Inc. – 2024 Annual Information Form			50



MATERIAL CONTRACTS

Other than as set forth below, during the year ended December 31, 2024, 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.

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 sedarplus.ca and EDGAR at sec.gov.

The following table summarizes the number of Cenovus securities subject to the Transfer Restrictions as at December 31, 2024:


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	17.3
L.F. Investments S.à r.l.	Common Shares	231,194,699	12.7
Total		548,121,750	30.0

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


Cenovus Energy Inc. – 2024 Annual Information Form			51

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 sedarplus.ca 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 is available on SEDAR+ at sedarplus.ca 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 is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.



INTERESTS OF EXPERTS

The Company’s independent registered public accounting firm is PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued a Report of Independent Registered Public Accounting Firm dated February 19, 2025 in respect of the Company’s Consolidated Financial Statements as at December 31, 2024 and December 31, 2023, and for each of the years then ended and on the effectiveness of internal control over financial reporting as at December 31, 2024. PricewaterhouseCoopers LLP has advised that they are independent with respect to the Company within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada, including the Rules of Professional Conduct with Guidance of the Chartered Professional Accountants of Alberta and any applicable legislation or regulations, as well as the rules of the U.S. Securities and Exchange Commission (“SEC”) and the Public Company Accounting Oversight Board on auditor independence.

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.


Cenovus Energy Inc. – 2024 Annual Information Form			52



ADDITIONAL INFORMATION

Additional information relating to Cenovus is available on SEDAR+ at sedarplus.ca, 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, 2024, can be found in Cenovus’s Consolidated Financial Statements and MD&A for the year ended December 31, 2024.

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, 2024, 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 IFRS Accounting Standards, which are generally accepted accounting principles for publicly accountable enterprises in Canada.

Cenovus holds interests in a number of joint ventures, as classified under IFRS Accounting Standards, that are accounted for using the equity method of accounting in our Consolidated Financial Statements, including a 30 percent equity ownership interest in Duvernay and a 40 percent equity ownership interest in HCML. Unless otherwise indicated, the operational events and results from these equity interests including, without limitation, production, reserves, revenues, costs and expenses may not be reflected in the Consolidated Financial Statements or the annual 2024 MD&A. As a result, the disclosure in the annual 2024 MD&A in respect to certain equity method investees may differ from corresponding information in this AIF. Readers are directed to the information contained under the heading “Reserves Data and Other Oil and Gas Information” in this AIF for further information regarding Cenovus’s interests in Duvernay and HCML.



ABBREVIATIONS AND CONVERSIONS

Crude Oil and NGLs

Natural Gas

Other

bbl

barrel

Mcf

thousand cubic feet

BOE

barrel of oil equivalent

Mbbls/d

thousand barrels per day

MMcf

million cubic feet

MBOE/d

thousand barrels of oil equivalent per day

MMbbls

million barrels

MMcf/d

million cubic feet per day

MMBOE

million barrels of oil equivalent

WTI

West Texas Intermediate

Bcf

billion cubic feet

OPEC

Organization of Petroleum Exporting Countries

WCS

Western Canadian Select

MMBtu

million British thermal units

OPEC+

OPEC and a group of 10 non-OPEC members

AWB

Access Western Blend

GHG

greenhouse gas

CDB

Christina Dilbit Blend

AECO

Alberta Energy Company

CLB

Cold Lake Blend

LLB

Lloyd Blend

WDB

Western Canada Dilbit Blend

In this AIF, natural gas volumes are 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. – 2024 Annual Information Form			53



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”, “plan”, “potential”, “progress”, “schedule”, “target”, “view” and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: returning incremental value to shareholders in accordance with the capital allocation framework; net debt targets and excess free funds flow; share repurchases under the NCIB; the impacts of the FNMPC; in respect of the White Rose project and SeaRose FPSO, commissioning activities and restart of operations, resuming production and achieving first oil; development of the Narrows Lake resource and timing to achieve first oil from the field; development of the MDK fields and anticipated timing with respect to production; exploration and development at Block DW-1; expected levels and timing of production for any facility, project, segment or the Company as a whole; the evaluation of a carbon capture and sequestration project at Minnedosa; the redemption of the Company’s preferred shares; the use of financial derivatives and other arrangements; investing in technology; improving operating practices; collaborating with third parties to find innovative solutions to minimize Cenovus’s environmental impact and maximize business value; relationships with Indigenous communities and other stakeholders; human rights; sustainable operation of the business; funding future development costs; margins and Netbacks; optimizing product mix, delivery points, transportation commitments and customer diversification; unlocking resource potential; creating additional transportation options for our products; capturing global prices for crude oil production; capturing value; forecast operating and financial results; forecast capital expenditures; techniques expected to be used to recover reserves; abandonment and reclamation costs; funding decommissioning liabilities; expected payment of taxes, royalties and other payments; potential impacts of various identified risk factors, including those related to commodity prices; credit ratings and cost of financing; reserves and related information, development of reserves, future net revenue, future development costs and funding of future development costs; expected capacities, including for projects, processing, storage, transportation and refining; interest and cost of external funding; regulatory, partner or internal approvals; impact of regulatory measures; forecast commodity prices, inflation, exchange rates 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 Company’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 bitumen, crude 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 of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs; 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, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions and the supply and demand for bitumen, 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 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 Company shares for cancellation at prices acceptable to the Company; the Company’s ability to use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates; 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 at a reasonable cost 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 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 flow to meet current and future obligations; estimated abandonment and reclamation costs,


Cenovus Energy Inc. – 2024 Annual Information Form			54

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 goals and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government and industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2025 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. 2025 guidance, as updated December 11, 2024, and available on cenovus.com, assumes: Brent prices of US$74.00 per barrel, WTI prices of US$70.00 per barrel; WCS of US$56.00 per barrel; Differential WTI-WCS of US$14.00 per barrel; AECO natural gas prices of $2.05 per Mcf; Chicago 3-2-1 crack spread of US$18.50 per barrel; and an exchange rate of $0.72 US$/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 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 goals and the commercial viability and scalability of emission reduction strategies and related technology and products; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; the Company’s ability to integrate upstream and downstream operations to help mitigate the impact of volatility in light-heavy crude oil differentials and contribute to its net earnings; foreign exchange risk, including related to agreements denominated in foreign currencies; 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, the impact of tariffs and responses thereto, currency and interest rates; 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; the ability to complete and optimize drilling, completion, tie-in and infrastructure projects; the ability of the Company to ramp-up activities at its refineries on its anticipated timelines; 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; tax audits and reassessments; 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; geopolitical and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the


Cenovus Energy Inc. – 2024 Annual Information Form			55

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 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 sedarplus.ca, 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. – 2024 Annual Information Form			56



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, 2024. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2024, 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, 2024, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation’s management and 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, 2024	Canada	85,168
McDaniel & Associates Consultants Ltd.	December 31, 2024	China	2,667
McDaniel & Associates Consultants Ltd.	December 31, 2024	Indonesia	563
GLJ Ltd.	December 31, 2024	Canada	2,617
			91,015

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 the effective date of our reports.

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

Executed as to our report referred to above:


/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 18, 2025


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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. The report of 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 Safety, Sustainability and Reserves Committee of 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/ Jonathan M. McKenzie						/s/ Karamjit S. Sandhar

Jonathan M. McKenzie President & Chief Executive Officer Cenovus Energy Inc.						Karamjit S. Sandhar Executive Vice-President & Chief Financial Officer Cenovus Energy Inc.

/s/ Alexander J. Pourbaix						/s/ Richard J. Marcogliese

Alexander J. Pourbaix Executive Chair Cenovus Energy Inc.						Richard J. Marcogliese Director and Chair of the Safety, Sustainability and Reserves Committee Cenovus Energy Inc.

February 19, 2025


Cenovus Energy Inc. – 2024 Annual Information Form			58



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.

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.


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(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.

(e)Review the findings of any significant examination by regulators and government agencies, that may have a material impact on the interim or annual financial statements or other documents filed with securities regulators containing financial information and related corporate compliance policies and programs.

(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.


Cenovus Energy Inc. – 2024 Annual Information Form			62

(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)Review and discuss the Corporation’s cyber security and cyber risks, receive reports from management on the occurrence of significant cyber incidents, and assess the steps management has taken to:

(i)develop and implement cyber security processes, procedures, and technology; and

(ii)identify, monitor, control, and mitigate the impacts of cyber risks to the Corporation.

(k)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.

(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.


Cenovus Energy Inc. – 2024 Annual Information Form			63

(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.Oversight Over the Internal Audit Group

(a)The Committee will have unrestricted access to the head of internal audit.

(b)Meet with the head of internal audit without the presence of management on a quarterly basis or ad hoc basis.

(c)Review and approve the appointment, compensation, performance, replacement, reassignment, or dismissal of the head of internal audit.

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

(e)Review and confirm the independence of the internal audit group annually.

(f)Approve the Internal Audit Charter and the Internal Audit Plan annually.

(g)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.

(h)Review and evaluate summaries of all internal audit reports and other communications between internal audit and senior management.


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(i)Monitor management’s action plan to address the results of internal audit engagements.

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 cyber security and 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.

(b)Monitoring development of legal and regulatory requirements related to integrated reporting affecting financial reporting and disclosures, including climate disclosures.

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;


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(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: December 11, 2024


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EX-99.2 3 a2024managementsdiscussion.htm EX-99.2 Document

Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Year Ended December 31, 2024

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS


For the year ended December 31, 2024


OVERVIEW OF CENOVUS						3

YEAR IN REVIEW						3
OPERATING AND FINANCIAL RESULTS						6
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS						11
OUTLOOK						14
REPORTABLE SEGMENTS						17
UPSTREAM						17
OIL SANDS						17
CONVENTIONAL						22
OFFSHORE						24
DOWNSTREAM						28
CANADIAN REFINING						28
U.S. REFINING						29
CORPORATE AND ELIMINATIONS						32
QUARTERLY RESULTS						34
OIL AND GAS RESERVES						37
LIQUIDITY AND CAPITAL RESOURCES						38
RISK MANAGEMENT AND RISK FACTORS						43
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES						62
CONTROL ENVIRONMENT						65
ADVISORY						66
ABBREVIATIONS AND DEFINITIONS						69
SPECIFIED FINANCIAL MEASURES						70
PRIOR PERIOD REVISIONS						81

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, joint arrangements, and partnership interests held directly or indirectly by, Cenovus Energy Inc.) dated February 19, 2025, should be read in conjunction with our December 31, 2024 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”). All of the information and statements contained in this MD&A are made as at February 19, 2025, 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 19, 2025. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR+ at sedarplus.ca, 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, do not constitute part of this MD&A.

Cenovus holds equity ownership interests in a number of joint ventures, as classified under IFRS Accounting Standards, that are accounted for using the equity method in our Consolidated Financial Statements. Unless otherwise indicated, operational results of these joint ventures are not reflected in this MD&A. For further information, see the Advisory section of this MD&A.

Basis of Presentation

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


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			2



OVERVIEW OF CENOVUS

We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are one of the largest Canadian-based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the largest Canadian-based refiners and upgraders, with downstream operations in Canada and the United States (“U.S.”).

For a description of our business segments see the Reportable Segments section of this MD&A.

Our Strategy

At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five strategic objectives include: delivering top-tier safety performance and sustainability leadership; maximizing value through competitive cost structures and optimizing margins; a focus on financial discipline, including maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle; and absolute and per share free funds flow growth.

On December 12, 2024, we released our 2025 corporate guidance which focused on disciplined capital allocation in support of increasing shareholder returns over time. We will continue to be focused on controlling costs, improving the profitability of our strategic downstream business and optimizing our advantaged portfolio to deliver value for our shareholders. For further details, see the Outlook section of this MD&A and our 2025 corporate guidance dated December 11, 2024, available on our website at cenovus.com.



YEAR IN REVIEW

Overall, our 2024 results reflect strong operational performance in the upstream business, steady performance in our Canadian Refining business and improving performance in the U.S. Refining business. Constructive crude oil prices, including the narrowing of the light-heavy price differential, benefited our upstream financial results while declining market crack spreads along with the narrowing of the WTI-WCS and upgrading differentials had a significant impact on our downstream Operating Margin. In addition, we:

•Delivered safe and reliable upstream performance. Upstream production averaged 797.2 thousand BOE per day, compared with 778.7 thousand BOE per day in 2023, primarily driven by strong performance from our Oil Sands assets. Oil Sands production averaged 610.7 thousand BOE per day, our highest-ever annual production, compared with 595.4 thousand BOE per day in 2023. The increase in production is attributed to successful results from our redevelopment, sustaining, growth and optimization programs.

•Achieved Offshore milestones. We progressed the West White Rose project and are on track to deliver first oil in 2026. The project is approximately 88 percent complete and mechanical completion of the topsides and concrete gravity structure occurred in the fourth quarter. Refit work on the SeaRose floating production, storage and offloading (“FPSO”) vessel was completed and the vessel returned to the field in November. The SeaRose FPSO is on station and reconnected to the White Rose field. Production is expected to resume late February 2025.

•Advanced our Oil Sands growth projects. We achieved significant milestones on our major upstream growth projects including mechanical completion of the Narrows Lake pipeline to Christina Lake, bringing three well pads online as part of the Sunrise growth program and progressing construction of the Foster Creek optimization project, which was approximately 64 percent complete as at December 31, 2024. At our Lloydminster conventional heavy oil assets, we continue to progress our planned drilling program.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			3

•Improved U.S. Refining throughput and refined product production. Average crude oil unit throughput (or “throughput”) increased 96.7 thousand barrels per day compared with 2023, to 556.4 thousand barrels per day in 2024. Refined product production averaged 590.0 thousand barrels per day, an increase of 105.0 thousand barrels per day from 2023. The increases in throughput and refined product production were mainly driven by a full year of production at the Toledo and Superior refineries combined with improved reliability across our U.S. Refining operations.

•Safely completed significant turnarounds. In the Canadian Refining segment, we completed the largest turnaround in the asset’s history at the Lloydminster Upgrader (“Upgrader”) that ran from early May until early July. In the U.S. Refining segment, we completed a significant turnaround at the Lima Refinery as well as a turnaround at our non-operated Borger Refinery. In our upstream operations, we completed turnarounds at Christina Lake and at certain Conventional assets.

•Generated cash from operating activities of $9.2 billion. Cash from operating activities increased by $1.8 billion compared with 2023. Adjusted Funds Flow was $8.2 billion, a decrease of $639 million compared with 2023, reflecting weaker market crack spreads that impacted our downstream results, partially offset by strong upstream performance due to higher realized pricing and increased sales volumes. The Chicago 3-2-1 crack spread declined 31 percent to US$16.74 per barrel compared with 2023.

•Increased our target returns to shareholders. On achieving our Net Debt target, in the third quarter we increased target returns to shareholders, stewarding to 100 percent of Excess Free Funds Flow over time. In the year, we returned $3.2 billion to common and preferred shareholders, comprising the purchase of 55.9 million common shares for $1.4 billion through our normal course issuer bid (“NCIB”), $1.5 billion through common share base and variable dividends, $45 million through preferred share dividends and the redemption of all 10.0 million of the Company’s series 3 preferred shares at a price of $25.00 per share, for a total of $250 million.

•Raised our common share base dividend. Beginning in the second quarter, the Board approved a 29 percent increase in the base dividend to $0.720 per common share annually. On February 19, 2025, the Board declared a first quarter base dividend of $0.180 per common share.

•Upgraded credit ratings. We achieved our mid-BBB credit ratings target with all agencies, following S&P Global’s upgrade of Cenovus to BBB with a Stable outlook on March 18, 2024. This upgrade is a reflection of our debt reduction, financial policy track record and operational momentum.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			4

Summary of Annual Results


($ millions, except where indicated)	2024	2023	2022

Upstream Production Volumes (1) (MBOE/d)	797.2	778.7	786.2

Downstream Total Processed Inputs (2) (3) (Mbbls/d)	678.0	586.8	513.0

Crude Oil Unit Throughput (2) (Mbbls/d)	646.9	560.4	493.7

Downstream Production Volumes (Mbbls/d)	693.1	599.2	525.1

Revenues	54,277	52,204	66,897

Operating Margin (4)	10,809	11,022	14,263
Operating Margin – Upstream (5)	11,121	9,870	11,824
Operating Margin – Downstream (5)	(312)	1,152	2,439

Cash From (Used In) Operating Activities	9,235	7,388	11,403

Adjusted Funds Flow (4)	8,164	8,803	10,978
Per Share – Basic (4) ($)	4.41	4.64	5.63
Per Share – Diluted (4) ($)	4.38	4.54	5.47

Capital Investment	5,015	4,298	3,708

Free Funds Flow (4)	3,149	4,505	7,270

Net Earnings (Loss)	3,142	4,109	6,450
Per Share – Basic ($)	1.68	2.15	3.29
Per Share – Diluted ($)	1.67	2.09	3.20

Total Assets	56,539	53,915	55,869

Total Long-Term Liabilities (4)	19,408	18,993	20,259

Long-Term Debt, Including Current Portion	7,534	7,108	8,691

Net Debt	4,614	5,060	4,282

Cash Returns to Common and Preferred Shareholders	3,246	2,798	3,457
Common Shares – Base Dividends	1,255	990	682
Base Dividends Per Common Share ($)	0.680	0.525	0.350
Common Shares – Variable Dividends	251	—	219
Variable Dividends Per Common Share ($)	0.135	—	0.114
Purchase of Common Shares Under NCIB	1,445	1,061	2,530
Payment for Purchase of Warrants	—	711	—
Dividends Paid on Preferred Shares	45	36	26
Preferred Share Redemption	250	—	—

(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)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

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

(5)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			5



OPERATING AND FINANCIAL RESULTS

Selected Operating and Financial Results — Upstream


	Year Ended December 31,
				Percent Change
		2024			2023
Production Volumes by Segment (1) (MBOE/d)
Oil Sands			610.7	3		595.4
Conventional			119.9	—		119.9
Offshore			66.6	5		63.4
Total Production Volumes			797.2	2		778.7

Production Volumes by Product (1)
Bitumen (Mbbls/d)			591.3	3		576.7
Heavy Crude Oil (Mbbls/d)			17.6	5		16.7
Light Crude Oil (Mbbls/d)			12.9	(9)		14.1
NGLs (Mbbls/d)			32.0	(2)		32.5
Conventional Natural Gas (MMcf/d)			860.2	3		832.6
Total Production Volumes (MBOE/d)			797.2	2		778.7

Per-Unit Operating Expenses by Segment (2) ($/BOE)
Oil Sands			11.40	(9)		12.54
Conventional			11.99	(8)		13.02
Offshore (3)			19.27	12		17.20

Oil and Gas Reserves (MMBOE) (4)
Total Proved			5,664	(3)		5,866
Probable			2,793	(2)		2,836
Total Proved Plus Probable			8,457	(3)		8,702

(1)Refer to the Oil Sands, Conventional or Offshore Reportable Segments section of this MD&A for a summary of production by product type by segment. Includes Cenovus’s 40 percent equity interest in Husky-CNOOC Madura Ltd. (“HCML”) joint venture, which is 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. Offshore Per-Unit Operating Expenses reflect Cenovus’s 40 percent equity interest in the HCML joint venture. Operating expenses for the Offshore segment, excluding Indonesia, for the year ended December 31, 2024, was $423 million (2023 – $384 million).

(4)Includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay Energy Corporation (“Duvernay”) joint venture and Cenovus’s 40 percent equity interest in the HCML joint venture.

Production

Total upstream production increased in 2024 compared with 2023 due to:

•Successful results from our redevelopment, sustaining, growth and optimization programs in our Oil Sands segment.

•A full year of production from the Terra Nova FPSO resuming production in November 2023.

•Increased production in Indonesia from the MAC field which had first gas in the fourth quarter of 2023.

The increase year-over-year is also due to lower production in 2023 in China following the temporary unplanned outage from the disconnection of the umbilical by a third-party vessel in April 2023. The production increases in 2024 were partially offset by turnaround activities in the Oil Sands and Conventional segments, and the suspension of production at the White Rose field in December 2023 for the SeaRose asset life extension (“ALE”) project in the Atlantic region.

In our Conventional segment, production volumes were consistent year-over-year. Production increased due to less well downtime in 2024 compared with 2023, partially offset by the divestiture of non-core assets. Well downtime in 2024 related to planned turnaround activity, while 2023 downtime was primarily in response to wildfire activity. In the second half of 2024, production was impacted by the deferral of new well development in response to lower natural gas benchmark prices.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			6

Per-Unit Operating Expenses

For the year ended December 31, 2024, per-unit operating expenses decreased in the Oil Sands segment, compared with 2023, mainly due to lower fuel costs as a result of significant declines in natural gas pricing and increased sales volumes. Per-unit operating expenses decreased in the Conventional segment, compared with 2023, mainly due to lower processing and gathering costs, electricity costs and workover costs, partially offset by increased repairs and maintenance costs. Per-unit operating expenses increased in the Offshore segment, compared with 2023, primarily due to higher repairs and maintenance and vessel mooring costs related to the SeaRose ALE project, and higher repairs and maintenance costs at the Terra Nova field. Overall, the Company has managed inflationary pressures through the use of long-term contracts, working with vendors and managing the timing of purchases of long-lead items.

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 as at December 31, 2024, were approximately 5.7 billion BOE and 8.5 billion BOE, respectively. Total proved reserves and total proved plus probable reserves each decreased three percent compared with 2023.

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

Selected Operating and Financial Results — Downstream


	Year Ended December 31,
				Percent Change
		2024			2023
Crude Oil Unit Throughput by Segment (Mbbls/d)
Canadian Refining			90.5	(10)		100.7
U.S. Refining			556.4	21		459.7
Total Crude Oil Unit Throughput			646.9	15		560.4

Production Volumes by Product (1) (Mbbls/d)
Gasoline			280.5	21		231.2
Distillates (2)			219.9	22		179.9
Synthetic Crude Oil			41.0	(14)		47.6
Asphalt			44.0	25		35.2
Ethanol			4.8	(4)		5.0
Other			102.9	3		100.3
Total Production Volumes			693.1	16		599.2

Per-Unit Operating Expenses by Segment (3) (4) ($/bbl)
Canadian Refining			22.56	68		13.40
U.S. Refining			12.99	(11)		14.63

Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3) ($/bbl)
Canadian Refining			15.38	16		13.29
U.S. Refining			11.55	(18)		14.01

(1)Refer to the Canadian Refining and U.S. Refining Reportable Segments section of this MD&A for a summary of production by product by segment.

(2)Includes diesel and jet fuel.

(3)Specified financial measure. Per-unit metrics are calculated based on total processed inputs. See the Specified Financial Measures Advisory of this MD&A.

(4)Inclusive of turnaround costs. In the Canadian Refining segment, operating expenses represent expenses associated with the Lloydminster Upgrader, the Lloydminster Refinery and the commercial fuels business.

We safely completed two significant turnarounds, as well as a turnaround at the Borger Refinery, in our refining segments in 2024. In Canada, we completed a turnaround at the Upgrader, which was the largest in its history in scope and cost, that ran from early May to early July. In the U.S., we completed a significant turnaround at the Lima Refinery that ran from early September to late October.

In 2024, total downstream throughput and refined product production increased compared with 2023. Throughput and production increased due to realizing a full year of production at the Toledo and Superior refineries, combined with improved reliability at our operated and non-operated refineries. We acquired the Toledo Refinery on February 28, 2023 (the “Toledo Acquisition”) and the Superior Refinery ramped up throughout 2023. The increases were partially offset by reduced throughput and production during the turnarounds discussed above.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			7

In 2024, per-unit operating expenses, excluding turnaround costs, increased in the Canadian Refining segment compared with 2023, primarily due to reliability projects completed during the turnaround period. Per-unit operating expenses, excluding turnaround costs, in the U.S. Refining segment decreased year-over-year primarily due to the increase in total processed inputs.

Selected Consolidated Financial Results

Revenues

Revenues increased four percent compared with 2023. Upstream revenue increased seven percent compared with 2023, primarily due to the narrowing of the WTI-WCS and condensate-WCS differentials following the start-up of the Trans Mountain Pipeline expansion project (“TMX”) and increased sales volumes. Downstream revenues increased three percent compared with 2023, primarily due to higher sales volumes in the U.S. Refining segment, partially offset by lower refined product pricing.

Operating Margin

Operating Margin is a non-GAAP 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.


	Year Ended December 31,
($ millions)		2024	2023
Gross Sales
External Sales		57,726	55,474
Intersegment Sales		8,970	8,234
		66,696	63,708
Royalties		(3,449)	(3,270)
Revenues		63,247	60,438
Expenses
Purchased Product		33,926	31,425
Transportation and Blending		11,331	11,088
Operating Expenses		7,159	6,891
Realized (Gain) Loss on Risk Management Activities		22	12
Operating Margin		10,809	11,022

Operating Margin by Segment

Years Ended December 31, 2024 and 2023


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			8

Operating Margin decreased compared with 2023. The increase in revenues, as discussed above, was more than offset by:

•Lower market crack spreads impacting our U.S. Refining segment and higher heavy crude oil costs affecting both of our refining segments.

•Higher operating expenses due to turnaround activity at the Upgrader, Lima Refinery and Christina Lake assets.

•Higher transportation expenses impacting our Oil Sands segment due to higher sales volumes exported to destinations outside of Alberta. This includes transportation expenses related to our use of TMX and increased pipeline transportation rates on shipments to U.S. destinations.

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


	Year Ended December 31,
($ millions)		2024	2023
Cash From (Used in) Operating Activities		9,235	7,388
(Add) Deduct:
Settlement of Decommissioning Liabilities		(234)	(222)
Net Change in Non-Cash Working Capital		1,305	(1,193)
Adjusted Funds Flow		8,164	8,803

Adjusted Funds Flow was lower in 2024, compared with 2023, primarily due to an increase in current tax expense, the decrease in Operating Margin and higher long-term incentive costs paid, partially offset by a realized foreign exchange gain in 2024, compared with a realized foreign exchange loss in 2023.

Cash from operating activities increased in 2024, compared with 2023, primarily due to a working capital release, which more than offset the decrease in Adjusted Funds Flow. The net change in non-cash working capital was primarily due to a source of cash in 2024 as accounts receivables decreased, and accounts payable and taxes payable increased, compared with a use of cash in 2023 mainly caused by an income tax liability from 2022 that was paid in the first quarter of 2023.

Net Earnings (Loss)

Net earnings in 2024 was $3.1 billion (2023 – $4.1 billion). The decrease was primarily due to foreign exchange losses, higher depreciation, depletion, amortization and exploration expense, lower Operating Margin, and higher general and administrative expense. The decrease was partially offset by gains on the divestiture of non-core assets in 2024.

Net Debt


As at ($ millions)	December 31, 2024	December 31, 2023
Short-Term Borrowings	173	179
Current Portion of Long-Term Debt	192	—
Long-Term Portion of Long-Term Debt	7,342	7,108
Total Debt	7,707	7,287
Cash and Cash Equivalents	(3,093)	(2,227)
Net Debt	4,614	5,060

Long-term debt increased by $426 million from December 31, 2023, primarily due to an unrealized loss of $442 million resulting from the weakening of the Canadian dollar relative to the U.S. dollar, impacting the translation of our U.S. denominated debt. Net Debt decreased by $446 million from December 31, 2023, mainly due to cash from operating activities of $9.2 billion, partially offset by capital investment of $5.0 billion, cash returns to common and preferred shareholders of $3.2 billion and the increase in long-term debt discussed above. For further details, see the Liquidity and Capital Resources section of this MD&A.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			9

Capital Investment (1)


	Year Ended December 31,
($ millions)		2024		2023
Upstream
Oil Sands			2,714		2,382
Conventional			421		452
Offshore			1,145		642
Total Upstream			4,280		3,476
Downstream
Canadian Refining			208		145
U.S. Refining			488		602
Total Downstream			696		747
Corporate and Eliminations			39		75
Total Capital Investment			5,015		4,298

(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets and capitalized interest. Excludes capital expenditures related to the Company’s joint ventures.

Capital investment in 2024 was mainly related to:

•Sustaining, redevelopment and optimization programs in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated winter program.

•The progression of the West White Rose project and the execution of the SeaRose ALE project.

•Sustaining activities at our operated Canadian and U.S. refining assets, and refining reliability projects at our non-operated refineries.

•Growth projects in our Oil Sands segment, including the mechanical completion of the Narrows Lake pipeline to Christina Lake, the optimization project at Foster Creek, the Sunrise growth program and the progression of the planned drilling program at our Lloydminster conventional heavy oil assets.

•Drilling, completion, tie-in and infrastructure projects in the Conventional segment.

Drilling Activity


	Net Stratigraphic Test Wells and Observation Wells		Net Production Wells (1)
	2024	2023	2024	2023
Foster Creek	85	87	22	44
Christina Lake	61	53	23	27
Sunrise	40	38	14	24
Lloydminster Thermal	53	71	22	9
Lloydminster Conventional Heavy Oil	19	3	49	34

Other	—	3	—	—
	258	255	130	138

(1)Steam-assisted gravity drainage (“SAGD”) well pairs in the Oil Sands segment are counted as a single producing well.

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


	2024			2023
(net wells)	Drilled (1)	Completed	Tied-in	Drilled	Completed	Tied-in
Conventional	36	31	31	38	37	41

(1)Includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay joint venture.

In the Offshore segment, we drilled and evaluated one exploration well in China (2023 – drilled and completed one (0.4 net) development well at the MAC field in Indonesia).


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			10



COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined product prices and 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$/bbl, unless otherwise indicated)	2024	Percent Change	2023	Q4 2024	Q3 2024	Q4 2023
Dated Brent	80.76	(2)	82.62	74.69	80.18	84.05
WTI	75.72	(2)	77.62	70.27	75.09	78.32
Differential Dated Brent - WTI	5.04	1	5.00	4.42	5.09	5.73
WCS at Hardisty	60.97	3	58.97	57.71	61.54	56.43
Differential WTI - WCS at Hardisty	14.75	(21)	18.65	12.56	13.55	21.89
WCS at Hardisty (C$/bbl)	83.52	5	79.59	80.74	83.95	76.95
WCS at Nederland	69.69	—	69.74	65.69	68.51	71.59
Differential WTI - WCS at Nederland	6.03	(23)	7.88	4.58	6.58	6.73
Condensate (C5 at Edmonton)	72.94	(5)	76.61	70.66	71.19	76.24
Differential Condensate - WTI Premium/(Discount)	(2.78)	175	(1.01)	0.39	(3.90)	(2.08)
Differential Condensate - WCS at Hardisty Premium/ (Discount)	11.97	(32)	17.64	12.95	9.65	19.81
Condensate (C$/bbl)	99.92	(3)	103.43	98.84	97.10	103.90
Synthetic at Edmonton	75.07	(6)	79.61	71.11	76.41	78.64
Differential Synthetic - WTI Premium/(Discount)	(0.65)	(133)	1.99	0.84	1.32	0.32
Synthetic at Edmonton (C$/bbl)	102.83	(4)	107.47	99.45	104.22	107.21
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	89.95	(8)	97.86	78.95	92.29	83.72
Chicago Ultra-low Sulphur Diesel (“ULSD”)	97.47	(11)	109.70	89.28	96.55	107.24
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)	16.74	(31)	24.19	12.12	18.62	13.24
Group 3 3-2-1 Crack Spread (2)	16.81	(43)	29.66	12.66	18.95	18.55
Renewable Identification Numbers (“RINs”)	3.74	(47)	7.04	4.02	3.89	4.77
Upgrading Differential (3) (C$/bbl)	19.21	(30)	27.55	18.64	20.26	29.97
Natural Gas Prices
AECO (4) (C$/Mcf)	1.46	(45)	2.64	1.48	0.69	2.30
NYMEX (5) (US$/Mcf)	2.27	(17)	2.74	2.79	2.16	2.88
Foreign Exchange Rates
US$ per C$1 – Average	0.730	(1)	0.741	0.715	0.733	0.734
US$ per C$1 – End of Period	0.695	(8)	0.756	0.695	0.741	0.756
RMB per C$1 – Average	5.255	—	5.247	5.142	5.255	5.304

(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 Upstream 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.

(3)The upgrading differential is the difference between synthetic crude oil at Edmonton and Lloydminster Blend crude oil at Hardisty. The upgrading differential does not precisely mirror the configuration and the product output of our refineries; however, it is used as a general market indicator.

(4)Alberta Energy Company ("AECO") 5A natural gas daily index.

(5)New York Mercantile Exchange (“NYMEX”) natural gas monthly index.

Crude Oil and Condensate Benchmarks

In 2024, crude oil benchmark prices, Brent and WTI decreased compared with 2023. Prices were higher in the first half of 2024, compared with the first half of 2023, as geopolitical events related to Russia and Ukraine, Israel and Gaza, Iran, the Red Sea, Venezuela and Guyana added to volatility and risk premiums, but had a limited impact on physical supply and demand in global oil markets. Weaker than expected global demand and potential unwinding of OPEC+ voluntary production cuts further weighed on prices in the second half of 2024, which was partially offset by low global inventories of crude. Global supply and demand were relatively balanced through 2024 as OPEC+ policy continued to support markets through the year as plans to unwind voluntary cuts were extended through the first quarter of 2025.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			11

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 in 2024 was relatively consistent compared with 2023.

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. The WTI-WCS differential at Hardisty narrowed in 2024, compared with 2023, due to the start-up of TMX increasing market access for WCS crude, the impact of Saudi Arabia’s voluntary production cuts, which are weighted towards medium and heavy crude, and stronger global demand for heavy crude.

WCS at Nederland is a heavy oil benchmark for sales of our product at the U.S. Gulf Coast (“USGC”). The WTI-WCS at Nederland differential is representative of the heavy oil quality differential and is influenced by global heavy oil refining capacity and global heavy oil supply. In 2024, the WTI-WCS at Nederland differential narrowed compared with 2023, due to the continued voluntary production cuts from OPEC+ members, including Saudi Arabia.

In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the 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.

In 2024, synthetic crude oil at Edmonton was priced at a discount to WTI, compared with a premium to WTI in 2023. The weakness in pricing relative to 2023 was a function of deep discounts in the first quarter of 2024, due to high synthetic crude oil production in Alberta, supply of light crude being above pipeline capacity on light crude pipelines and limited local storage capacity.

Crude Oil Benchmark Prices (1)

(1)Forward pricing as at January 31, 2025.

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 20 percent to 35 percent. The Condensate-WCS differential is an important benchmark, as a higher premium generally results in a decrease in operating margin 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 blended product sales.

In 2024, the average Edmonton condensate benchmark traded at a greater discount to WTI compared with 2023. Weakness was influenced by low light crude oil prices in the first quarter of 2024 in Alberta, as an oversupply of light crude exceeded pipeline takeaway capacity.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			12

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.

In 2024, refined product prices declined compared with 2023, due to high global and regional supply of refined products as a result of incremental global refining capacity additions and U.S. refineries operating at high utilization rates for most of 2024. Refinery utilization in PADD 2 remained high throughout the fourth quarter of 2024, despite lower seasonal demand for gasoline, which resulted in the Chicago 3-2-1 crack spread weakening by US$1.00/bbl relative to the fourth quarter of 2023. Average cost of RINs were also lower in 2024 compared with 2023, due to a decline in biofuel feedstock costs and increased renewable diesel production.

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 refining margins are affected by various other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the feedstock 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, or the location we sell product; however, they are used as a general market indicator.

Refined Product Benchmarks (1)

(1)Forward pricing as at January 31, 2025.

Natural Gas Benchmarks

In 2024, average NYMEX and AECO natural gas prices decreased compared with 2023, due to high production, high inventory levels and mild weather in the U.S. and Western Canada. AECO prices weakened further relative to NYMEX natural gas due to limited Western Canadian takeaway capacity. 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. dollar 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. Changes in foreign exchange rates also impact the translation of our U.S. and Asia Pacific operations.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			13

In 2024, on average, the Canadian dollar weakened relative to the U.S. dollar compared with 2023, positively impacting our reported revenues. The Canadian dollar weakened relative to the U.S. dollar as at December 31, 2024, compared with December 31, 2023, resulting in unrealized foreign exchange losses on the translation of our U.S. dollar debt.

A portion of our long-term sales contracts in the Asia Pacific region 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 2024, on average, the Canadian dollar was relatively consistent with the RMB compared with 2023.

Interest Rate Benchmarks

Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. A change in interest rates could change our net finance costs, affect how certain liabilities are measured, and impact our cash flow and financial results.

As at December 31, 2024, the Bank of Canada’s Policy Interest Rate was 3.25 percent, a decrease from 5.00 percent on December 31, 2023. On January 29, 2025, the Bank of Canada reduced the overnight rate by 25 basis points to 3.00 percent due to the easing of inflation concerns and the threat of trade tariffs.



OUTLOOK

Commodity Price Outlook

Although discussions continue regarding a potential economic arrangement between the U.S. and Canada, there remains significant uncertainty over whether tariffs, surtaxes, or other restrictive trade measures or countermeasures will be implemented. Potential measures could include, among others, increased tariffs on Canadian energy exports, restrictions on cross-border supply chains, or additional regulatory barriers that could have a significant impact on the market for crude oil, NGLs, natural gas and refined petroleum products in Canada and internationally, and could result in, among other things, a high degree of both cost and price volatility, a relative weakening of the Canadian dollar and widening differentials. We continue to monitor these developments closely; however, these matters have introduced uncertainty and volatility in the market. The scope, impact and duration of any measures implemented remain uncertain at this time.

Global crude oil prices have trended lower in 2024, compared with 2023, as OPEC+ announced its intention to end production cuts that have supported prices. OPEC+ plans to gradually unwind voluntary cuts over 18 months starting April 2025. Non-OPEC+ supply growth, led by U.S. shale, has been robust and is expected to continue to grow in 2025, though slowing U.S. drilling activity since 2023 has softened the expectations for U.S. supply growth modestly. Demand growth has continued, but has been weaker than in 2023, due to lower than expected Chinese demand growth, which has also weighed on prices. Current geopolitical risks are causing volatility in global oil prices, with any escalation causing prices to rise and any de-escalation causing prices to settle. With planned production growth expected from OPEC+ due to the unwinding of production cuts, and high Middle East spare production capacity, geopolitical tensions are not impacting global oil prices as much as they would have in an under-supplied or more balanced global oil market.

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.

OPEC+ policy continues to remain crucial to global oil supply and demand balances, and prices. In the U.S., Trump administration policies around tariffs, trade relations, global conflicts and domestic supply will be key considerations for energy prices. Global policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shift global trade patterns. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-OPEC+ supply growth, the potential for resumed crisis in Israel and Gaza if the ceasefire breaks down including any spread to a wider conflict, developments relating to conflicts involving Iran and attacks on vessels in the Red Sea, and tensions between Venezuela and Guyana.

In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession remain a risk to the pace of demand growth.

Refined product prices have declined in 2024 compared with 2023, as a result of incremental global capacity additions, reduced RIN prices, and U.S. refineries operating at very high utilization rates. Forward curves are showing signs of refined product prices strengthening in 2025.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			14

In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:

•We expect the WTI-WCS at Hardisty 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. As expected, the start-up of TMX in 2024 is having a narrowing impact on WTI-WCS differentials.

•We expect refined product prices will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies continue to impact demand. Refined product prices and market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America and globally.

•NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and ample natural gas in storage, although the prospect of new LNG facilities in the U.S. coming into service or ramping up in the next 12 months could increase demand and support natural gas prices on NYMEX. Weather will continue to be a key driver of demand and impact prices.

•We expect the Canadian dollar to continue to be impacted by 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, Trump administration policies toward Canada-U.S. trade, crude oil prices and emerging macro-economic factors.

Most of our upstream crude oil and downstream refined product production is exposed to movements in the WTI crude oil price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane, and is used as crude oil feedstock at our downstream refining operations. Condensate extracted from our blended crude oil is sold back to 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 market crack spreads in these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly.

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 and spreads on refined products.

•Monitoring market fundamentals and optimizing run rates at our refineries accordingly.

•Traditional crude oil storage tanks in various geographic locations.

Key Priorities for 2025

Our 2025 priorities are focused on top-tier safety performance, improved reliability in our downstream business, maintaining and growing our competitive advantages in our Oil Sands business and execution on our growth projects. We will continue to maintain returns to shareholders and focus on cost and sustainability improvements.

Top-tier Safety Performance

Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, and aim to be best-in-class operators for each of our major assets and businesses.

Downstream Competitiveness

A competitive, reliable downstream business is essential to our integrated business. It allows us to be agile in our response to fluctuating demand for refined products and serves as a natural partial hedge in times of widening location and heavy oil differentials.

We will continue to target improved reliability of our downstream assets, leveraging our upstream expertise to maximize the long-term profitability of our assets.

Oil Sands Business

Our Oil Sands business is the backbone of our company. Maintaining and growing our competitive advantages while operating safely and reliably is critical to our company.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			15

Project Execution

Investing in future growth is a focus for us, with several key projects underway, including the West White Rose project, the optimization and sulphur recovery projects at Foster Creek, the Sunrise growth program and the Lloydminster conventional heavy oil growth project. We plan to continue to execute these multi-year projects on time and on budget.

We made the decision to recalibrate work on the enterprise-wide IT systems upgrades to a more fit for purpose outcome. Certain components of the project, including the replacement of Cenovus’s enterprise resource planning systems, will be put on hold as a result of continuing to focus on controlling corporate costs. Work will continue on cyber security resilience and standardization of data governance to enhance efficiency and effectiveness of the Company’s systems.

Cost Leadership

We aim to maximize shareholder value through continued focus on low cost structures and margin optimization across our business. We are focused on reducing operating, capital and general and administrative costs, realizing the full value of our integrated strategy while making decisions that support long-term value for Cenovus.

Returns to Shareholders

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. We plan to steward Net Debt to $4.0 billion and return 100 percent of Excess Free Funds Flow to shareholders over time. For further details, see the Liquidity and Capital Resources section of this MD&A.

Sustainability

Sustainability is central to Cenovus’s culture. We have established ambitious targets in our five environmental, social and governance (“ESG”) focus areas, and we continue to advance work to support progress against these targets.

We continue to support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal and provincial governments that provide a sufficient level of fiscal support to progress large-scale carbon capture projects, while maintaining global competitiveness. It is critical that the federal and provincial governments provide support at a level consistent with what similar large-scale carbon capture projects are receiving globally to enable Canada to achieve its greenhouse gas (“GHG”) emissions goals.

Additional information on Cenovus’s performance in safety, Indigenous reconciliation, and inclusion and diversity is available in Cenovus’s 2023 Corporate Social Responsibility report on our website at cenovus.com.

2025 Corporate Guidance

Our corporate guidance dated December 11, 2024, is available on our website at cenovus.com.

Our 2025 corporate guidance for total capital investment is between $4.6 billion and $5.0 billion. This includes $3.2 billion directed towards sustaining capital to maintain base production and support continued safe and reliable operations, and between $1.4 billion and $1.8 billion in optimization and growth capital.

Optimization and growth capital will be directed mainly toward:

•Installation and commissioning of the West White Rose project.

•Progressing the optimization and the enhanced sulphur recovery projects at Foster Creek.

•Drilling new well pads at Sunrise and development drilling at our conventional heavy oil business in the Lloydminster area.

•Initiatives in our downstream business to improve safety, maintenance and reliability.

The following table shows our corporate guidance for 2025:


	Capital Investment ($ millions)	Production (MBOE/d)	Crude Oil Unit Throughput (Mbbls/d)
Upstream
Oil Sands	2,700 - 2,800	615 - 635
Conventional	350 - 400	125 - 135
Offshore	900 - 1,000	65 - 75
Upstream Total	3,950 - 4,200	805 - 845

Downstream	650 - 750		650 - 685

Corporate and Eliminations	Up to 50


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			16



REPORTABLE SEGMENTS

The Company operates through the following reportable segments:

Upstream Segments

•Offshore, includes offshore operations, exploration and development activities in the east coast of Canada and the Asia Pacific region, representing China and the equity-accounted investment in HCML, which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia.

Downstream Segments

•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment also includes the jointly-owned Wood River and Borger refineries, held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.

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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.

UPSTREAM

Oil Sands

In 2024, we:

•Delivered safe and reliable operations, including the safe execution of a turnaround at Christina Lake which was completed ahead of schedule.

•Produced 610.7 thousand BOE per day, our highest-ever annual production (2023 – 595.4 thousand BOE per day).

•Delivered successful results from our redevelopment, sustaining, growth and optimization programs.

•Generated Operating Margin of $9.8 billion, an increase of $1.6 billion compared with 2023, due to higher average Realized Sales Prices, higher sales volumes and lower fuel operating costs.

•Earned a Netback of $44.88 per BOE (2023 – $38.10 per BOE).

•Invested capital of $2.7 billion for sustaining activities and growth projects. We mechanically completed the Narrows Lake pipeline to Christina Lake and brought three well pads online as part of the Sunrise growth program.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			17

Financial Results



($ millions)	2024	2023
Gross Sales
External Sales	21,857	20,608
Intersegment Sales	6,590	5,584
	28,447	26,192
Royalties	(3,274)	(3,059)
Revenues	25,173	23,133
Expenses
Purchased Product	1,851	1,457
Transportation and Blending	11,000	10,774
Operating	2,511	2,716
Realized (Gain) Loss on Risk Management	20	17
Operating Margin	9,791	8,169
Unrealized (Gain) Loss on Risk Management	(16)	15
Depreciation, Depletion and Amortization	3,117	2,993
Exploration Expense	2	19
(Income) Loss from Equity-Accounted Affiliates	(14)	6
Segment Income (Loss)	6,702	5,136

Operating Margin Variance

Year Ended December 31, 2024

(1)Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses.

(2)Includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil or natural gas.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			18

Operating Results



	2024	2023
Total Sales Volumes (1) (MBOE/d)	599.5	589.5

Realized Sales Price (2) ($/BOE)	80.20	73.02

Crude Oil Production by Asset (Mbbls/d)
Foster Creek	196.0	186.3
Christina Lake	234.2	237.4
Sunrise	49.6	48.9
Lloydminster Thermal	111.5	104.1
Lloydminster Conventional Heavy Oil	17.6	16.7
Total Crude Oil Production (3) (Mbbls/d)	608.9	593.4
Natural Gas (4) (MMcf/d)	11.1	11.9
Total Production (MBOE/d)	610.7	595.4

Effective Royalty Rate (5) (percent)
Foster Creek	24.0	25.1
Christina Lake	27.3	29.5
Sunrise	6.1	6.8
Lloydminster (6)	11.7	9.5
Total Effective Royalty Rate	21.0	21.9

Transportation and Blending Expense (7) ($/BOE)	9.00	8.18

Operating Expense (7) ($/BOE)	11.40	12.54

Per-Unit DD&A (7) ($/BOE)	13.49	12.94

(1)Bitumen, heavy crude oil and natural gas.

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

(3)Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.

(4)Conventional natural gas product type.

(5)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.

(6)Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets.

(7)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

Revenues

Gross sales increased in 2024 compared with 2023, due to increased Realized Sales Prices as a result of the narrowing of the WTI-WCS and condensate-WCS differentials following the startup of TMX, and increased sales volumes.

Price

Our bitumen and heavy oil production must be blended with condensate to reduce its viscosity in order to transport it to market through pipelines. Within our Netback calculations, our realized bitumen and heavy oil sales price excludes the impact of purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending increases relative to the price of blended crude oil or our blend ratio increases, our realized bitumen and heavy oil sales price decreases.

Our Realized Sales Price increased in 2024, compared with 2023, mainly due to narrower WTI-WCS and condensate-WCS differentials, driven by the start-up of TMX.

In 2024, approximately 33 percent (2023 – 25 percent) of our crude oil sales volumes were sold to destinations outside of Alberta and approximately 20 percent (2023 – 20 percent) of our Oil Sands crude oil sales volumes were sold to our Canadian and U.S. downstream operations.

Cenovus makes storage and transportation decisions to use our marketing and transportation infrastructure, including storage and pipeline assets, in order to optimize product mix, delivery points, transportation commitments and customer diversification. To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			19

Production Volumes

Oil Sands crude oil production increased in 2024 compared with 2023 due to:

•Less well downtime and successful results from our sustaining and optimization programs at Foster Creek.

•Successful results from our redevelopment and optimization programs at our Lloydminster assets.

•Positive results from our sustaining, redevelopment, growth and optimization programs at Sunrise.

The increase was partially offset by turnaround activity in September 2024 at Christina Lake.

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 one percent of product revenues and the post-payout calculation is based on 20 percent of operating margin. The freehold calculation is limited to post-payout projects and is based on an eight percent rate.

In 2024, Oil Sands royalties increased compared with 2023, primarily due to higher realized pricing and sales volumes. The Oil Sands effective royalty rate decreased slightly primarily due to annual adjustments on the end-of-period filings, partially offset by higher realized prices compared with 2023.

Expenses

Transportation and Blending

In 2024, blending expenses increased $6 million compared with 2023, due to higher sales volumes partially offset by lower condensate prices.

In 2024, transportation expenses and per-unit transportation expenses increased, compared with 2023, due to higher sales volumes exported to destinations outside of Alberta, which includes transportation costs related to our use of TMX, and increased pipeline transportation rates on shipments to U.S. destinations.

Per-Unit Transportation Expenses (1)



($/BOE)	2024	2023
Foster Creek	13.57	11.98
Christina Lake	6.53	6.69
Sunrise	16.07	12.47
Lloydminster (2)	3.95	3.51
Total Oil Sands	9.00	8.18

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

(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.

At Foster Creek, per-unit transportation expenses increased primarily due to higher costs as a result of the start-up of TMX, partially offset by lower rail transportation costs. In 2024, we had West Coast sales of 20 percent and volumes sold to U.S. destinations of 37 percent, a decrease from 44 percent of sales to U.S. destinations in 2023.

At Christina Lake, per-unit transportation expenses decreased primarily due to lower rail costs, partially offset by increased pipeline transportation costs. In 2024, we shipped 18 percent (2023 – 18 percent) of Christina Lake volumes to U.S. destinations.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			20

At Sunrise, per-unit transportation expenses increased primarily due to the use of TMX and increased sales volumes to U.S. destinations. In 2024, sales to U.S. destinations increased to 67 percent from 50 percent in 2023. In addition, 18 percent of sales were on the West Coast due to the use of TMX in 2024.

At Lloydminster, per-unit transportation expenses increased primarily due to higher pipeline transportation rates and increased sales outside of Alberta. We shipped three percent to U.S. destinations (2023 – no sales to U.S. destinations) and approximately 55 percent of production to our Canadian Refining operations.

Operating

Primary drivers of our operating expenses in 2024 were fuel, repairs and maintenance, and workforce. Total operating expenses in 2024 decreased compared with 2023, due to lower fuel costs as a result of significant declines in AECO benchmark prices. The decreases were partially offset by higher repairs and maintenance costs and GHG compliance costs. We have experienced some inflationary pressures on our costs; however, we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.

Per-Unit Operating Expenses (1)



($/BOE)	2024	Percent Change	2023
Foster Creek
Fuel	2.10	(40)	3.48
Non-Fuel	7.77	(2)	7.96
Total	9.87	(14)	11.44
Christina Lake
Fuel	2.09	(30)	2.98
Non-Fuel	6.54	18	5.54
Total	8.63	1	8.52
Sunrise
Fuel	2.89	(40)	4.78
Non-Fuel	11.47	(6)	12.24
Total	14.36	(16)	17.02
Lloydminster (2)
Fuel	2.74	(40)	4.54
Non-Fuel	14.78	(6)	15.78
Total	17.52	(14)	20.32

Total Oil Sands
Fuel	2.30	(36)	3.60
Non-Fuel	9.10	2	8.94
Total	11.40	(9)	12.54

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

(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.

Per-unit fuel expenses decreased overall due to significantly lower natural gas prices, as discussed above.

Foster Creek per-unit non-fuel expenses slightly decreased in 2024, compared with 2023, due to lower electricity costs and increased sales volumes, partially offset by increased workover activity and GHG compliance costs.

Christina Lake per-unit non-fuel expenses increased in 2024, compared with 2023, due to higher turnaround activity, workover activity and GHG compliance costs.

Sunrise per-unit non-fuel expenses decreased in 2024, compared with 2023, due to increased sales volumes and lower electricity costs, partially offset by increased repairs and maintenance costs.

Lloydminster per-unit non-fuel expenses decreased in 2024, compared with 2023, due to increased sales volumes combined with lower chemical costs and workover activity, partially offset by increased GHG compliance costs.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			21

Netback (1)



($/BOE)	2024	2023
Sales Price	80.20	73.02
Royalties	14.92	14.20
Transportation and Blending	9.00	8.18
Operating Expenses	11.40	12.54
Netback	44.88	38.10

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

Conventional

In 2024, we:

•Delivered safe and reliable operations, including safely executing turnarounds.

•Produced 119.9 thousand BOE per day (2023 – 119.9 thousand BOE per day).

•Generated Operating Margin of $291 million, a decrease of $292 million from 2023, primarily due to lower natural gas benchmark prices.

•Averaged a Netback of $6.48 per BOE (2023 – $12.02 per BOE).

•Invested capital of $421 million with a continued focus on drilling, completion, tie-in and infrastructure projects.

Financial Results



($ millions)	2024	2023

Gross Sales
External Sales	1,211	1,488
Intersegment Sales	1,848	1,785
	3,059	3,273
Royalties	(76)	(112)
Revenues	2,983	3,161
Expenses
Purchased Product	1,823	1,695
Transportation and Blending	320	298
Operating	555	590
Realized (Gain) Loss on Risk Management	(6)	(5)
Operating Margin	291	583
Unrealized (Gain) Loss on Risk Management	4	(19)
Depreciation, Depletion and Amortization	442	386
Exploration Expense	1	6
(Income) Loss From Equity-Accounted Affiliates	2	—
Segment Income (Loss)	(158)	210


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			22

Operating Margin Variance

Year Ended December 31, 2024

(1)Changes to price include the impact of realized risk management gains and losses.

(2)Reflects Operating Margin from processing facilities.

Operating Results



	2024	2023
Total Sales Volumes (MBOE/d)	119.9	119.9

Realized Sales Price (1) ($/BOE)	25.18	31.76
Light Crude Oil ($/bbl)	92.68	101.34
NGLs ($/bbl)	54.62	48.25
Conventional Natural Gas ($/Mcf)	2.51	3.91

Production by Product
Light Crude Oil (Mbbls/d)	4.9	5.9
NGLs (Mbbls/d)	21.0	21.7
Conventional Natural Gas (MMcf/d)	563.8	554.1
Total Production (MBOE/d)	119.9	119.9

Conventional Natural Gas Production (percentage of total)	78	77
Crude Oil and NGLs Production (percentage of total)	22	23

Effective Royalty Rate (2) (percent)	10.3	10.8

Transportation Expense (3) ($/BOE)	4.98	4.16

Operating Expense (3) ($/BOE)	11.99	13.02

Per-Unit DD&A (3) ($/BOE)	9.90	8.76

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

(2)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.

(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

Revenues

Gross sales decreased in 2024 compared with 2023, due to decreased benchmark pricing.

Price

Our total Realized Sales Price decreased in 2024, compared with 2023, primarily due to lower natural gas benchmark prices. For the year ended December 31, 2024, the AECO natural gas benchmark price declined 45 percent compared with 2023.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			23

Production Volumes

Production volumes were consistent in 2024, compared with 2023. In 2024, production increased due to less well downtime compared with 2023, partially offset by the divestiture of non-core assets. Well downtime in 2024 related to planned turnaround activity in the third quarter, while 2023 downtime was primarily in response to wildfire activity. In the second half of 2024, production was impacted by the deferral of new well development in response to lower natural gas benchmark prices.

Royalties

The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties decreased in 2024, compared with 2023, primarily due to lower natural gas benchmark prices.

Expenses

Transportation

Our transportation expenses reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. In 2024, transportation expenses and per-unit transportation expenses increased primarily due to increased pipeline transportation rates, compared with 2023.

Operating

Primary drivers of operating expenses in 2024 were repairs and maintenance, workforce and property tax costs. Total operating expense and per-unit operating costs decreased compared with 2023, primarily due to lower processing and gathering costs, electricity costs and workover costs, partially offset by increased repairs and maintenance costs driven by higher turnaround activity.

In 2024, we completed five turnarounds in our Conventional segment and incurred $40 million in turnaround costs (2023 – $9 million). Per-unit operating expenses excluding turnaround costs were $11.08 per BOE (2023 – $12.82 per BOE).

Netback (1)



($/BOE)	2024	2023
Sales Price	25.18	31.76
Royalties	1.73	2.56
Transportation and Blending	4.98	4.16
Operating Expenses	11.99	13.02
Netback	6.48	12.02

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

Offshore

In 2024, we:

•Delivered safe and reliable operations.

•Produced 66.6 thousand BOE per day of light crude oil, NGLs and natural gas (2023 – 63.4 thousand BOE per day).

•Generated Operating Margin of $1.0 billion, a decrease of $79 million from 2023, primarily due to lower Realized Sales Price and increased operating expenses.

•Averaged a Netback of $52.38 per BOE (2023 – $56.48 per BOE).

•Invested capital of $1.1 billion, mainly related to the progression of the West White Rose project and the execution of the SeaRose ALE project.

In late December 2023, we suspended production at the White Rose field as we prepared for the SeaRose ALE project. Refit work that commenced in the first quarter of 2024 was completed and the vessel returned to the field in November. The SeaRose FPSO is on station and reconnected to the White Rose field. Production is expected to resume late February 2025.

We have made significant progress on the West White Rose project and we are on track to deliver first oil in 2026. The project is approximately 88 percent complete and mechanical completion of the topsides and concrete gravity structure occurred in the fourth quarter. The focus in 2025 will be on installation and commissioning of the platform as we prepare to transition the project from construction to operations. Since our decision in 2022 to restart the project, we have invested approximately $1.6 billion.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			24

Financial Results



	2024			2023
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	322	1,250	1,572	400	1,217	1,617
Intersegment Sales	—	—	—	—	—	—
	322	1,250	1,572	400	1,217	1,617
Royalties	(2)	(97)	(99)	(15)	(84)	(99)
Revenues	320	1,153	1,473	385	1,133	1,518
Expenses
Transportation and Blending	11	—	11	16	—	16
Operating	290	133	423	262	122	384
Operating Margin (1)	19	1,020	1,039	107	1,011	1,118
Depreciation, Depletion and Amortization			563			487
Exploration Expense			66			17
(Income) Loss from Equity-Accounted Affiliates			(53)			(57)
Segment Income (Loss)			463			671

(1)Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Specified Financial Measures Advisory of this MD&A.

Operating Margin Variance

Year Ended December 31, 2024


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			25

Operating Results



	2024	2023
Sales Volumes
Atlantic (Mbbls/d)	8.0	9.6
Asia Pacific (MBOE/d)
China	42.6	40.5
Indonesia (1)	16.0	14.7
Total Asia Pacific	58.6	55.2
Total Sales Volumes (MBOE/d)	66.6	64.8

Realized Sales Price (1) (2) ($/BOE)	78.40	81.63

Atlantic - Light Crude Oil ($/bbl)	109.58	113.74

Asia Pacific (1) ($/BOE)	74.13	76.04
NGLs ($/bbl)	97.59	99.73
Conventional Natural Gas ($/Mcf)	11.45	11.71

Production by Product
Atlantic – Light Crude Oil (Mbbls/d)	8.0	8.2
Asia Pacific (1)
NGLs (Mbbls/d)	11.0	10.8
Conventional Natural Gas (MMcf/d)	285.3	266.6
Total Asia Pacific (MBOE/d)	58.6	55.2
Total Production (MBOE/d)	66.6	63.4

Effective Royalty Rate (3) (percent)
Atlantic	0.7	3.7
Asia Pacific (1)	9.5	10.3

Operating Expense (2) ($/BOE)	19.27	17.20
Atlantic (4)	97.70	67.93
Asia Pacific (1) (2)	8.52	8.37

Per-Unit DD&A (4) ($/BOE)	22.33	25.57

(1)Reported sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 40 percent equity interest in the HCML joint venture. The HCML joint venture is accounted for using the equity method in the Consolidated Financial Statements.

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

(3)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.

(4)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

Revenues

Gross sales decreased in 2024, compared with 2023, due to a decrease in Realized Sales Price resulting from lower Brent benchmark pricing, partially offset by an increase in sales volumes in China.

Price

Our Atlantic Realized Sales Price on light crude oil decreased in 2024, compared with 2023, due to lower Brent benchmark pricing. The prices we receive for natural gas sold in Asia Pacific are set under long-term contracts.

Production Volumes

Atlantic production decreased in 2024, compared with 2023, primarily due to the suspension of production at the White Rose field in December 2023 for the SeaRose ALE project, partially offset by resuming production at the Terra Nova field in November 2023. Light crude oil production from the White Rose and Terra Nova fields are offloaded from the SeaRose and Terra Nova FPSOs, respectively, to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales.

Asia Pacific production increased in 2024, compared with 2023, due to less well downtime in China and higher production from the MAC field in Indonesia that came online in September 2023. In 2023, well downtime was due to the temporary unplanned outage that occurred in the second quarter of 2023, related to the disconnection of the umbilical by a third-party vessel.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			26

Royalties

For the year ended December 31, 2024, Atlantic royalties and the effective royalty rate decreased compared with 2023. The decreases were due to suspended production at the White Rose field for all of 2024, which has a higher effective royalty rate. All production in 2024 was at the Terra Nova field with a lower effective royalty rate.

Royalty rates in Asia Pacific are governed by production-sharing contracts, in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for Asia Pacific for 2024 declined compared with 2023, primarily due to a production bonus paid to the Government of Indonesia for achieving a production milestone in the first quarter of 2023, partially offset by a consumption tax implemented in China in June 2023 and in effect for the full year of 2024.

Expenses

Transportation

Transportation expenses include the costs of transporting crude oil from the Terra Nova FPSO and SeaRose FPSO vessels to onshore terminals via tankers, as well as storage costs. Transportation expenses for the year ended December 31, 2024, were $11 million (2023 – $16 million).

Operating

Primary drivers of our Atlantic operating expenses in 2024 were repairs and maintenance, costs related to vessels and air services, and workforce. Operating expenses increased compared with 2023, primarily due to higher repairs and maintenance and vessel mooring costs related to the SeaRose ALE project, and higher repairs and maintenance costs at the Terra Nova field. Per-unit operating expenses increased in 2024 compared with 2023, mainly due to the same factors discussed above and lower sales volumes.

Primary drivers of our China operating expenses in 2024 were repairs and maintenance, workforce costs and insurance. For the year ended December 31, 2024, operating expenses increased compared with 2023, primarily due to higher insurance costs, workforce, and repairs and maintenance costs. Per-unit operating expenses increased compared with 2023, mainly due to the factors discussed above, partially offset by higher sales volumes.

For the year ended December 31, 2024, Indonesia per-unit operating expenses increased compared with 2023, due to increased repairs and maintenance costs and workforce costs, partially offset by higher sales volumes.

Netbacks (1)


	2024
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Sales Price		109.58	80.26		57.82		78.40
Royalties		0.72	6.19		9.32		6.29
Transportation and Blending		3.81	—		—		0.46
Operating Expenses		97.70	7.61		10.93		19.27
Netback		7.35	66.46		37.57		52.38


	2023
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Sales Price		113.74	82.14		59.16		81.63
Royalties		4.24	5.68		13.75		7.29
Transportation and Blending		4.44	—		—		0.66
Operating Expenses		67.93	7.51		10.76		17.20
Netback		37.13	68.95		34.65		56.48

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

(2)Reported sales volumes and associated per-unit values reflect Cenovus’s 40 percent equity interest in the HCML joint venture. The HCML joint venture is accounted for using the equity method in the Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			27

DOWNSTREAM

Canadian Refining

In 2024, we:

•Delivered safe and reliable operations.

•Safely completed the largest turnaround in the Upgrader’s history, which commenced in May and ramped up to full operations in July.

•Achieved crude unit utilization of 84 percent with throughput of 90.5 thousand barrels per day (2023 – 93 percent and 100.7 thousand barrels per day, respectively).

•Incurred per-unit operating expenses excluding turnaround costs of $15.38 per barrel (2023 – $13.29 per barrel).

•Recorded an Operating Margin shortfall of $80 million, a decrease of $755 million from 2023, mainly due to lower production volumes due to the turnaround and lower commodity prices.

•Invested capital of $208 million, primarily focused on sustaining activities.

Financial and Operating Results



($ millions, except where indicated)	2024	2023
Gross Sales
External Sales	4,787	5,385
Intersegment Sales	523	848
Revenues	5,310	6,233
Purchased Product	4,483	4,919
Gross Margin (1)	827	1,314
Expenses
Operating	907	639
Operating Margin	(80)	675
Depreciation, Depletion and Amortization	185	185
Segment Income (Loss)	(265)	490

Operable Capacity (2) (Mbbls/d)	108.0	108.0

Total Processed Inputs (3) (Mbbls/d)	96.6	107.1

Crude Oil Unit Throughput (Mbbls/d)	90.5	100.7

Crude Unit Utilization (4) (percent)	84	93

Total Production (Mbbls/d)	103.1	114.2
Synthetic Crude Oil	41.0	47.6
Asphalt	15.7	15.4
Diesel	10.8	12.9
Other	30.8	33.3
Ethanol	4.8	5.0

Refining Margin (1) ($/bbl)	20.82	30.13

(1)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader, commercial fuels business and the Lloydminster Refinery for the year ended December 31, 2024, were $5.0 billion (2023 – $5.8 billion).

(2)Operable capacity is the capacity based on throughput barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. We previously reported crude oil name plate capacity. See the Abbreviations and Definitions section of this MD&A.

(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

(4)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.

In 2024, throughput and production were lower at our Canadian Refining assets compared with 2023, primarily due to the planned turnaround at the Upgrader that ran from early May to early July and the ramp-up to full operations that followed.

Revenues, Gross Margin and Refining Margin

The Upgrader processes blended heavy crude oil and bitumen into high-value synthetic crude oil and low-sulphur diesel. 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 and bitumen feedstock.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			28

The Lloydminster Refinery processes blended heavy crude oil into asphalt, bulk distillates and industrial products. Gross Margin is largely dependent on asphalt and industrial products pricing and the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery are seasonal and increase during paving season, which typically runs from May through October each year.

The Upgrader and Lloydminster Refinery source crude oil feedstock from our Oil Sands segment. In 2024, approximately 12 percent of total crude oil sales volumes from our Oil Sands assets were sold to our Canadian Refining segment (2023 – 13 percent).

Revenues decreased compared with 2023, due to decreased synthetic crude oil and diesel benchmark prices and lower production, as discussed above. Gross Margin and per-barrel Refining Margin decreased compared with 2023, due to lower sales prices, lower production and higher feedstock costs.

Operating Expenses

The following table and discussion represent operating expenses associated with the Upgrader, the Lloydminster Refinery and the commercial fuels business.



($ millions, except where indicated)	2024	2023

Operating Expenses - Upgrading and Refining	798	524
Operating Expenses – Excluding Turnaround Costs	544	520
Operating Expenses – Turnaround Costs	254	4

Per-Unit Operating Expenses (1) ($/bbl)	22.56	13.40
Per-Unit Operating Expenses – Excluding Turnaround Costs (1)	15.38	13.29
Per-Unit Operating Expenses – Turnaround Costs (1)	7.18	0.11

(1)Specified financial measure. Per-unit metrics are calculated on total processed inputs. Changes in metrics from prior periods have been re-presented. See the Specified Financial Measures Advisory of this MD&A.

Primary drivers of operating expenses were turnaround costs, workforce costs, and repairs and maintenance. In 2024, operating expenses excluding turnaround costs increased compared with 2023, primarily due to projects related to reliability that occurred during the turnaround period at the Upgrader. The increase in operating expenses, combined with decreased total processed inputs, resulted in increased per-unit operating expenses compared with 2023.

U.S. Refining

In 2024, we:

•Delivered safe operations.

•Safely completed a significant turnaround at the Lima Refinery that ran from early September until late October.

•Achieved crude unit utilization of 91 percent (2023 – 78 percent) and increased throughput to 556.4 thousand barrels per day compared with 459.7 thousand barrels per day in 2023.

•Achieved per-unit operating expenses excluding turnaround costs of $11.55 per barrel (2023 – $14.01 per barrel).

•Recorded an Operating Margin shortfall of $232 million, a decrease of $709 million from 2023. The decrease was primarily due to lower market crack spreads year-over-year with a sharp decline in the fourth quarter, a narrower WTI-WCS differential at Hardisty and the impact of the turnaround at the Lima Refinery, partially offset by the lower cost of RINs.

•Invested capital of $488 million, primarily focused on sustaining activities at our operated assets and refining reliability projects at our non-operated assets.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			29

Financial and Operating Results



($ millions, except where indicated)	2024	2023
Gross Sales
External Sales	28,299	26,376
Intersegment Sales	9	17
Revenues	28,308	26,393
Purchased Product	25,769	23,354
Gross Margin (1)	2,539	3,039
Expenses

Operating	2,763	2,562
Realized (Gain) Loss on Risk Management	8	—
Operating Margin	(232)	477
Unrealized (Gain) Loss on Risk Management	8	(17)
Depreciation, Depletion and Amortization	462	486
Segment Income (Loss)	(702)	8

Operable Capacity (2) (Mbbls/d)	612.3	612.3

Total Processed Inputs (3) (Mbbls/d)	581.4	479.7

Crude Oil Unit Throughput (Mbbls/d)	556.4	459.7
Heavy Crude Oil	219.6	173.9
Light/Medium Crude Oil	336.8	285.8

Crude Unit Utilization (4) (5) (percent)	91	78

Total Refined Product Production (Mbbls/d)	590.0	485.0
Gasoline	280.5	231.2
Distillates (6)	209.1	167.0
Asphalt	28.3	19.8
Other	72.1	67.0

Refining Margin (1) ($/bbl)	11.93	17.36
Weighted Average Crack Spread, Net of RINs (7) (US$/bbl)	13.01	18.15
Weighted Average Crack Spread, Net of RINs (7) (C$/bbl)	17.82	24.49
Market Capture (1) (5) (8) (percent)	67	71

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

(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

(4)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.

(5)The Superior Refinery’s operable capacity is included in the metrics effective April 1, 2023. The Toledo Refinery includes a weighted average operable capacity in the metrics, as full ownership of the Toledo Refinery was acquired on February 28, 2023.

(6)Includes diesel and jet fuel.

(7)Weighted average crack spread, net of RINs is calculated as Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs. Average foreign exchange rates in the period are used to convert to Canadian dollars.

(8)The definition of Market Capture is Refining Margin divided by the weighted average crack spread, net of RINs, expressed as a percentage.

Throughput and refined product production increased in 2024, compared with 2023, primarily due to full operations from the Toledo Acquisition and the ramp-up of the Superior Refinery in 2023, combined with improved reliability across our U.S. Refining operations. The increases were partially offset by the turnaround at the Lima Refinery and unplanned outages at our refineries throughout the year. We were able to partially mitigate the impact of the Lima Refinery turnaround on production by processing Lima intermediate products at our Toledo Refinery, allowing the Lima Refinery’s crude unit to continue operations. In addition, we completed a turnaround at the non-operated Borger Refinery in 2024, compared with two turnarounds in 2023.

Revenues

Revenues increased in 2024, compared with 2023, due to higher sales volumes. The increase was partially offset by declines in benchmark gasoline and diesel prices of eight percent and 11 percent, respectively, compared with 2023.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			30

Gross Margin and Market Capture

Market crack spreads do not precisely mirror the refinery configuration for crude diet and product yields, or the location we sell product; 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. Some of these factors include the type of crude oil feedstock processed; refinery configuration and the proportion of gasoline, distillates 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.

Gross Margin decreased 16 percent in 2024 compared with 2023, primarily due to lower market crack spreads and the 21 percent narrower WTI-WCS differential at Hardisty due to the start-up of TMX, which increased the cost of heavy crude entering our refineries. The Chicago 3-2-1 crack spread decreased 31 percent and the Group 3 3-2-1 crack spread decreased 43 percent, compared with 2023. These factors, combined with the increase in total processed inputs compared with 2023, also decreased our per-barrel Refining Margin.

Market Capture is the Refining Margin, calculated on a FIFO basis of accounting, generated as a percentage of the weighted average market crack spread, net of RINs. The Chicago and Group 3 3-2-1 market crack spreads are used to calculate Market Capture, with a heavier weighting towards Chicago 3-2-1.

In 2024, Market Capture decreased compared with 2023, primarily due to the narrowing of the WTI-WCS differential at Hardisty, as discussed above.

Operating Expenses



($ millions, except where indicated)	2024	2023
Operating Expenses	2,763	2,562
Operating Expenses – Excluding Turnaround Costs	2,457	2,454
Operating Expenses – Turnaround Costs	306	108

Per-Unit Operating Expenses (1) ($/bbl)	12.99	14.63
Per-Unit Operating Expenses – Excluding Turnaround Costs (1)	11.55	14.01
Per-Unit Operating Expenses – Turnaround Costs (1)	1.44	0.62

Primary drivers of operating expenses were repairs and maintenance, workforce and turnaround costs. In 2024, operating expenses increased mainly due to the significant turnaround at the Lima Refinery. In 2023, turnarounds were completed at the non-operated Wood River and Borger refineries. The increase in operating expenses was also due to obtaining full ownership of the Toledo Refinery in 2023. Per-unit operating expenses decreased primarily due to higher total processed inputs, partially offset by higher operating expenses, as discussed above.

Operating expenses excluding turnaround costs were relatively consistent compared with 2023, primarily due to the Toledo Acquisition, as discussed above, offset by a decrease in repairs and maintenance expenses following the completion of commissioning and start-up activities at the Toledo and Superior refineries in 2023. Per-unit operating expenses excluding turnaround costs decreased primarily due to higher total processed inputs.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			31

CORPORATE AND ELIMINATIONS

Financial Results



($ millions)	2024	2023
Realized (Gain) Loss on Risk Management	24	(3)
Unrealized (Gain) Loss on Risk Management	16	73
Depreciation, Depletion and Amortization	102	107
General and Administrative	794	688
Finance Costs, Net (1)	514	538
Integration, Transaction and Other Costs	166	85
Foreign Exchange (Gain) Loss, Net	462	(67)
(Gain) Loss on Divestiture of Assets (1)	(119)	20
Re-measurement of Contingent Payments	30	59
Other (Income) Loss, Net	(55)	(63)

(1)Revised presentation as of January 1, 2024. Refer to Note 4 of the Consolidated Financial Statements for further detail.

General and Administrative

Primary drivers of our general and administrative expenses in 2024 were workforce costs and information technology related costs. The increase in general and administrative expenses was primarily due to higher information technology and software costs, and higher people costs.

Finance Costs, Net

Net finance costs were lower compared with 2023, primarily due to lower interest expenses on long-term debt and higher interest income in 2024, partially offset by the discount on the redemption of long-term debt from the purchase of US$1.0 billion of unsecured notes in 2023. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.

The annualized weighted average interest rate on outstanding debt for 2024 was 4.5 percent (2023 – 4.7 percent).

Integration, Transaction and Other Costs

In 2024, we incurred costs of $166 million, primarily related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. We are recalibrating work on the previously announced enterprise-wide IT systems upgrades to a more fit for purpose outcome and have deferred the enterprise-wide upgrades post 2025.

In 2023, we incurred transaction and integration costs of $85 million, primarily related to the Toledo Acquisition.

Foreign Exchange (Gain) Loss, Net



($ millions)	2024	2023
Unrealized Foreign Exchange (Gain) Loss	550	(210)
Realized Foreign Exchange (Gain) Loss	(88)	143
	462	(67)

Unrealized foreign exchange gains and losses were primarily due to the translation of U.S. denominated debt. In 2024, realized foreign exchange gains were primarily related to working capital. In 2023, realized foreign exchange losses were primarily related to the purchase of U.S. denominated notes. As at December 31, 2024, the Canadian dollar was eight percent weaker relative to the U.S. dollar at December 31, 2023.

(Gain) Loss on Divestiture of Assets

The Company closed a transaction with Athabasca Oil Corporation to create the jointly-controlled Duvernay, in which we hold a 30 percent equity interest and is accounted for using the equity method in the Consolidated Financial Statements. We recorded a before-tax gain of $65 million on the transaction.

The Company also closed the sale of non-core assets in its Conventional segment for net proceeds of $39 million and recorded a before-tax gain of $51 million.

In 2023, we recorded a non-cash revaluation loss of $34 million as part of the Toledo Acquisition.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			32

Re-measurement of Contingent Payments

On August 31, 2024, the variable payment obligation associated with the transaction with BP Canada Energy Group ULC to purchase the remaining 50 percent interest in Sunrise Oil Sands Partnership ended, and the final payment was made in October 2024. We recorded a non-cash remeasurement loss of $30 million associated with this payment in 2024 (2023 – $59 million).

Income Taxes



($ millions)	2024	2023
Current Tax
Canada	1,141	1,041
United States	9	(109)
Asia Pacific	214	224
Other International	39	25
Total Current Tax Expense (Recovery)	1,403	1,181
Deferred Tax Expense (Recovery)	(474)	(250)
	929	931

For the year ended December 31, 2024, we recorded current tax expense related to operations in all jurisdictions in which we operate. The increase in total current tax expense was primarily due to a current tax recovery in the U.S. in 2023. The effective tax rate for 2024 was 22.8 percent (2023 – 18.5 percent). The higher effective tax rate in 2024 is primarily due to non-taxable foreign exchange losses on long-term debt compared with non-taxable foreign exchange gains in 2023, paired with lower U.S. basis recognition.

Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to, different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax basis and other legislation.

In June 2024, the Global Minimum Tax Act was enacted in Canada to implement the new global minimum tax framework (“Pillar Two”), which is to be applied retroactively to fiscal periods beginning on or after December 31, 2023. The Company is subject to Pillar Two and has applied the mandatory temporary exemption of IAS 12, “Income Taxes” and in turn, has not recognized the impacts of Pillar Two in the deferred income tax calculation.

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.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			33



QUARTERLY RESULTS



	2024	2023
($ millions, except where indicated)			Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Average Commodity Prices (1) (US$/bbl)
Dated Brent			74.69	80.18	84.94	83.24	84.05	86.76	78.39	81.27
WTI			70.27	75.09	80.57	76.96	78.32	82.26	73.78	76.13
WCS at Hardisty			57.71	61.54	66.96	57.65	56.43	69.35	58.74	51.36
Differential WTI-WCS at Hardisty			12.56	13.55	13.61	19.31	21.89	12.91	15.04	24.77
Chicago 3-2-1 Crack Spread (2)			12.12	18.62	18.76	17.45	13.24	26.06	28.57	28.88
Group 3 3-2-1 Crack Spread (2)			12.66	18.95	18.13	17.50	18.55	36.96	31.78	31.35
RINs			4.02	3.89	3.39	3.68	4.77	7.42	7.72	8.20
Upstream Production Volumes
Bitumen (Mbbls/d)			608.6	569.6	591.7	595.4	595.1	586.0	554.6	570.7
Heavy Crude Oil (Mbbls/d)			18.0	16.3	18.1	17.9	17.5	15.6	17.0	16.8
Light Crude Oil (Mbbls/d)			12.3	13.6	13.5	12.5	15.8	15.2	10.1	15.3
NGLs (Mbbls/d)			31.7	31.0	33.0	32.4	34.2	35.6	26.7	33.4
Conventional Natural Gas (MMcf/d)			873.3	844.6	867.2	855.8	876.3	867.4	729.4	857.0
Total Production Volumes (MBOE/d)			816.0	771.3	800.8	800.9	808.6	797.0	729.9	779.0

Downstream Total Processed Inputs (3) (Mbbls/d)			700.5	674.4	652.9	683.8	605.7	691.3	566.9	480.7
Crude Oil Unit Throughput (3) (Mbbls/d)			666.7	642.9	622.7	655.2	579.1	664.3	537.8	457.9
Downstream Production Volumes (3) (Mbbls/d)			722.6	685.2	659.5	702.1	627.4	706.0	571.9	487.7

Revenues (4)			12,813	13,819	14,582	13,063	13,134	14,577	12,231	12,262

Operating Margin (5)			2,274	2,408	2,936	3,191	2,151	4,369	2,400	2,102
Operating Margin – Upstream (6)			2,670	2,731	3,089	2,631	2,455	3,447	2,257	1,711
Operating Margin – Downstream (6)			(396)	(323)	(153)	560	(304)	922	143	391

Cash From (Used in) Operating Activities			2,029	2,474	2,807	1,925	2,946	2,738	1,990	(286)

Adjusted Funds Flow (5)			1,601	1,960	2,361	2,242	2,062	3,447	1,899	1,395
Per Share – Basic (5) ($)			0.88	1.06	1.27	1.20	1.10	1.82	1.00	0.73
Per Share – Diluted (5) ($)			0.87	1.05	1.26	1.19	1.08	1.81	0.98	0.71

Capital Investment			1,478	1,346	1,155	1,036	1,170	1,025	1,002	1,101

Free Funds Flow (5)			123	614	1,206	1,206	892	2,422	897	294

Excess Free Funds Flow (5)			(416)	146	735	832	471	1,989	505	(499)

Net Earnings (Loss)			146	820	1,000	1,176	743	1,864	866	636
Per Share – Basic ($)			0.08	0.44	0.53	0.62	0.39	0.98	0.45	0.33
Per Share – Diluted ($)			0.07	0.42	0.53	0.62	0.32	0.97	0.44	0.31

Total Assets			56,539	54,680	56,000	54,994	53,915	54,427	53,747	54,000



Long-Term Debt, Including Current Portion			7,534	7,199	7,275	7,227	7,108	7,224	8,534	8,681

Net Debt			4,614	4,196	4,258	4,827	5,060	5,976	6,367	6,632

Cash Returns to Common and Preferred Shareholders			706	1,070	1,034	436	731	1,225	584	258
Common Shares – Base Dividends			330	329	334	262	261	264	265	200
Base Dividends Per Common Share ($)			0.180	0.180	0.180	0.140	0.140	0.140	0.140	0.105
Common Shares – Variable Dividends			—	—	251	—	—	—	—	—
Variable Dividends Per Common Share ($)			—	—	0.135	—	—	—	—	—
Purchase of Common Shares Under NCIB			108	732	440	165	350	361	310	40
Payment for Purchase of Warrants			—	—	—	—	111	600	—	—
Dividends Paid on Preferred Shares			18	9	9	9	9	—	9	18
Preferred Share Redemption			250	—	—	—	—	—	—	—

(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.

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

(4)2024 comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A.

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

(6)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			34

Our results for the fourth quarter reflect strong operational performance in the upstream business and improved performance from our refining operations compared with the third quarter of 2024. Our U.S. Refining financial results were significantly impacted by declining market crack spreads. Total Operating Margin for the quarter was $2.3 billion, comprising $2.7 billion in the upstream and an Operating Margin shortfall of $396 million in the downstream (third quarter of 2024 Operating Margin – $2.4 billion).

•Upstream production averaged 816.0 thousand BOE per day, an increase of 44.7 thousand BOE per day from the third quarter of 2024, due to the completion of the Christina Lake turnaround in September and positive post-turnaround impacts.

•Downstream throughput increased four percent from the third quarter of 2024 to 666.7 thousand barrels per day, largely driven by improved reliability in the U.S. Refining segment and the completion of the turnaround at the Lima Refinery in October, partially offset by some economic run cuts as market crack spreads weakened.

•Benchmark market crack spreads declined significantly in the fourth quarter of 2024. The Chicago 3-2-1 crack spread and the Group 3 3-2-1 crack spread fell 35 percent and 33 percent, respectively, from the third quarter of 2024 to US$12.12 and US$12.66 per barrel. Net of RINs, Chicago market crack spreads in the fourth quarter averaged US$8.10 per barrel, compared with US$14.73 per barrel in the third quarter of 2024.

•We mechanically completed the Narrows Lake pipeline to Christina Lake. The pipeline will commence steam injection in the spring and the project remains on track for first oil mid-2025.

•We progressed the West White Rose project and mechanical completion of the topsides and concrete gravity structure occurred in the fourth quarter. The project is on track to deliver first oil in 2026.

•Refit work that commenced in the first quarter of 2024 on the SeaRose FPSO was completed and the vessel returned to the field in November.

•Cash from operating activities fell to $2.0 billion from $2.5 billion in the third quarter of 2024, and Adjusted Funds Flow decreased to $1.6 billion from $2.0 billion in the third quarter, primarily due to higher cash taxes and lower Operating Margin.

•We returned $438 million to common shareholders through the base dividend and share buybacks of $108 million.

Fourth Quarter 2024 Results Compared with the Fourth Quarter 2023

The summary below compares financial and operating results for the three months ended December 31, 2024, compared with the same period in 2023.

Upstream Production Volumes

Total upstream production increased 7.4 thousand BOE per day in the fourth quarter of 2024 compared with 2023, primarily due to:

•Successful results from redevelopment wells and positive post-turnaround impacts at our Christina Lake asset.

•Increased production at the fully operational MAC field that came online in September 2023, combined with higher buyer nominations and increased condensate lifting in our Indonesia operations.

The increases were partially offset by less new well development and the divestiture of non-core assets in the first and third quarters of 2024 in our Conventional segment.

Downstream Refining Throughput and Production

Canadian Refining operations were strong in the fourth quarter with crude unit utilization of 97 percent (2023 – 93 percent). Throughput increased 4.1 thousand barrels per day to 104.4 thousand barrels per day and production increased 5.1 thousand barrels per day to 118.4 thousand barrels per day compared with 2023.

U.S. Refining throughput increased 83.5 thousand barrels per day to 562.3 thousand barrels per day and total refined product production increased 90.1 thousand barrels per day to 604.2 thousand barrels per day compared with 2023, primarily due to lower maintenance activity in 2024, compared with a turnaround at the non-operated Borger Refinery in 2023. The increases were partially offset by the turnaround at the Lima Refinery, which ended in late October. We were able to partially mitigate the impact of the turnaround at the Lima Refinery by processing intermediate products at our Toledo Refinery, which allowed the Lima Refinery’s crude unit to continue operations.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			35

Operating Margin

Three Months Ended December 31, 2024 and 2023

Operating Margin was $2.3 billion in the fourth quarter of 2024, compared with $2.2 billion in the fourth quarter of 2023. The increase was primarily due to higher Realized Sales Prices in our Oil Sands segment driven by the narrower WTI-WCS differential. The increase was partially offset by lower Gross Margin in the Canadian Refining segment as a result of lower refined product pricing and lower sales volumes in our Offshore segment. Operating Margin in the U.S. Refining segment decreased due to lower market crack spreads and higher operating expenses.

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

Cash from operating activities decreased $917 million to $2.0 billion in the fourth quarter of 2024, compared with the fourth quarter of 2023, primarily due to changes in non-cash working capital and higher cash taxes. The net change in non-cash working capital was a source of cash of $492 million in 2024, primarily due to increases in accounts payable and taxes payable, combined with a decrease in accounts receivable, partially offset by increased inventories. In 2023, the $949 million source of cash was primarily due to lower accounts receivable and inventories, partially offset by lower accounts payable, all driven by decreasing commodity prices during the period.

Adjusted Funds Flow decreased to $1.6 billion in the fourth quarter of 2024, compared with $2.1 billion in 2023, primarily due to higher cash taxes.

Net Earnings (Loss)

Net earnings were $146 million in the fourth quarter of 2024 compared with $743 million in the fourth quarter of 2023. The decrease was primarily due to foreign exchange losses of $381 million in 2024 compared with gains of $74 million and higher general and administrative expenses, mainly driven by higher people costs compared with 2023.

Capital Investment

Capital investment increased to $1.5 billion in the fourth quarter of 2024, compared with $1.2 billion in the fourth quarter of 2023, as we continued our upstream growth projects and downstream sustaining work.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			36



OIL AND GAS RESERVES


As at December 31, 2024 (before royalties) (1) (2)	Bitumen (3) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (4) (Bcf)	Total (MMBOE)
Total Proved	5,179	91	69	1,950	5,664
Probable	2,500	77	37	1,071	2,793
Total Proved Plus Probable	7,679	168	107	3,021	8,457


As at December 31, 2023 (before royalties) (1) (2)	Bitumen (3) (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (4) (Bcf)	Total (MMBOE)




























Total Proved	5,411	38	74	2,062	5,866




Probable	2,487	125	40	1,100	2,836
Total Proved Plus Probable	7,899	163	114	3,162	8,702

(1)Totals may not sum due to rounding.

(2)Includes values attributable to Cenovus’s 40 percent equity interest in the HCML joint venture. 2024 includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay joint venture.

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

(4)Includes shale gas that is not material.

The following developments occurred in 2024 compared with 2023:

The reserves data is presented as at December 31, 2024, using an average of the forecast prices, inflation and exchange rates (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast is dated January 1, 2025. Comparative information as at December 31, 2023, uses the January 1, 2024, Average Forecast.

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, 2024. Our AIF is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in the Risk Management and Risk Factors section and the Advisory section of this MD&A.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			37



LIQUIDITY AND CAPITAL RESOURCES

Our capital allocation framework enables us to preserve our balance sheet, provide flexibility in both high and low commodity price environments, and deliver value to shareholders.

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 Ratings, Morningstar DBRS and Fitch Ratings. In the first quarter of 2024, we received a rating upgrade from S&P Global to BBB with a Stable outlook. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.



($ millions)	2024	2023
Cash From (Used In)
Operating Activities	9,235	7,388
Investing Activities	(5,126)	(5,295)
Net Cash Provided (Used) Before Financing Activities	4,109	2,093
Financing Activities	(3,505)	(4,313)
Effect of Foreign Exchange on Cash and Cash Equivalents	262	(77)
Increase (Decrease) in Cash and Cash Equivalents	866	(2,297)

	December 31,	December 31,
As at ($ millions)	2024	2023
Cash and Cash Equivalents	3,093	2,227
Total Debt	7,707	7,287

Cash From (Used in) Operating Activities

In 2024, cash from operating activities increased compared with 2023, primarily due to a working capital release, partially offset by lower Operating Margin. Non-cash working capital was a source of cash of $1.3 billion in 2024, due to lower accounts receivable, higher accounts payable and higher taxes payable, partially offset by higher inventories. In 2023, changes in non-cash working capital was a use of cash of $1.2 billion, primarily driven by the payment of the December 31, 2022, income tax liability that occurred in the first quarter of 2023.

Cash From (Used in) Investing Activities

Cash used in investing activities decreased in 2024 compared with 2023, primarily due to the Toledo Acquisition in the first quarter of 2023, partially offset by a planned increase in capital investment in 2024.

Cash From (Used in) Financing Activities

Cash used in financing activities decreased in 2024 compared with 2023. The decrease was primarily due to the purchase of US$1.0 billion of unsecured notes in the third quarter of 2023. The decrease was partially offset by returns to common shareholders of $3.0 billion (2023 – $2.8 billion) and the redemption of $250 million of preferred shares.

Working Capital

Working capital as at December 31, 2024, was $3.1 billion (December 31, 2023 – $3.5 billion). The decrease in working capital was driven by an increase in accounts payable combined with a decrease in accounts receivable, partially offset by an increase in cash and inventories.

We anticipate that we will continue to meet our payment obligations as they come due.

Returns to Shareholders Target

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. Our Net Debt target is $4.0 billion and represents a Net Debt to Adjusted Funds Flow ratio target of approximately 1.0 times at the bottom of the commodity pricing cycle, which we believe is approximately US$45.00 per barrel.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			38

On achieving our Net Debt target, in the third quarter we increased target returns to shareholders, stewarding to 100 percent of Excess Free Funds Flow over time while maintaining Net Debt near $4.0 billion. Working capital movements, foreign exchange rate changes and other factors may result in periods where shareholder returns are less than, or exceed, Excess Free Funds Flow, and Net Debt is above or below our target. The allocation of Excess Free Funds Flow to shareholder returns may be accelerated, deferred or reallocated between quarters at management’s discretion.


	Three Months Ended December 31,		Twelve Months Ended December 31,
($ millions)	2024	2023	2024	2023
Excess Free Funds Flow (1)	(416)	471	1,297	2,466
Target Return (2)	(416)	236	514	1,233

Shareholder Returns by way of:
Purchase of Common Shares Under NCIB	108	350	1,445	1,061
Payment for Purchase of Warrants	—	111	—	711
Variable Dividends Paid	—	—	251	—
Preferred Share Redemption	250	—	250	—
Total	358	461	1,946	1,772

Return in (Excess)/Short of Target	(774)	(225)	(1,432)	(539)

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

(2)The target return for the year ended December 31, 2024, includes 100 percent of Excess Free Funds Flow in the third and fourth quarters of 2024 and 50 percent of Excess Free Funds Flow in the first and second quarters of 2024. The target return for 2023 was 50 percent of Excess Free Funds Flow.

Short-Term Borrowings

There were no direct borrowings on our uncommitted demand facilities as at December 31, 2024, or December 31, 2023. As at December 31, 2024, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$120 million (C$173 million) (December 31, 2023 – US$135 million (C$179 million)).

Long-Term Debt, Including Current Portion

Long-term debt, including the current portion, as at December 31, 2024, was $7.5 billion (December 31, 2023 – $7.1 billion). The increase was due to the weakening of the Canadian dollar relative to the U.S. dollar, impacting the translation of our U.S. denominated debt. We hold U.S. dollar denominated unsecured notes of US$3.8 billion (C$5.5 billion) (December 31, 2023 – US$3.8 billion (C$5.0 billion)) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2023 – $2.0 billion).

As at December 31, 2024, 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, 2024:

($ millions)

Maturity

Amount Available

Cash and Cash Equivalents

n/a

3,093

Committed Credit Facility

Revolving Credit Facility – Tranche A

June 26, 2028

3,300

Revolving Credit Facility – Tranche B

June 26, 2027

2,200

Uncommitted Demand Facilities

Cenovus Energy Inc. (1)

n/a

1,072

WRB (2)

n/a

151

(1)Represents amounts available for cash draws. Our uncommitted demand facilities include $1.7 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, 2024, there were outstanding letters of credit aggregating to $355 million (December 31, 2023 – $364 million) and no direct borrowings (December 31, 2023 – $nil).

(2)Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at December 31, 2024, US$120 million (C$173 million) of this capacity was drawn (December 31, 2023 – US$135 million (C$179 million)).

On June 26, 2024, Cenovus renewed its existing committed credit facility to extend the maturity dates by more than one year. As at December 31, 2024, no amount was drawn on the credit facility (December 31, 2023 – $nil).

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 below this limit.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			39

Base Shelf Prospectus

We have a base shelf prospectus that allows us to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, Total Debt, the Net Debt to Adjusted EBITDA ratio, the Net Debt to Adjusted Funds Flow ratio and the Net Debt to Capitalization ratio. Refer to Note 22 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 Shareholder’s 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 (loss) before finance costs, net, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, (gain) loss on divestiture of assets, re-measurement of contingent payments and net other (income) loss calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and are measures of our overall financial strength.


As at	December 31, 2024	December 31, 2023
Net Debt to Adjusted EBITDA Ratio (times)	0.5	0.5
Net Debt to Adjusted Funds Flow Ratio (times)	0.6	0.6
Net Debt to Capitalization Ratio (percent)	13	15

Our Net Debt to Adjusted Funds Flow ratio and our Net Debt to Adjusted EBITDA ratio targets are approximately 1.0 times and Net Debt at or below $4.0 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 or the strengthening or weakening of the Canadian dollar relative to the U.S. dollar. 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, steward working capital, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common or preferred shares for cancellation, issue new debt, or issue new shares.

Our Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio as at December 31, 2024, were consistent with December 31, 2023, as a result of lower Net Debt partially offset by lower Operating Margin. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt.

Our Net Debt to Capitalization ratio as at December 31, 2024, decreased compared with December 31, 2023, primarily due to comprehensive income of $4.2 billion partially offset by returns to shareholders and lower Net Debt.

Share Capital and Stock-Based Compensation Plans

Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Our cumulative redeemable preferred shares series 1, 2, 5 and 7 are listed on the TSX. On December 31, 2024, Cenovus exercised its right to redeem all 10.0 million of the Company’s series 3 preferred shares at a price of $25.00 per share, for a total of $250 million.

As at December 31, 2024, there were approximately 1,825.0 million common shares outstanding (December 31, 2023 – 1,871.9 million common shares) and 26.0 million preferred shares outstanding (December 31, 2023 – 36.0 million preferred shares). Refer to Note 27 of the Consolidated Financial Statements for further details. In 2024, Cenovus established an employee benefit plan trust (the “Trust”). The Trust, through an independent trustee, acquires Cenovus’s common shares on the open market, which are held to satisfy the Company’s obligations under certain stock-based compensation plans. As at December 31, 2024, there were 2.0 million common shares held by the Trust.

As at December 31, 2024, there were approximately 3.6 million Cenovus Warrants outstanding (December 31, 2023 – 7.6 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 27 of the Consolidated Financial Statements for further details.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			40

Refer to Note 29 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 14, 2025	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	1,823,629	n/a
Cenovus Warrants	3,631	n/a
Series 1 First Preferred Shares	10,740	n/a
Series 2 First Preferred Shares	1,260	n/a
Series 5 First Preferred Shares	8,000	n/a
Series 7 First Preferred Shares	6,000	n/a
Stock Options	8,890	4,999
Other Stock-Based Compensation Plans	17,094	1,792

Common Share Dividends

In 2024, we paid base dividends of $1.3 billion or $0.680 per common share (2023 – $990 million or $0.525 per common share) and variable dividends of $251 million or $0.135 per common share (2023 – $nil).

On February 19, 2025, the Board declared a first quarter base dividend of $0.180 per common share. The dividend is payable on March 31, 2025, to common shareholders of record as at March 14, 2025.

The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.

Cumulative Redeemable Preferred Share Dividends

For the year ended December 31, 2024, dividends of $45 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (2023 – $36 million).

On February 19, 2025, the Board declared a first quarter dividend on the series 1, 2, 5 and 7 preferred shares for a total of $6 million, payable on March 31, 2025, to preferred shareholders of record as at March 14, 2025.

The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly.

Share Repurchases

We had an NCIB program to purchase up to 133.2 million common shares from November 9, 2023, to November 8, 2024.

On November 7, 2024, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 127.5 million common shares during the period from November 11, 2024, to November 10, 2025.



	2024	2023
Common Shares Purchased and Cancelled Under NCIB (millions of common shares)	55.9	43.6
Weighted Average Price per Common Share ($)	25.38	24.32
Purchase of Common Shares Under NCIB ($ millions)	1,445	1,061


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			41

Contractual Obligations and Commitments

We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from our total commitments disclosed below. For further information, see Note 35 to the Consolidated Financial Statements.


As at December 31, 2024
($ millions)	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Commitments
Transportation and Storage (1) (2)	2,122	1,947	1,921	1,904	1,815	14,551	24,260
Product Purchases	14	—	—	—	—	—	14

Real Estate	63	63	61	59	63	532	841
Obligation to Fund HCML	104	105	98	56	44	105	512
Other Long-Term Commitments	411	191	187	158	117	589	1,653
Total Commitments	2,714	2,306	2,267	2,177	2,039	15,777	27,280
Long-Term Debt (Principal and Interest)	526	324	1,586	1,502	487	7,286	11,711
Decommissioning Liabilities	203	289	286	283	318	6,301	7,680

Lease Liabilities (Principal and Interest) (3)	538	446	378	339	306	2,606	4,613
Total Commitments and Obligations	3,981	3,365	4,517	4,301	3,150	31,970	51,284

(1)Includes transportation commitments that are subject to regulatory approval or were approved but are not yet in service of $854 million (December 31, 2023 – $13.0 billion). Terms are up to 20 years on commencement.

(2)As at December 31, 2024, includes $1.8 billion related to transportation and storage commitments with HMLP (December 31, 2023 – $2.1 billion).

(3)Lease contracts related to office space, a pipeline, storage tanks, railcars, refining equipment, vessels, a natural gas processing plant, caverns, fleet vehicles, our commercial fuels network and other field equipment.

As at December 31, 2024, outstanding letters of credit issued as security for performance under certain contracts totaled $355 million (December 31, 2023 – $364 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.

Transactions with Related Parties

Husky Midstream Limited Partnership

Cenovus holds a 35 percent interest in HMLP. As the operator of the assets held by HMLP, we provide management services for which we recover shared service costs in accordance with our profit-sharing agreement. 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, 2024, we charged HMLP $155 million for construction and management services (2023 – $160 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. Access fees and transportation and storage services are based on contractually agreed rates with HMLP. For the year ended December 31, 2024, we incurred costs of $278 million for the use of HMLP’s pipeline systems, as well as for transportation and storage services (2023 – $295 million).

For the year ended December 31, 2024, the Company received $65 million of distributions from HMLP (2023 – $56 million) and paid $51 million in contributions (2023 – $62 million).

Husky-CNOOC Madura Ltd.

Cenovus holds a 40 percent equity interest in the jointly-controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture is recorded in (income) loss from equity-accounted affiliates.

For the year ended December 31, 2024, the Company received $107 million of distributions from HCML (2023 – $93 million) and paid $nil in contributions (2023 – $35 million).


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RISK MANAGEMENT AND RISK FACTORS

Risk Governance

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. The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. 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 consolidated risk reports presented to our Board as well as through regular updates.

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 following discussion describes the financial, operational, regulatory, environmental, reputational, climate-change related and other risks 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, ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, ability to respond to changes in our operating environment, access to capital, cost of borrowing, access to liquidity, ability to fund share repurchases, dividend payments and/or business plans, fulfill our obligations and/or the market price of our securities. These factors should be considered when investing in securities of Cenovus.

Financial Risk

Commodity Prices

Our financial performance is significantly dependent on prevailing commodity prices. Prices for crude oil, refined products, natural gas, NGLs and other related products are impacted by a number of factors, including, but not limited to: global and regional supply of, and demand for, these commodities; the ability of producers and governments to replace reduced supply; processing and export capacity; export restrictions; domestic and global economic conditions; inflation and changes to interest rates; the impact of tariffs and responses thereto (including by governments, our trade partners and customers), which may include, without limitation, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S. or other measures; central bank policies; 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; developments related to the market for these commodities; inventory levels of these commodities; seasonal trends; refinery availability; current and potential future environmental laws and regulations; 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; enforcement of government or environmental laws and regulations; shifts or changes in governmental policy in the jurisdictions in which we conduct our business operations, development or exploration, or elsewhere; public sentiment towards the use of non-renewable resources; political instability and social conditions in countries producing these commodities; market access constraints and transportation restrictions or interruptions; terrorist threats; technological developments; economic sanctions; outbreak of a pandemic, or war or other international or regional conflict and any related government action or military exercise; the occurrence of natural disasters; and weather conditions.

The focus on the timing and pace of the transition to a lower-carbon economy and resulting trends will likely continue to 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, the transition to a lower-carbon economy.

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 crude oil produced. Of particular importance to us are condensate 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 condensate costs, can adversely affect our financial condition.


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The financial performance of our refining operations is impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to factors such as, but not limited to, access to price advantaged crude oil; incremental capacity at existing refineries; global and regional demand for refined products; and 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.

All of these factors are beyond our control and can result in a high degree of both cost and price volatility.

Fluctuations in the commodity prices, associated price differentials, and refining margins may impact our financial condition, results of operations, cash flows, growth, access to capital, cost of borrowing, ability to meet guidance targets, the value of our assets, the level of shareholder returns and our ability to meet guidance targets, and 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 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.

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 Accounting Standards. If crude oil, refined product, natural gas and NGL prices decline significantly and remain at low levels for an extended period, or if the costs to develop such resources significantly increase, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.

Risks Associated with Uncertainty Surrounding Recently Announced U.S. Tariffs on Canada and Potential Retaliatory Measures

On February 1, 2025, President Trump signed an executive order (the “Executive Order”) imposing a 25 percent tariff on all goods originating in Canada and imported into the U.S. and a 10 percent tariff on “energy and energy resources” from Canada, effective on February 4, 2025. The Executive Order also states that, if Canada introduces retaliatory measures, such as through the imposition of import duties on U.S. exports to Canada (or other similar measures), the U.S. tariffs may be increased or expanded. In response, the Government of Canada imposed 25 percent tariffs on $155.0 billion in goods imported from the U.S., coming into effect in two phases starting on February 4, 2025. Provincial governments across Canada have also responded to the U.S. tariffs, in some cases introducing their own retaliatory measures. On February 3, 2025, Canada and the U.S. agreed to delay the imposition of their respective tariffs on imported goods for 30 days. President Trump has also suggested that a new economic deal may be structured with Canada, though the scope and terms of such a deal, if any, are unknown.

Although discussions continue regarding a potential economic arrangement between the two countries, there remains significant uncertainty over whether tariffs, surtaxes, or other restrictive trade measures or countermeasures will ultimately be implemented and, if so, the scope, impact, and duration of any such measures. Potential measures could include, among others, increased tariffs on Canadian energy exports, restrictions on cross-border supply chains, or additional regulatory barriers that could impact our ability to access international markets and conduct business efficiently.

Restrictive trade measures or countermeasures, if implemented for any period of time, could have a significant impact on the market for crude oil, NGLs, natural gas and refined petroleum products in Canada and internationally and could result in, among other things, a high degree of both cost and price volatility, a relative weakening of the Canadian dollar, widening differentials, and decreased demand for our products and services. Any or all of such effects may have a material adverse impact on our business, results of operations and financial condition.

Additionally, retaliatory measures imposed on our products could reduce our ability to compete in the global market. We also rely on the importation of specialized equipment, raw materials and technology from various global suppliers. Any increase in tariffs on these goods could lead to higher costs for these essential inputs, thereby having a negative effect on our financial position and cash flows.

Risks Associated with Financial Risk Management Activities

Our Board-approved Market Risk Management Policy allows Management to use approved derivative financial instruments as needed, within authorized limits, to help mitigate the impact of changes in crude oil and condensate prices and differentials, NGL and natural gas spreads, basis and prices, electricity prices, refined product and crack spread margins, as well as fluctuations in foreign exchange and interest rates. We may also use derivative instruments in various operational markets to help optimize our supply costs or sales of our production, or fixed-price commitments for the purchase or sale of crude oil, refined products, natural gas, NGLs and other related products.


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Notwithstanding the anticipated benefits of undertaking these risk management activities, the use thereof may expose us to risks which may cause significant loss, including risks related to: changes in the valuation of the risk management instrument being poorly correlated to the change in the valuation of the underlying exposures; 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; the unenforceability of contracts; and any inability to fulfill our delivery obligations related to the underlying physical transaction. These financial instruments may also limit the benefit to us of commodity prices, interest or foreign exchange rates change.

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 32, 33 and 36 of the Consolidated Financial Statements.

Impact of Financial Risk Management Activities

Cenovus may employ various price alignment and volatility management strategies, including financial risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.

Transactions typically span across numerous time 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 discussion below 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 below are a reasonable measure of volatility. The impact of the below on the Company’s open risk management positions could result in an unrealized gain (loss) impacting earnings before income tax as follows:


As at December 31, 2024	Sensitivity Range	Increase	Decrease
Crude Oil and Condensate Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	—	—
Crude Oil and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	20	(20)
WCS (Hardisty) Differential Price	± US$2.50/bbl Applied to WCS Differential Hedges Tied to Production	(6)	6
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(3)	3
Natural Gas Commodity Price	± US$0.50/Mcf Applied to Natural Gas Hedges Tied to Production	—	—
Natural Gas Basis Price	± US$0.25/Mcf Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$10.00/MWh (2) Applied to Power Hedges	46	(46)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	24	(28)

(1)Excluding WCS at Hardisty.

(2)One thousand kilowatts of electricity per hour (“MWh”).

For further information on our risk management positions, see Notes 32 and 33 of the Consolidated Financial Statements.

Credit, Liquidity and Availability of Future Financing

The future development of our business may be dependent on our ability to access external 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.

Our ability to access capital and secure insurance coverage, at reasonable costs, or at all, may be adversely affected in the event that investors, insurers, or other relevant stakeholders adopt more restrictive decarbonization policies, we fail to achieve our GHG emissions reduction goals, or it is perceived that our GHG emissions reduction goals are insufficient or will not be achieved.

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 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.


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We are required to comply with various financial and operating covenants under our credit facility and the indentures governing our debt securities. Non-compliance with these covenants may lead to restrictions on access to capital or accelerated repayment.

Credit Ratings

A downgrade in any of our credit ratings, particularly a downgrade below investment grade ratings, a negative change in the Company's credit ratings outlook, or the withdrawal of a rating by a rating agency, could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital, and our business relationships with counterparties, operating partners and suppliers. Credit ratings are based on our financial and operational strength and several factors not entirely within our control, including, but not limited to, conditions affecting the crude oil, natural gas, NGL and refining industry generally, industry risks associated with the transition to a lower-carbon economy, government policies and the general state of the economy.

If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post additional collateral in the form of cash, letters of credit or other financial instruments to establish or maintain business arrangements. Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated.

Exposure to Counterparties

In the normal course of business, we enter contractual relationships with suppliers, partners, lenders, customers and other counterparties. If such parties do not fulfill their contractual obligations on a timely basis or at all, we may suffer financial losses or delays to 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.

Foreign Exchange Rates

Cenovus’s revenues are predominantly based on U.S. dollar benchmark prices, and a significant portion of our long-term debt and interest expense is denominated in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. Fluctuations in foreign exchange rates, particularly the U.S./Canadian dollar and RMB/Canadian dollar, may affect our results and could have a material adverse effect on our cash flows and financial condition.

Interest Rates

Interest rate fluctuations may have a material adverse impact on Cenovus’s results upon the refinancing of maturing long-term debt or when new debt financing is required. We are also exposed to changing interest rates on existing credit facilities that may be used to support our liquidity needs. Changes in interest rates can also impact how certain liabilities are recorded. These factors could impact Cenovus’s financial results.

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 and steward to Net Debt of $4.0 billion, 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, including Management’s discretion to accelerate, defer or reallocate any Excess Free Funds Flow to shareholder returns between quarters. 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.


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Disclosure Controls and Procedures (“DC&P”) and Internal Control Over Financial Reporting (“ICFR”)

Based on their inherent limitations, DC&P 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.

Operational Risk

Operational Considerations (Safety, Environment and Reliability)

Our operations are subject to risks generally affecting the oil and gas, and refining industries and normally incidental to: (i) the storing, transporting, processing and marketing of crude oil, refined products, natural gas, NGLs and other related products; (ii) the 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; (iv) the operation of refineries, terminals, pipelines and other transportation and distribution facilities in or regional evacuation alerts or orders issued by provincial or regional authorities over the jurisdictions in which we conduct operations, development or exploration, including at facilities operated by our partners or third-parties; and (v) the development and operation of projects relating to our GHG emissions reduction goals, including carbon capture, utilization and storage projects. These risks include, but are not limited to: the effects of government actions, laws or regulations, policies and initiatives, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration; encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; flooding; geologic activity arising from fracking or carbon capture, utilization and storage projects; 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; accidents or damage caused by third parties or otherwise occurring in the operation of our business; 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, facilities, wells and projects; the breakdown or failure of operational and information technology and systems and processes, any compromise thereof or released data; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; failure to maintain adequate supplies of spare parts; operator error; shortages of skilled labour; labour disputes and strikes; disputes with owners or operators of 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; protests, blockades or other acts of activism; geopolitical factors, war, vandalism or terrorism, or other regional or international conflict; other catastrophic events, including, but not limited to, adverse sea conditions, extreme weather events, wildfires and natural disasters and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites.

Climate change may result in an increased level of operational risk requiring increased or additional mitigation measures. Systemic climatic changes or extreme climatic conditions may increase our exposure to, and magnitude of, the impact of physical climate risks, such as floods, drought, wildfires, earthquakes, hurricanes, typhoons, storms, extreme temperatures and other extreme weather events or natural disasters. Severe weather conditions may result in an operational incident with the potential to result in spills, asset damage and production, refining disruption or safety and reliability of operations.

If any such risks materialize, they may: interrupt operations; impair our ability to achieve our ESG goals, including our GHG emissions reduction goals; cause loss of life or personal injury; result in loss of or damage to equipment, property, operational and information technology and control systems and data, which may result in reduced revenue from reduced capacity or business interruption, or increased costs related to asset repair; cause environmental damage that may include polluting water, land or air; cause reputational damage; 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.

We maintain 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 we cannot guarantee 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.


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Market Access Constraints and Transportation Restrictions

Our production is transported through, and our refineries are reliant on, various pipelines and terminals, as well as rail, marine and truck networks, to transport feedstock and refined products to and from third-party, or Cenovus, owned and/or operated, facilities. The impacts of tariffs (and any responses thereto, including, without limitation, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S. or other measures) or disruptions in, or restricted availability of, pipeline, terminal, marine, rail or truck transport systems could limit the ability to deliver production volumes and adversely affect commodity prices, sales volumes and/or the prices received for our products, projected production growth, upstream or refining operations and cash flows. These interruptions and restrictions may be caused or intensified 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 third-party pipeline projects for new or expanded capacity will be approved or constructed or that such projects would provide sufficient transportation capacity.

There is no certainty that rail, marine and truck 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, labour disputes or strikes, shortages of skilled labour, inclement weather, vessel, railcar or truck availability, geopolitical factors, war, terrorism, or other international or regional conflict, 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 laws and 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 associated future net cash flows and revenue 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 laws and 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 estimates.

All of 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 crude oil, refined products, natural gas, NGLs and other related products; 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.


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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, including those related to our GHG emissions reduction goals; 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; changing government or environmental policies, laws and regulations; supply chain disruptions, including force majeure; and access to skilled labour and critical third-party services. Such higher costs may not be fully offset through corresponding increases in commodity prices and other sources of funding. Inflation and any governmental response thereto, such as the imposition of higher interest rates or wage controls, 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.

Technology, Information Systems and Data Privacy

We rely heavily on technology, including operating technology and information technology, to effectively operate our business. This includes on-premise systems (such as networks, computer hardware and software), telecommunications systems, mobile applications, cloud services and other technology systems, networks and services, including systems using artificial intelligence. Some systems and services are provided by third-parties. In the event we are unable to access, use, rely upon, adequately 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 data. Despite our security measures, our technology systems, infrastructure and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties), disruptions from staff or third-party error, malfeasance, natural disasters, acts of state or industrial espionage, activism, terrorism, war, regional or international conflict, or the geopolitical landscape. These risks also include, but are not limited to, cyber-related fraud or attacks such as attempts to circumvent electronic communications controls, attempts to impersonate internal personnel or business partners to divert payments and financial assets to accounts controlled by the perpetrators, or attempts to introduce ransomware into one or more systems or services to extract a payment, preventing access to systems, among others.

Any such incident, breach, or disruption of our internal or our third-party service providers’ technology systems or services, or other vendor technology systems and 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, business, financial, proprietary, personal or other sensitive data.

The rapid emergence and continuous evolution of generative artificial intelligence tools may exacerbate the Company’s technology, information systems and data privacy-related risks due to its potential for user misuse, biased decision-making or unauthorized exposure of Cenovus’s sensitive data.

Cyber incidents, privacy or security breaches or irresponsible use of technology or data, including through the irresponsible use of or reliance upon artificial intelligence tools, could result in business interruption, theft or misuse of confidential information, financial losses, remediation and recovery costs, legal claims or proceedings, liability under laws that govern data, its processing, or the decisions that may arise from same (including laws related to the use of artificial intelligence, cybersecurity, data collection and protection and privacy), regulatory penalties or fines (if such penalties or fines are authorized under the relevant legislation), 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.

The regulation of the use of technology is rapidly evolving across many of the jurisdictions in which we conduct operations, development or exploration, creating a complex legal and regulatory framework, including existing and proposed laws and regulations that govern data, data processing and related tools, data transfers, artificial intelligence, data collection and protection and privacy. These laws and regulations impose obligations on companies that process personal data and provide additional rights of actions and remedies to individuals whose personal data is in the Company’s control.

Failure to comply with laws and regulatory standards governing cybersecurity, data collection and protection and privacy, including the misuse of or failure to adequately secure and protect personal data, that impact the use of artificial intelligence, could result in, without limitation; criminal, administrative and civil liabilities proceedings against the Company by governmental entities or others; imposition of severe fines and penalties (if such fines and penalties are authorized under the relevant legislation); damage to our reputation and credibility; and may have a negative impact on our financial condition, results of operations and cash flows. Compliance with continuously evolving legislation may also result in increased operating costs.


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Competition

We compete with other producers, refiners and marketers in all aspects, including access to capital, the exploration and 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. Competitors may have lower operating/capital costs or higher quality resource inventory than Cenovus does, may develop and implement technologies and business practices which are superior to those we employ, and/or may assemble portfolios that generate stronger financial returns than Cenovus does, reducing our ability to compete. The crude oil, natural gas, NGL and refining 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. We may not be able to compete successfully against current and future competitors, and competitive pressures 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 growth and optimization projects across our global portfolio of assets. In addition, we have a number of other projects in various stages of planning and development, including maintenance and turnaround projects, and projects related to our GHG emissions reduction goals. 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 contract terms or to be granted access within land-use agreements; our ability to access, implement and use operational and information technologies and data, including improvements thereto; risks relating to schedule, contractor performance, engineering and design, transportation and installation of project components, 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 on a cost effective basis; our ability to identify or complete strategic transactions; and the effect of changing government laws and regulations, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration; and public expectations in relation to the impacts of oil and gas operations on the environment and those associated with GHG emissions abatement initiatives. The commissioning and integration of new infrastructure and 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, cash flows and reputation.

Joint Ventures and Partnerships

Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures and we are, at times, dependent upon our partners for the successful execution and operation of various projects and assets, their management of operational issues and their reporting. In addition, certain of our projects under development, including those related to our GHG emissions reduction goals, are expected to be constructed and operated in collaboration with third parties. Therefore, our results of operations, cash flows and progress towards our GHG emissions reduction goals 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.

Our partners may have objectives and interests that either 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 and projects 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 or partners’ 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 or partners 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, progress towards our GHG emissions reduction goals, reputation and cash flows.

Existing and Emerging Technologies

Current technologies used for the recovery of bitumen are 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. In addition, we depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business goals including our ESG goals. 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.


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Governmental Policy

Shifts in government policy by new or existing administrations in jurisdictions in which we conduct operations, development or exploration or elsewhere can impact our operations and ability to grow our business. Restrictions on fossil fuel-based energy use, cross-border economic activity (including the imposition of tariffs by foreign governments impacting our business and any governmental responses thereto, including, without limitation, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S. or other measures), 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 conduct business operations, development or exploration to ensure we remain competitive, 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.

Regulatory Risk

The crude oil, natural gas, NGL and refining industry in general and our operations in particular are subject to regulation and intervention under various levels of legislation in the countries in which we operate, seek to develop or explore. Regulated areas of our operations include, but are not limited to: land tenure; permitting of projects; royalties; taxes (including income taxes and tariffs); government fees; production rates; environmental protection; occupational and process safety management; protection of certain species or lands; cumulative effects and/or impacts from all types of industrial development; environmental plans, laws and regulations; the reduction of GHG and other emissions; the export of crude oil, refined products, natural gas, NGLs and other related products; the transportation of crude oil, refined products, natural gas, NGLs and other related products by pipeline, rail, marine or truck transport; generation, handling, storage, transportation, treatment and disposal of hazardous substances; the awarding, acquisition and maintenance of exploration, development and production rights; the imposition of specific drilling obligations; control over the development, abandonment, remediation and reclamation of fields (including restrictions on production) and/or facilities; and possible expropriation or cancellation of contract rights. See “Environmental Plans and Regulations Risks” below. Any changes to applicable regulatory regimes, including the implementation of new laws or regulations or enforcement initiatives, repeal of any existing laws or regulations, or the modification or changed interpretation of existing laws or 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.

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 on acceptable conditions, or at all, all necessary licences, permits and other approvals required to conduct activities (including, without limitation, certain exploration, development and operating activities) related to our projects. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder consultation, Indigenous consultation (including consensus seeking, collaboration or consent), 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. The failure to obtain applicable regulatory approvals or satisfy any conditions on a timely basis or satisfactory terms could result in increased costs, project delays and may limit Cenovus’s ability to develop or expand proposed projects efficiently or at all.

Decommissioning

We are subject to oil and gas asset decommissioning, abandonment, remediation and reclamation (“Decommissioning”) liabilities for our operations, development and exploration, including those imposed by regulation under various levels of legislation in the jurisdictions in which we conduct operations, development or exploration.

We maintain estimates of our Decommissioning 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.

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 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 Decommissioning liability regulatory regimes in the jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated and may be affected by changes in governmental policy, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration. Any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and could 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 and mineral tax 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 and mineral tax 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 conduct operations, development or exploration, or changes to how existing royalty and mineral tax 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.

Indigenous Land and Rights Claims

Opposition by Indigenous people and communities to our Company, operations, activities, development or exploration, or disagreements between Indigenous communities, or between Indigenous people and governments, in the jurisdictions in which we conduct operations, development or exploration may adversely impact our reputation and our relationships with host governments, local communities and other Indigenous communities. Other impacts may include diversion of Management’s time and resources, increased legal, regulatory and other advisory expenses, and impeding our ability to explore, develop and continue to operate projects.

In Canada, Aboriginal and/or treaty rights held by Indigenous people are protected under the Constitution. Impacts to these Indigenous and/or treaty rights must be considered, in particular, in areas where Cenovus operates on Crown lands.

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. In some jurisdictions, the Crown delegates consultation responsibilities to proponents. 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, licenses and other approvals, or to meet the terms and conditions of those approvals. Failure to adequately consult can lead to project delays, legal challenges, or damage to our reputation.

In addition, the Canadian federal government, the British Columbia provincial government and the Northwest Territories territorial government have passed legislation which requires such governments to take all necessary measures to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). The means and timelines associated with UNDRIP’s implementation by governments is ongoing and, in some instances, 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.

Climate Change-Related Risks

There is international concern regarding climate change and a significant focus on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, non-governmental organizations (“NGOs”), environmental and governance organizations, rating agencies, institutional investors, social and environmental activists, shareholders and individuals are 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. A transition to a lower carbon economy could increase the demand for lower emissions and alternative energy sources. Changes in customer behaviour related to reduced energy consumption could impact Cenovus’s customers and in turn, the demand for Cenovus’s services. Transition to a lower carbon economy could also pose a risk to Cenovus if it is unable to diversify its operations on pace with such a transition.


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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, regulatory approvals, 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.

Climate Change Regulations

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 and changes which may occur as a result of change in governmental policy, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations, regulatory approvals and cash flows, which cannot be reliably or accurately estimated at this time.

The Government of Canada, under the Canadian Net-Zero Emissions Accountability Act, aims to reduce GHGs emissions by 40 percent to 45 percent below 2005 levels by 2030 and 45 percent to 50 percent by 2035. These targets are part of Canada's broader strategy to achieve net-zero emissions by 2050. Specific plans are not available, but the government is attempting to meet these targets through a number of measures including its economy wide price on carbon or carbon tax. The carbon tax will increase to $170/tonne CO2e by 2030, with the 2025 rate set at $95/tonne CO2e. 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 jurisdictions where provincial carbon pricing regulations apply to industry. In British Columbia, the provincial carbon pricing system applies in full. In Alberta, Saskatchewan and Newfoundland and Labrador, the provincial carbon pricing systems apply in part. These provincial programs are expected to continue to meet the federal stringency requirements such that the federal backstop regulations do not apply.

In November 2024, the Government of Canada released its draft Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations under the Canadian Environmental Protection Act, 1999. As currently drafted, the regulations would come into force in 2026 with the first three-year compliance period beginning January 1, 2030. The regulation would apply to, among other things, all direct GHG emissions from upstream oil and gas facilities, including offshore facilities and bitumen upgraders. For the 2030-2032 compliance period, facilities will be required to reduce industry-wide emissions by 27 percent from 2026 levels. Under the proposed regime, facilities that emit more than the allowances allocated under the distribution rate formula would have some flexibility to cover up to 20 percent of their compliance obligations through a combination of payments into a decarbonization fund and federally recognized offset credits. Further allowances could be purchased from other operators, provided there is sufficient supply. Environment and Climate Change Canada has not provided substantive details regarding the cap level beyond 2032.

The Government of Canada has also implemented regulations to reduce methane emissions from the crude oil and natural gas sector. The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (“Methane Regulation”) are designed to achieve a 40 percent to 45 percent reduction from 2012 levels by 2025 through both requirements for fugitive equipment leaks and venting from well completion and compressors (which came into force on January 1, 2020), and restrictions on facility production venting restrictions and venting limits for pneumatic equipment (which came into force on January 1, 2023). In December 2023, the Government of Canada published draft amendments to the Methane Regulation to facilitate achieving an additional target to reduce oil and gas methane emissions by at least 75 percent below 2012 levels by 2030. The proposed regulatory amendments relate to venting, flaring, hydrocarbon gas destruction equipment and fugitive emissions, and would come into force between 2027 and 2030.

In the U.S., 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. The U.S. has 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.


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Changes in environmental and emissions regulation by governmental authorities 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; penalties; permitting delays; general shift away from fossil fuel-based energy; and substantial costs to generate or purchase emission credits or allowances, any 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, shutting in production and the suspension of operations.

The extent and magnitude of any adverse impacts of current or additional programs or regulations 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.

Clean Fuel Regulations

In Canada, the Clean Fuel Regulations came into force in June 2022. The aim of this regulation is to lower the GHG emissions from various liquid fossil fuels by requiring producers or importers of gasoline, diesel, kerosene and light and heavy fuel oils (“Primary Suppliers”) to lower the carbon intensity of such fuels. The regulation sets a baseline carbon intensity for each type of liquid fossil fuel, against which the Primary Suppliers must make annual carbon intensity reductions. The regulation could result in the negative consequences noted above under “Climate Change Regulations”, including increased compliance costs, increased operating costs and capital expenditures.

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 compliance costs and a potential reduction in revenue. Existing and proposed regulations may negatively affect the marketing of our bitumen, crude oil or refined products (diesel and ethanol), and may require us to purchase low carbon fuel compliance credits in order to ensure compliance and support sales within such jurisdictions. These regulations have the potential to impact our business, financial condition, results of operations and cash flows.

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 which mandates that a certain volume of renewable fuels replace or reduce the quantity of certain petroleum-based transportation fuels sold or introduced in the U.S.

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 blend stocks, and the costs to obtain the necessary RINs and blend stocks 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 blend stocks to comply with the RFS mandated standards.

Clean Electricity Regulations

In December 2024, the Government of Canada released final Clean Electricity Regulations intended to accelerate progress towards a near-zero power generation sector in Canada. The regulations will impose a limit on total emissions based on a stringent carbon intensity threshold and generation unit capacity and will come into effect on the latter of January 1, 2035 or 25 years after a facility’s commissioning date. The full extent of any adverse impacts of these regulations cannot be reliably or accurately estimated at this time.

Light-Duty Vehicle Greenhouse Gas Emission Standards

In March 2024, the U.S. EPA announced new, more stringent final standards to further reduce GHGs from light-duty to medium-duty vehicles starting with model year 2027. The new rule builds upon existing federal GHG emissions standards established in 2021 for passenger cars and light trucks for Model Years 2023 through 2026. 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, including the outcome of legal challenges to the standards and the potential for EPA to reconsider them under the Trump administration. In addition, the Canadian federal government has published proposed regulated sales targets for electric vehicles.


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Climate Scenarios and Assumptions

We integrate the potential impact of climate change and 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 a number of globally recognized scenarios in our strategic planning for several years and 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 these external 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.

Labour Relations

We depend on unionized labour for the operation of certain facilities and may be subject to employee relations and labour disputes, which could disrupt operations at such facilities. As of December 31, 2024, approximately 11 percent of our employees were represented by unions under collective bargaining agreements, which includes just over 46 percent of our U.S. workforce. At unionized worksites, there is risk that strikes or work stoppages could occur. Any strike or work stoppage may have a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows.

In the event of a labour dispute, strike or work stoppage, mitigation and emergency operation plans may involve 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, future unionization efforts of Cenovus’s non-represented workforce 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 have a material adverse effect on our safety and reliability performance, reputation, results of operations and cash flows and may limit our operational flexibility.

Leadership and Talent

Our success is dependent upon 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 behaviours, leadership skills, and professional and technical competencies to drive our desired organizational and safety culture, it could have a material adverse effect on our business, safety performance, financial condition, results of operations and reputation. Failure to manage human resources risks may lead to financial and/or reputational loss, including loss arising from activity that is inconsistent with applicable employment laws.

Security and Terrorist Threats

Security threats and terrorist activities may impact our personnel, or those of partners, customers, and suppliers, which could result in 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 or terrorist attack 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. The risk profile for security and terrorist threats may vary based on geography, international developments and geopolitical risk levels, and the outcomes of such incidents could have a material adverse effect on our business, financial condition, results of operations, cash flows and reputation.

International Developments and Geopolitical Risk

We are exposed to the financial and operational risks associated with operating in the Asia Pacific region. Our business includes both operated and non-operated assets in the South China Sea, and requires cooperation agreements with our partner China National Offshore Oil Corporation or its subsidiaries (collectively, “CNOOC”). Additionally, the Asia Pacific business includes non-operated assets offshore in the Indonesia Madura Straights as operated by HCML, whereby CNOOC is the operator of HCML.

Political developments impacting international trade, particularly between Canada and the U.S., the U.S. and China, Canada and China, and EU and China, including military exercises, trade disputes, new or increased tariffs, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S., sanctions and other measures, may negatively impact markets and cause weaker macroeconomic conditions or drive political or national sentiment, weakening demand for crude oil, refined products, natural gas, NGLs and other related products, which could materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows.


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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’ approaches 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 have the potential to adversely affect our financial condition.

Increased tensions between the U.S. and China caused by military exercises around, or conflict involving, Taiwan and the South China Sea could lead to geopolitical uncertainty in the area, which may negatively impact our China business and operations, including by requiring us to curtail or suspend operations and reduce or shut in production, 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. Additionally, China enacted the Anti-Foreign Sanctions Law which 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 had a material impact on our business activities in Asia thus far, 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, refined products, natural gas, NGLs and other related 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.


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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.

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.

Litigation and Claims

From time to time, we may receive demands or be involved in disputes, regulatory orders, investigations or proceedings, arbitrations and/or litigation (“Claims”) arising out of, or related to, our business, operations and/or contractual relationships. Claims may be material. Due to the nature of our business and operations, we may be subject to various types of Claims including, but not limited to, failure to comply with applicable laws and regulations such as those related to health and safety, climate change, competition, public statements and marketing, the environment, including environmental claims, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, derivative actions, patent infringement, privacy, employment, human rights, labour relations, personal injury and other Claims.

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. 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, like Cenovus. We may 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 substantial expenses and devote significant resources in respect of any such Claims. In addition, any such Claims could result in unfavourable judgments, decisions, fines, sanctions, penalties, monetary damages, temporary or permanent suspensions of operations or restrictions on our business. The outcome of any such Claims can be difficult to assess or quantify and may have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows.

Environmental Plans and Regulations Risks

All phases of our operations are subject to environmental regulation, oversight and enforcement pursuant to a variety of laws and regulations imposed by various levels of governments in the jurisdictions in which we conduct operations, development or exploration, including land management plans, laws and regulations. Compliance with applicable regulations may result in approval delays for projects, critical licences and permits, stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, litigation, increased capital and operating expenses, increased compliance costs and increased costs for closure, controls/limits on land and resource access, reclamation, and ecological restoration. Third-party NGOs, citizen activist groups and Indigenous communities can also influence environmental laws and regulations in the jurisdictions in which we conduct our operations, development or exploration, including the U.S. and Canada. We anticipate that further changes in environmental legislation will occur, which may result in approval delays for projects, 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 laws and regulations make it difficult to predict the potential future impact to our business.

U.S. environmental and health and safety regulations and their aggressive enforcement from regulators present challenges and risks to our U.S. operations. These risks can arise if new emissions standards, water quality standards, occupational or process safety management requirements, or regulation of emerging contaminants are finalized or the government develops new interpretations that 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. For example, in July 2024, U.S. regulators designated certain per- and poly-fluoroalkyl substances (“PFAS”) as hazardous substances, which could lead to additional cleanup liability at U.S. sites.


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Canadian Species at Risk Act

The Canadian federal Species at Risk Act (“SARA”) and associated agreements, 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 or Leach’s Storm-Petrel. The extent and magnitude of any potential adverse impacts of legislation on project development and operations (which may include precluding further development or modification of existing operations) are very difficult to predict, as uncertainty exists as to whether jurisdictional plans and actions undertaken (at the regional/provincial level) will be sufficient to support the recovery of listed species. Similarly, uncertainty exists with respect to the outcome of litigation that could be initiated under SARA.

Canadian Federal Air Quality Management System

The Multi-Sector Air Pollutants Regulations (“MSAPRs”), 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 MSAPRs 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 MSAPRs 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 to retrofit existing facilities and increased operating costs.

Review of Environmental and Regulatory Processes

Increased or evolving environmental assessment obligations imposed by various levels of governments in the jurisdictions in which we conduct operations, development or exploration may create risk of increased costs, project development delays and an increased number of conditions. The regulatory frameworks within the jurisdictions where we conduct operations, development or exploration are constantly evolving 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 such regulatory frameworks on project development and operations cannot be estimated at this time.

Water Regulation

We utilize fresh water in certain operations, which is obtained in accordance with respective jurisdictions’ regulations, including through water licences. If water fees increase, the terms of water licences change or there are restrictions 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 licences. There is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted, or 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. Non-compliance with these requirements 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 PFAS in water discharge permits by requiring installation of additional wastewater treatment units and requiring monitoring of PFAS in discharges.

Hydraulic Fracturing

Legislative and regulatory initiatives have been introduced related to stakeholder claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources, and are increasing the frequency of seismic activity. 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, restrictions to freshwater usage, 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 and Goals

We have established ambitious targets in our five ESG focus areas and continue to allocate resources and progress tangible plans to meet these targets. 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 benefits of these investments may be less than we expect, which may have an adverse effect on our business, financial condition and reputation.


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Generally, our ESG goals 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. Investors and stakeholders increasingly compare companies based on ESG-related performance, including climate-related performance. Failure to achieve our ESG goals, or a perception among key stakeholders that our ESG goals 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 goals may fail to materialize, may cost more to achieve than we expect or may not occur within the anticipated time periods. In addition, there is a risk that the actions we take in implementing targets and ambitions relating to our ESG focus areas may, among other things, increase our capital expenditures and thereby impair our ability to invest in other aspects of our business, which could have a negative impact on our future operating and financial results.

Climate and GHG Emissions Reduction Goals

Our ability to meet our GHG emissions reduction goals is subject to numerous risks and uncertainties and our actions taken in implementing such goals may also expose us to certain additional and/or heightened litigation, financial and operational risks. A reduction in GHG emissions relies on, among other things, our ability to develop, access and implement commercially viable and scalable emissions reduction strategies, and related technology and products. 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 GHG emissions reduction goals on the planned timeline, or at all.

Furthermore, our longer-term goals are 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 such goals, and the cooperation and actions of third parties, including Pathways Alliance. The Pathways Alliance’s proposed carbon capture and storage project is of particular importance, and if this project is delayed or does not proceed, Cenovus’s ability to achieve its GHG reduction goals and ambitions will be delayed and may not be achieved.

In addition, achieving our GHG emissions reduction goals relies on the existence of a favourable and stable regulatory framework that includes, among other things, support from various levels of government, including financial support and shared capital cost commitments, which may not develop in a manner consistent with our expectations, or at all. Achieving our GHG emissions reduction goals will also 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 resulting 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 meet our water stewardship targets 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 deploy the necessary technologies, or such strategies or technologies do not perform as expected, progress toward our targets could be interrupted, delayed or abandoned.

Biodiversity Targets

Our ability to meet our biodiversity targets is subject to various operational, environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on us. See “Decommissioning” 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. In some cases, meeting our biodiversity targets has operational implications for reduced operational footprint and accelerated abandonment, reclamation and restoration.

Indigenous Reconciliation Targets

A failure or delay in achieving our Indigenous reconciliation targets or continuing to advance Indigenous reconciliation initiatives, may adversely affect our relationship with neighbouring Indigenous businesses and communities, and our reputation. If we are unable to maintain a positive relationship with Indigenous communities near our operations, our progress and ability to develop and operate projects in line with our current business and operational strategies may be adversely impacted.

Inclusion and Diversity Targets

Inclusion and valuing the diversity of our staff play a critical role in strengthening our business performance and culture. A failure or delay in achieving our inclusion and diversity targets, or a failure in our ability to maintain targets once met, could have a material adverse effect on our recruitment activities and reputation with our stakeholders.


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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.

Development of fossil fuel-based energy, and oil sands in particular, 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.

Shareholder activism has been increasing in the crude oil, natural gas, NGL and refining 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, Management 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.

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, including equity awards granted to our directors and officers, will have a further dilutive effect on the ownership interest of shareholders of Cenovus. Such dilutive effect on Cenovus's earnings per share could adversely affect the market price of Cenovus common shares and the value of our shareholders' investments.

Risks Relating to Acquisitions and Dispositions

We have completed, and may complete in the future, acquisitions and dispositions for various strategic reasons. We may not be able to complete such transactions on favourable terms, on a timely basis, or at all. The integration of acquired assets and operations may result in the disruption of business and may divert Management’s focus and resources from other strategic opportunities and operational matters during the process, which may result in increased costs and adversely affect our ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires assessments of their characteristics which are inexact and inherently uncertain and, as such, the acquired assets may not produce or operate as expected, may not have the anticipated benefits or synergies and may be subject to increased costs and liabilities. Further, we may not be able to obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition.

Various factors could materially affect our ability to dispose of assets in the future and may also reduce the proceeds or value realized from such dispositions. We may also retain certain liabilities or agree to indemnification obligations in a sale transaction, which may be difficult to quantify at the time of the transaction and could ultimately be material.

Should any of the risks associated with acquisitions or dispositions materialize, they could have an adverse effect on our business, financial condition or reputation.

Risks Related to Significant Shareholders of Cenovus

The sale into the market of Cenovus common shares held by significant shareholders of Cenovus, Hutchison Whampoa Europe Investments S.à r.l. (“Hutchison”), L.F. Investments S.à r.l. (“L.F. Investments”), and Capital World Investors (“Capital World”, together with Hutchison and L.F. Investments, the “Significant Shareholders”) or market perception regarding any intention of the Significant Shareholders 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, the Significant Shareholders may be able to impact certain matters requiring Cenovus shareholder approval.


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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 similar factors as those impacting the market price of Cenovus common shares. In addition, the market price of Cenovus common shares will significantly affect the market price of Cenovus Warrants which may result in significant volatility in the market price of the Cenovus Warrants and may negatively impact the value of the Cenovus Warrants.

Tax Laws

Income tax laws and regulations and other laws and government incentive programs (such as Canadian Carbon Capture Utilization and Storage Investment Tax Credits) may in the future be changed or interpreted in a manner that adversely affects us, our financial results, our ability to achieve our GHG emissions reduction goals 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. Further, as there are usually a number of tax matters under review, income taxes are subject to measurement uncertainty. 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 Organization for Economic Co-operation and Development. 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.

Pandemic Risk

Pandemics, epidemics or outbreaks, remain a risk for the Company, and the ultimate impact of a pandemic is highly uncertain and subject to change. A 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. Actions taken by various levels of government and health authorities in the event of a pandemic, epidemic or outbreak may result in a reduction in the demand for, and prices of, commodities that are closely linked to our financial performance and may negatively impact our business, results of operations and financial condition, and reputation.

Fighting Against Forced Labour and Child Labour in Supply Chains Act

The Fighting Against Forced Labour and Child Labour in Supply Chains Act requires Cenovus to publish an annual report on steps taken to assess and mitigate the risk of forced or child labour in its business and supply chains. Further, the customs tariff prohibits importing goods made in whole or in part with forced labour, child labour and prison labour. Increased scrutiny on forced or child labour in Canadian markets and supply chains, along with measures by us, our suppliers, other businesses and the Government of Canada, may impact business activities, including the import of goods and materials. These measures could lead to changes or disruptions in suppliers and supply chains, affecting the availability or cost of goods and materials we purchase. This could impact our access to certain goods or materials at desired prices, procurement processes, productivity, operating costs and financial condition. There is a risk that our supply chain may use or be alleged to use forced or child labour, and gathering sufficient information from suppliers to assess and mitigate such risks may be challenging. Our due diligence and mitigation activities might not identify or mitigate all risks, potentially harming our reputation. The Government of Canada plans to expand the legislative framework on forced and child labour, possibly including specific due diligence requirements for high-risk goods. However, there is uncertainty about the timing, requirements, implementation, and impact of these additional measures on our business activities and supply chains. The risks and commercial impacts of expanding regulation in this area cannot be fully assessed at this time.

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 sedarplus.ca, 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 material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements.

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.

Identification of Cash-Generating Units

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.

Assessment of Impairment Indicators or Impairment Reversals

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. 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. The identification of indicators of impairment or reversal of impairment requires significant judgment.

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.

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 WRB, a jointly-controlled entity. The joint arrangement meets the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

Prior to February 28, 2023, Cenovus held a 50 percent interest in BP-Husky Refining LLC (“Toledo”), which was jointly controlled with BP Products North America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo, as defined under IFRS 10, “Consolidated Financial Statements”, and, accordingly, Toledo was consolidated.


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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 Toledo and the past and future development of WRB, 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.

•Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services, purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does not have employees and, as such, is not capable of performing these roles.

•As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf.

•In each arrangement, output is taken by the partners, indicating that the partners have the rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

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 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 estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads, net of RINs, and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate market expectations and the evolving worldwide demand for energy.

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.

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 expected future production volumes, future development and operating expenses, forward commodity prices, estimated 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 quantity of reserves, expected future production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, net of RINs, future operating expenses and capital expenditures, and discount rates. 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 future production volumes, quantity of reserves, discount rates, and future development and operating expenses. Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology and engineering professionals, and IQREs. For downstream assets, key assumptions used to estimate fair value include refined product production, forward crude oil prices, forward crack spreads, net of RINs, future operating expenses, future capital expenditures and discount rates. 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.

Update to Accounting Policies

As of January 1, 2024, the Company updated its accounting policies to aggregate certain items presented in the Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Cash Flows to more appropriately reflect the integrated operations of the business. There were no re-measurements of balances. Certain historical disaggregated balances continue to be presented in Note 1 of the Consolidated Financial Statements.

The following presentation changes were made, with comparative periods being re-presented:

•Gross sales and royalties were aggregated and presented as ‘Revenues’.

•Purchased product and transportation and blending were aggregated and presented as ‘Purchased Product, Transportation and Blending’.

•Depreciation, depletion and amortization, and exploration expense were aggregated and presented as ‘Depreciation, Depletion, Amortization and Exploration Expense’.

•Finance costs and interest income were aggregated and presented as ‘Finance Costs, Net’.

•Revaluation (gain) loss and (gain) loss on divestiture of assets were aggregated and presented as ‘(Gain) Loss on Divestiture of Assets’.

New Accounting Standards and Interpretations Not Yet Adopted

Presentation and Disclosure in Financial Statements

On April 9, 2024, the IASB issued IFRS 18, “Presentation and Disclosure in Financial Statements” (“IFRS 18”), which will replace International Accounting Standard 1, “Presentation of Financial Statements”. IFRS 18 will establish a revised structure for the Consolidated Statements of Comprehensive Income (Loss) and improve comparability across entities and reporting periods.

IFRS 18 is effective for annual periods beginning on or after January 1, 2027. The standard is to be applied retrospectively, with certain transition provisions. The Company is currently evaluating the impact of adopting IFRS 18 on the Consolidated Financial Statements.


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Financial Instruments

On May 30, 2024, the IASB issued amendments to IFRS 9, “Financial Instruments”, and IFRS 7, “Financial Instruments: Disclosures”. The amendments include clarifications on the derecognition of financial liabilities and the classification of certain financial assets. In addition, new disclosure requirements for equity instruments designated as FVOCI were added. The amendments are effective for annual periods beginning on or after January 1, 2026, and will be applied retrospectively. The Company is currently evaluating the impact of the amendments on the Consolidated Financial Statements.



CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of ICFR and DC&P as at December 31, 2024. 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, 2024.

The effectiveness of our ICFR was audited as at December 31, 2024, 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 Consolidated Financial Statements for the year ended December 31, 2024.

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 are 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.

Interests in Joint Ventures

Cenovus holds interests in a number of joint ventures, as classified under IFRS Accounting Standards, that are accounted for using the equity method of accounting in our Consolidated Financial Statements, including a 30 percent equity ownership interest in Duvernay and a 40 percent equity ownership interest in HCML. Unless otherwise indicated, the operational events and results from these equity interests including, without limitation, production, reserves, revenues, costs and expenses may not be reflected in the Consolidated Financial Statements or this MD&A. As a result, the disclosure in the AIF in respect to certain equity method investees may differ from corresponding information in this MD&A. Readers are directed to the information contained under the heading “Reserves Data and Other Oil and Gas Information” in the AIF for further information regarding Cenovus’s interests in Duvernay and HCML.

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 “aim”, “anticipate”, “believe”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “may”, “objective”, “opportunities”, “plan”, “position”, “priority”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our five strategic objectives; shareholder value and returns; safety; sustainability; our commitment to the Pathways Alliance foundational project; maximizing value; disciplined capital allocation; Free Funds Flow; cash flow volatility and stability; focus on cost and sustainability improvements; liquidity; growth of our base business; capital investment; our 2025 corporate guidance; realizing the full value of our integrated business; reinvesting in our business; capitalizing on opportunities; Net Debt; allocating Excess Free Funds Flow; absolute and per share free funds flow growth; our competitive, reliable downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; project execution; progression of our planned drilling program; growing our competitive advantages while operating safely and reliably monitoring market fundamentals and optimizing run rates at our refineries; safe and reliable operations; being best-in-class operators; maintaining a strong balance sheet; costs; margins; long-term value for Cenovus; downstream reliability and profitability; timing for resuming production from the SeaRose FPSO, timing of first oil from the West White Rose project; progressing the Foster Creek optimization and Sunrise growth projects; our five ESG focus areas; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; volatility of refined product prices; impact of U.S. tariffs on market benchmarks and Cenovus; Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; capitalizing on opportunities throughout the commodity price cycle; Net Debt to Adjusted EBITDA ratio; maintaining sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar, the factors that affect such outlook, and the influences and effects 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. 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 bitumen, crude oil and natural gas, natural gas liquids, condensate and refined products prices, and light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs, 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, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions and the supply and demand for bitumen, 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, third party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			66

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 Company’s ability to use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange rate and interest rates; 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 and development plans and dividends, including any increase thereto; our downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; 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 its 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 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 divestitures, 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; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2025 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.

2025 guidance dated December 11, 2024, and available on cenovus.com, assumes: Brent prices of US$74.00 per barrel, WTI prices of US$70.00 per barrel; WCS of US$56.00 per barrel; Differential WTI-WCS of US$14.00 per barrel; AECO natural gas prices of $2.05 per Mcf; Chicago 3-2-1 crack spread of US$18.50 per barrel; and an exchange rate of $0.72 US$/C$.


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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 refining 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 and 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 refining 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 and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.

Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward‐looking statements, whether as a result of new information, future events or otherwise. 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 the Company’s most recently filed Annual 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 sedarplus.ca, 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 MD&A unless expressly incorporated by reference herein.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			68

ABBREVIATIONS AND DEFINITIONS

Abbreviations

The following abbreviations and definitions are used in this document:

Crude Oil and NGLs

Natural Gas

Other

bbl

barrel

Mcf

thousand cubic feet

BOE

barrel of oil equivalent

Mbbls/d

thousand barrels per day

MMcf

million cubic feet

MBOE

thousand barrels of oil
equivalent

MMbbls

million barrels

MMcf/d

million cubic feet per day

MBOE/d

thousand barrels of oil
equivalent per day

WCS

Western Canadian Select

Bcf

billion cubic feet

MMBOE

million barrels of oil equivalent

WTI

West Texas Intermediate

DD&A

depreciation, depletion and
amortization

ESG

environmental, social and
governance

GHG

greenhouse gas

CO2e

carbon dioxide equivalent

FPSO

floating production, storage and

offloading unit

NCIB

normal course issuer bid

AECO

Alberta Energy Company

NYMEX

New York Mercantile Exchange

OPEC

Organization of Petroleum
Exporting Countries

OPEC+

OPEC and a group of 11
non-OPEC members

SAGD

steam-assisted gravity drainage

USGC

U.S. Gulf Coast

Revision of Operational Metrics

Following changes to our downstream portfolio in recent years, we undertook a review of our downstream disclosures with the intent of enhancing the performance reporting of our refining operations and increasing comparability with peers. As a result of this review, commencing in June 2024, we introduced the following new, and/or revised, operational metrics to our Canadian Refining and our U.S. Refining segments. Comparative periods have been provided or recalculated where applicable.

•Total processed inputs is a new measure that reflects the overall inputs required to produce refined products in our refineries, and is used as the denominator in our per-unit measures, replacing crude oil unit throughput.

•Market capture is a new measure in our U.S. Refining segment that reflects Refining Margin generated as a percentage of the weighted average crack spread, net of RINs, on a FIFO basis of accounting. The weighted average crack spread, net of RINs is calculated on Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.

•Operable capacity is the capacity based on barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. Operable capacity has replaced crude oil unit throughput capacity, which was based on barrels per stream day and represents the amount of input that a distillation facility can process under optimal crude and product slate conditions, with no allowance for downtime.

•Crude unit utilization is crude oil unit throughput divided by operable capacity, expressed as a percentage. Previously this measure was calculated using crude oil unit throughput capacity.

The table below details the operable capacity and crude oil unit throughput capacity as at December 31, 2023, and is provided to illustrate the magnitude of the revised metrics detailed above:


(Mbbls/d)	Canadian Refining	U.S. Refining
Operable Capacity	108.0	612.3
Crude Oil Unit Throughput Capacity	110.5	635.2

Definitions and reconciliations of certain Specified Financial Measures, such as Refining Margin, Market Capture, per-unit operating expenses, per-unit operating expenses – excluding turnaround costs and per-unit operating expenses – turnaround costs are included in the Specified Financial Measures section of this MD&A.


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SPECIFIED FINANCIAL MEASURES

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS Accounting Standards including Operating Margin, Operating Margin by asset, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Total Long-Term Liabilities, Gross Margin, Refining Margin, Market Capture, Realized Sales Price, Offshore and Asia Pacific Per-Unit Operating Expenses, and Netbacks (including the total Netback per BOE).

These measures may not be comparable to similar measures presented by other issuers. These measures are 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 Accounting Standards. 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. Refer to the Specified Financial Measures Advisory of the relevant period’s MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow, Realized Sales Price and Netbacks for prior period information from 2024, 2023 and 2022 that is not found below.

Non-GAAP Measures and Non-GAAP Ratios

Operating Margin

Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for upstream or downstream operations 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 expenses, 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. The following tables provide a reconciliation to our unaudited interim Consolidated Financial Statements and accompanying notes for the periods ended December 31, 2024 (“interim Consolidated Financial Statements”).

Operating Margin


	Three Months Ended December 31,
	2024	2023	2024	2023	2024	2023
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales	6,050	5,796	7,677	8,240	13,727	14,036
Intersegment Sales	2,190	2,001	160	164	2,350	2,165
	8,240	7,797	7,837	8,404	16,077	16,201
Royalties	(914)	(902)	—	—	(914)	(902)
Revenues	7,326	6,895	7,837	8,404	15,163	15,299
Expenses
Purchased Product	1,000	663	7,364	7,888	8,364	8,551
Transportation and Blending	2,816	2,894	—	—	2,816	2,894
Operating	842	864	866	826	1,708	1,690
Realized (Gain) Loss on Risk Management	(2)	19	3	(6)	1	13
Operating Margin	2,670	2,455	(396)	(304)	2,274	2,151

(1)Found in Note 1 of the interim Consolidated Financial Statements.


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	Year Ended December 31,
	2024	2023		2024	2023	2024	2023
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales	24,640	23,713		33,086	31,761	57,726	55,474
Intersegment Sales	8,438	7,369		532	865	8,970	8,234
	33,078	31,082		33,618	32,626	66,696	63,708
Royalties	(3,449)	(3,270)		—	—	(3,449)	(3,270)
Revenues	29,629	27,812		33,618	32,626	63,247	60,438
Expenses
Purchased Product	3,674	3,152		30,252	28,273	33,926	31,425
Transportation and Blending	11,331	11,088		—	—	11,331	11,088
Operating	3,489	3,690		3,670	3,201	7,159	6,891
Realized (Gain) Loss on Risk Management	14	12		8	—	22	12
Operating Margin	11,121	9,870		(312)	1,152	10,809	11,022

(1)Found in Note 1 of the Consolidated Financial Statements.

Operating Margin by Asset


	Year Ended December 31, 2024
($ millions)		Atlantic	Asia Pacific	Offshore (1)
Gross Sales		322	1,250	1,572
Royalties		(2)	(97)	(99)
Revenues		320	1,153	1,473
Expenses
Transportation and Blending		11	—	11
Operating		290	133	423
Operating Margin		19	1,020	1,039


	Year Ended December 31, 2023
($ millions)		Atlantic	Asia Pacific	Offshore (1)
Gross Sales		400	1,217	1,617
Royalties		(15)	(84)	(99)
Revenues		385	1,133	1,518
Expenses
Transportation and Blending		16	—	16
Operating		262	122	384
Operating Margin		107	1,011	1,118

(1)Found in Note 1 of the Consolidated Financial Statements.

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, in total and on a per-share basis. Adjusted Funds Flow is defined as cash from (used in) operating activities excluding settlement of decommissioning liabilities and net change in operating non-cash working capital. Operating non-cash working capital is composed of accounts receivable and accrued revenues, income tax receivable, inventories (excluding non-cash inventory write-downs and reversals), 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 operating non-cash working capital, minus capital investment.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			71

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, net purchases of common shares under the employee benefit plan, other uses of cash (including settlement of decommissioning liabilities and principal repayment of leases), and expenditures for acquisitions net of cash acquired, plus proceeds from, or payments related to, divestitures.


	Three Months Ended December 31,		Year Ended December 31,
($ millions)	2024	2023	2024	2023
Cash From (Used in) Operating Activities	2,029	2,946	9,235	7,388
(Add) Deduct:
Settlement of Decommissioning Liabilities	(64)	(65)	(234)	(222)
Net Change in Non-Cash Working Capital	492	949	1,305	(1,193)
Adjusted Funds Flow	1,601	2,062	8,164	8,803
Capital Investment	1,478	1,170	5,015	4,298
Free Funds Flow	123	892	3,149	4,505
Add (Deduct):
Base Dividends Paid on Common Shares	(330)	(261)	(1,255)	(990)
Dividends Paid on Preferred Shares	(18)	(9)	(45)	(36)
Purchase of Common Shares Under Employee Benefit Plan	(43)	—	(43)	—
Settlement of Decommissioning Liabilities	(64)	(65)	(234)	(222)
Principal Repayment of Leases	(80)	(72)	(299)	(288)
Acquisitions, Net of Cash Acquired	(3)	(14)	(22)	(515)
Proceeds From Divestitures	(1)	—	46	12

Excess Free Funds Flow	(416)	471	1,297	2,466

Total Long-Term Liabilities

Total Long-Term Liabilities is a non-GAAP financial measure. The measure is disclosed to fulfill the requirements of National Instrument 51-102, “Continuous Disclosure Obligations” and is defined as total liabilities less total current liabilities.


	As at December 31,
($ millions)	2024	2023	2022
Total Liabilities	26,770	25,203	28,280
Less: Total Current Liabilities	7,362	6,210	8,021
Total Long-Term Liabilities	19,408	18,993	20,259

Gross Margin, Refining Margin and Market Capture

Gross Margin is a non-GAAP financial measure and Refining Margin contains a non-GAAP financial measure. These measures are 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 from our refineries, Upgrader and commercial fuels business divided by total processed inputs. Commencing in June 2024, total processed inputs was updated as the denominator to better reflect the overall inputs required to produce refined products. Before June 30, 2024, comparative periods were calculated based on barrels of crude oil unit throughput. All comparative periods have been revised to conform with our current presentation. The following tables for the quarters ended December 31, 2024 and 2023, provide a reconciliation to our interim Consolidated Financial Statements.


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Canadian Refining


	Three Months Ended December 31, 2024

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,207	56	1,263
Purchased Product	1,032	36	1,068
Gross Margin	175	20	195

Total Processed Inputs (Mbbls/d)	112.1

Refining Margin ($/bbl)	16.95

(1)Includes ethanol operations and crude-by-rail operations.

(2)These amounts, excluding Gross Margin, are found in Note 1 of the interim Consolidated Financial Statements.


	Three Months Ended December 31, 2023

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,454	103	1,557
Purchased Product	1,197	66	1,263
Gross Margin	257	37	294

Total Processed Inputs (Mbbls/d)	105.1

Refining Margin ($/bbl)	26.48

(1)Includes ethanol operations and crude-by-rail operations.

(2)These amounts, excluding Gross Margin, are found in Note 1 of the interim Consolidated Financial Statements.


	Year Ended December 31, 2024

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	5,014	296	5,310
Purchased Product	4,278	205	4,483
Gross Margin	736	91	827

Total Processed Inputs (Mbbls/d)	96.6

Refining Margin ($/bbl)	20.82

(1)Includes ethanol operations and crude-by-rail operations.

(2)These amounts, excluding Gross Margin, are found in Note 1 of the Consolidated Financial Statements.


	Year Ended December 31, 2023

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	5,812	421	6,233
Purchased Product	4,634	285	4,919
Gross Margin	1,178	136	1,314

Total Processed Inputs (Mbbls/d)	107.1

Refining Margin ($/bbl)	30.13

(1)Includes ethanol operations and crude-by-rail operations.

(2)These amounts, excluding Gross Margin, are found in Note 1 of the Consolidated Financial Statements.


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	Three Months Ended March 31, 2024

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining
Revenues	1,249	83	1,332
Purchased Product	1,024	63	1,087
Gross Margin	225	20	245

Total Processed Inputs (Mbbls/d)	108.8

Refining Margin ($/bbl)	22.68

(1)Includes ethanol operations and crude-by-rail operations.

U.S. Refining

Market Capture contains a non-GAAP financial measure and is used in our U.S. Refining segment to provide an indication of margin captured relative to what was available in the market based on widely-used benchmarks. We define Market Capture as Refining Margin divided by the weighted average 3-2-1 market benchmark crack, net of RINs, expressed as a percentage. The weighted average crack spread, net of RINs, is calculated on Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.


	Three Months Ended December 31,		Year Ended December 31,
($ millions)	2024	2023	2024	2023
Revenues (1)	6,574	6,847	28,308	26,393
Purchased Product (1)	6,296	6,625	25,769	23,354
Gross Margin	278	222	2,539	3,039

Total Processed Inputs (Mbbls/d)	588.4	500.6	581.4	479.7

Refining Margin ($/bbl)	5.14	4.82	11.93	17.36

Operable Capacity (Mbbls/d)	612.3	612.3	612.3	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81	81	82
Group 3 3-2-1 Crack Spread Weighting	19	19	19	18

Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	12.12	13.24	16.74	24.19
Group 3 3-2-1 Crack Spread (US$/bbl)	12.66	18.55	16.81	29.66
RINs (US$/bbl)	4.02	4.77	3.74	7.04
US$ per C$1 – Average	0.715	0.734	0.730	0.741

Weighted Average Crack Spread, Net of RINs ($/bbl)	11.47	12.94	17.82	24.49

Market Capture (2) (percent)	45	37	67	71

(1)Found in Note 1 of the interim Consolidated Financial Statements.

(2)The Superior Refinery’s operable capacity is included in Market Capture effective April 1, 2023. For the year ended December 31, 2023, Market Capture includes a weighted average operable capacity for the Toledo Refinery as full ownership was acquired on February 28, 2023.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			74



($ millions)									Three Months Ended March 31, 2024
Revenues (1)									6,901
Purchased Product (1)									5,798
Gross Margin									1,103

Total Processed Inputs (Mbbls/d)									575.0

Refining Margin ($/bbl)									21.08

Operable Capacity (Mbbls/d)									612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting									81
Group 3 3-2-1 Crack Spread Weighting									19

Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)									17.45
Group 3 3-2-1 Crack Spread (US$/bbl)									17.50
RINs (US$/bbl)									3.68
US$ per C$1 – Average									0.741

Weighted Average Crack Spread, Net of RINs ($/bbl)									18.59

Market Capture (percent)									113

(1)Reflects certain revisions. See Prior Period Revisions section of this MD&A.

Netback Reconciliations and Realized Sales Price

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. Our Netback calculation is substantially aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netback is defined as gross sales less royalties, transportation and blending, and operating expenses. 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. Condensate or butane (diluent) is blended with crude oil to transport it to market. In March 2024, modifications were made to our Netback definition to enhance the clarity of certain costs captured in this metric. These modifications resulted in minor adjustments that are captured in the Netback calculation on a prospective basis.

The following tables provide a reconciliation of Netback to Operating Margin found in our interim Consolidated Financial Statements and Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			75

Oil Sands


	Basis of Netback Calculation
Three Months Ended December 31, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	1,454	1,646	380	871	4,351	—	4,351
Royalties	(283)	(455)	(19)	(117)	(874)	—	(874)
Revenues	1,171	1,191	361	754	3,477	—	3,477
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	281	137	59	44	521	—	521
Operating	163	187	72	200	622	—	622
Netback	727	867	230	510	2,334	—	2,334
Realized (Gain) Loss on Risk Management							(3)
Operating Margin							2,337


	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2024 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	4,351		2,181	465	94	7,091
Royalties	(874)		—	—	—	(874)
Revenues	3,477		2,181	465	94	6,217
Expenses
Purchased Product	—		—	465	65	530
Transportation and Blending	521		2,181	—	33	2,735
Operating	622		—	—	(7)	615
Netback	2,334		—	—	3	2,337
Realized (Gain) Loss on Risk Management	(3)		—	—	—	(3)
Operating Margin	2,337		—	—	3	2,340

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.

(2)Other includes construction, transportation and blending.

(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.


	Basis of Netback Calculation
Three Months Ended December 31, 2023 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	1,312	1,447	357	778	3,894	2	3,896
Royalties	(353)	(366)	(32)	(86)	(837)	(1)	(838)
Revenues	959	1,081	325	692	3,057	1	3,058
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	200	161	58	39	458	—	458
Operating	174	167	65	203	609	1	610
Netback	585	753	202	450	1,990	—	1,990
Realized (Gain) Loss on Risk Management							24
Operating Margin							1,966


	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2023 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	3,896		2,329	156	96	6,477
Royalties	(838)		—	—	(3)	(841)
Revenues	3,058		2,329	156	93	5,636
Expenses
Purchased Product	—		—	156	70	226
Transportation and Blending	458		2,329	—	22	2,809
Operating	610		—	—	5	615
Netback	1,990		—	—	(4)	1,986
Realized (Gain) Loss on Risk Management	24		—	—	—	24
Operating Margin	1,966		—	—	(4)	1,962

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.

(2)Other includes construction, transportation and blending.

(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			76


	Basis of Netback Calculation
Year Ended December 31, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	5,837	6,428	1,574	3,724	17,563	—	17,563
Royalties	(1,176)	(1,601)	(78)	(413)	(3,268)	—	(3,268)
Revenues	4,661	4,827	1,496	3,311	14,295	—	14,295
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	937	554	294	185	1,970	—	1,970
Operating	682	733	263	819	2,497	—	2,497
Netback	3,042	3,540	939	2,307	9,828	—	9,828
Realized (Gain) Loss on Risk Management							20
Operating Margin							9,808


	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2024 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	17,563		8,913	1,531	440	28,447
Royalties	(3,268)		—	—	(6)	(3,274)
Revenues	14,295		8,913	1,531	434	25,173
Expenses
Purchased Product	—		—	1,531	320	1,851
Transportation and Blending	1,970		8,913	—	117	11,000
Operating	2,497		—	—	14	2,511
Netback	9,828		—	—	(17)	9,811
Realized (Gain) Loss on Risk Management	20		—	—	—	20
Operating Margin	9,808		—	—	(17)	9,791

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.

(2)Other includes construction, transportation and blending.

(3)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.


	Basis of Netback Calculation
Year Ended December 31, 2023 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	5,347	5,848	1,298	3,208	15,701	8	15,709
Royalties	(1,136)	(1,556)	(74)	(285)	(3,051)	(5)	(3,056)
Revenues	4,211	4,292	1,224	2,923	12,650	3	12,653
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	819	572	215	153	1,759	—	1,759
Operating	782	729	294	884	2,689	9	2,698
Netback	2,610	2,991	715	1,886	8,202	(6)	8,196
Realized (Gain) Loss on Risk Management							17
Operating Margin							8,179


	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2023 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	15,709		8,907	1,199	377	26,192
Royalties	(3,056)		—	—	(3)	(3,059)
Revenues	12,653		8,907	1,199	374	23,133
Expenses
Purchased Product	—		—	1,199	258	1,457
Transportation and Blending	1,759		8,907	—	108	10,774
Operating	2,698		—	—	18	2,716
Netback	8,196		—	—	(10)	8,186
Realized (Gain) Loss on Risk Management	17		—	—	—	17
Operating Margin	8,179		—	—	(10)	8,169

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.

(2)Other includes construction, transportation and blending.

(3)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			77

Conventional


	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2024 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	273	470	33	776
Royalties	(15)	—	—	(15)
Revenues	258	470	33	761
Expenses
Purchased Product	—	470	—	470
Transportation and Blending	52	—	27	79
Operating	118	—	5	123
Netback	88	—	1	89
Realized (Gain) Loss on Risk Management	1	—	—	1
Operating Margin	87	—	1	88


	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2023 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	331	437	38	806
Royalties	(27)	—	—	(27)
Revenues	304	437	38	779
Expenses
Purchased Product	—	437	—	437
Transportation and Blending	54	—	24	78
Operating	141	—	5	146
Netback	109	—	9	118
Realized (Gain) Loss on Risk Management	(5)	—	—	(5)
Operating Margin	114	—	9	123

(1)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.

(2)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.


	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2024 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	1,105	1,823	131	3,059
Royalties	(76)	—	—	(76)
Revenues	1,029	1,823	131	2,983
Expenses
Purchased Product	—	1,823	—	1,823
Transportation and Blending	218	—	102	320
Operating	526	—	29	555
Netback	285	—	—	285
Realized (Gain) Loss on Risk Management	(6)	—	—	(6)
Operating Margin	291	—	—	291


	Basis of Netback Calculation	Adjustments
Year Ended December 31, 2023 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	1,390	1,695	188	3,273
Royalties	(112)	—	—	(112)
Revenues	1,278	1,695	188	3,161
Expenses
Purchased Product	—	1,695	—	1,695
Transportation and Blending	182	—	116	298
Operating	570	—	20	590
Netback	526	—	52	578
Realized (Gain) Loss on Risk Management	(5)	—	—	(5)
Operating Margin	531	—	52	583

(1)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.

(2)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			78

Offshore


	Basis of Netback Calculation					Adjustments
Three Months Ended December 31, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	58	315	110	425	483	(110)	—	373
Royalties	—	(25)	(27)	(52)	(52)	27	—	(25)
Revenues	58	290	83	373	431	(83)	—	348
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	2	—	—	—	2	—	—	2
Operating	65	35	20	55	120	(19)	3	104
Netback	(9)	255	63	318	309	(64)	(3)	242
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					309	(64)	(3)	242


	Basis of Netback Calculation					Adjustments
Three Months Ended December 31, 2023 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	168	346	91	437	605	(91)	—	514
Royalties	(4)	(30)	(18)	(48)	(52)	18	—	(34)
Revenues	164	316	73	389	553	(73)	—	480
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	7	—	—	—	7	—	—	7
Operating	71	29	17	46	117	(15)	1	103
Netback	86	287	56	343	429	(58)	(1)	370
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					429	(58)	(1)	370

(1)Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the interim Consolidated Financial Statements.

(2)Primarily related to Offshore project expenses.

(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.


	Basis of Netback Calculation					Adjustments
Year Ended December 31, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	322	1,250	339	1,589	1,911	(339)	—	1,572
Royalties	(2)	(97)	(55)	(152)	(154)	55	—	(99)
Revenues	320	1,153	284	1,437	1,757	(284)	—	1,473
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	11	—	—	—	11	—	—	11
Operating	287	119	64	183	470	(56)	9	423
Netback	22	1,034	220	1,254	1,276	(228)	(9)	1,039
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					1,276	(228)	(9)	1,039


	Basis of Netback Calculation					Adjustments
Year Ended December 31, 2023 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	400	1,217	317	1,534	1,934	(317)	—	1,617
Royalties	(15)	(84)	(74)	(158)	(173)	74	—	(99)
Revenues	385	1,133	243	1,376	1,761	(243)	—	1,518
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	16	—	—	—	16	—	—	16
Operating	239	111	58	169	408	(47)	23	384
Netback	130	1,022	185	1,207	1,337	(196)	(23)	1,118
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					1,337	(196)	(23)	1,118

(1)Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements.

(2)Primarily related to Offshore project expenses.

(3)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			79

Upstream 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)	2024	2023	2024	2023
Oil Sands (2)
Foster Creek	184.0	192.6	188.8	187.4
Christina Lake	245.7	238.6	231.9	234.3
Sunrise	52.2	50.8	50.0	47.3
Lloydminster	125.9	123.4	127.7	120.5
Total Oil Sands	607.8	605.4	598.4	589.5

Conventional	117.8	123.8	119.9	119.9

Offshore
Atlantic	6.2	15.0	8.0	9.6
Asia Pacific
China	42.6	44.2	42.6	40.5
Indonesia	19.6	16.3	16.0	14.7
Total Asia Pacific	62.2	60.5	58.6	55.2
Total Offshore	68.4	75.5	66.6	64.8

(1)Sales volumes exclude the impact of purchased condensate.

(2)Includes bitumen and heavy crude oil sales.

Other Specified Financial Measures

Per-Unit Operating Expenses and Turnaround Costs

Per-unit operating expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. We define Canadian Refining per-unit operating expenses as total operating expenses from the Upgrader, the Lloydminster Refinery and the commercial fuels business, divided by total processed inputs. We define U.S. Refining per-unit operating expenses as operating expenses divided by total processed inputs.

Per-unit operating expenses – excluding turnaround costs are specified financial measures used to evaluate the normalized performance of our downstream operations. We define per-unit operating expenses – excluding turnaround costs as the refining segments’ operating expenses – excluding turnaround costs divided by total processed inputs.

Per-unit operating expenses – turnaround costs are specified financial measures used to evaluate the cost of turnarounds for our downstream operations. We define per-unit operating expenses – turnaround costs as the refining segments’ operating expenses – turnaround costs divided by total processed inputs.

Our upstream per-unit operating expenses are defined as total operating expenses divided by sales volumes and are part of our Netback calculation, which can be found above.

Per-Unit Transportation Expenses

Per-unit transportation expenses are specified financial measures used to measure transportation expenses on a per-unit basis in our upstream segments. We define per-unit transportation expenses as the total transportation expenses divided by sales volumes. Our upstream per-unit transportation expenses are part of the transportation and blending line in our Netback calculation, which can be found above.

Per-Unit Depreciation, Depletion and Amortization

Per-unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define per-unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties, and the associated decommissioning costs, divided by sales volumes.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			80


Prior Period Revisions

During the three months ended December 31, 2024, it was identified that certain transactions in the U.S Refining segment undertaken in contemplation of each other were reported on a gross basis in revenues and purchased product rather than on a net basis. As a result, revenues and purchased product were overstated for the nine months ended September 30, 2024. Prior quarters have been restated to reflect the change. There was no impact on net earnings (loss), segment income (loss), cash flows or financial position.

The following tables reconcile the amounts previously reported in the Consolidated Statements of Comprehensive Income (Loss) and segmented disclosures to the corresponding revised amounts:


	U.S. Refining Segment			Consolidated
For the three months ended March 31, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,235	(334)	6,901	13,397	(334)	13,063
Purchased Product	6,132	(334)	5,798	6,133	(334)	5,799
Transportation and Blending	—	—	—	2,575	—	2,575
Purchased Product, Transportation and Blending (1)	6,132	(334)	5,798	8,708	(334)	8,374
	1,103	—	1,103	4,689	—	4,689


	U.S. Refining Segment			Consolidated
For the three months ended June 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,918	(303)	7,615	14,885	(303)	14,582
Purchased Product	7,124	(303)	6,821	7,184	(303)	6,881
Transportation and Blending	—	—	—	2,865	—	2,865
Purchased Product, Transportation and Blending (1)	7,124	(303)	6,821	10,049	(303)	9,746
	794	—	794	4,836	—	4,836


	U.S. Refining Segment			Consolidated
For the three months ended September 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,648	(430)	7,218	14,249	(430)	13,819
Purchased Product	7,284	(430)	6,854	7,556	(430)	7,126
Transportation and Blending	—	—	—	2,489	—	2,489
Purchased Product, Transportation and Blending (1)	7,284	(430)	6,854	10,045	(430)	9,615
	364	—	364	4,204	—	4,204

(1)Revised presentation as of January 1, 2024. Refer to Note 4 of the Consolidated Financial Statements for further detail.


Cenovus Energy Inc. – 2024 Management's Discussion and Analysis			81

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Exhibit 99.3

Cenovus Energy Inc.

Consolidated Financial Statements

For the Year Ended December 31, 2024

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS


For the year ended December 31, 2024


TABLE OF CONTENTS


REPORT OF MANAGEMENT						3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM						4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)						7

CONSOLIDATED BALANCE SHEETS						8
CONSOLIDATED STATEMENTS OF EQUITY						9
CONSOLIDATED STATEMENTS OF CASH FLOWS						10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS						11
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES						11
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE						16
3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY						16
4. UPDATES TO ACCOUNTING POLICIES						18
5. ACQUISITIONS AND DIVESTITURES						19
6. GENERAL AND ADMINISTRATIVE						20
7. FINANCE COSTS, NET						20

8. FOREIGN EXCHANGE (GAIN) LOSS, NET						20

9. IMPAIRMENT CHARGES AND REVERSALS						20

10. INCOME TAXES						22
11. PER SHARE AMOUNTS						25
12. CASH AND CASH EQUIVALENTS						26
13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES						26
14. INVENTORIES						26

15. EXPLORATION AND EVALUATION ASSETS, NET						27
16. PROPERTY, PLANT AND EQUIPMENT, NET						28
17. LEASES						29
18. JOINT ARRANGEMENTS						30
19. OTHER ASSETS						31
20. GOODWILL						31
21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES						31
22. DEBT AND CAPITAL STRUCTURE						31

23. CONTINGENT PAYMENTS						35
24. DECOMMISSIONING LIABILITIES						35
25. OTHER LIABILITIES						36
26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS						36
27. SHARE CAPITAL AND WARRANTS						39
28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)						42
29. STOCK-BASED COMPENSATION PLANS						42
30. EMPLOYEE SALARIES AND BENEFIT EXPENSES						45
31. RELATED PARTY TRANSACTIONS						45
32. FINANCIAL INSTRUMENTS						46
33. RISK MANAGEMENT						48
34. SUPPLEMENTARY CASH FLOW INFORMATION						51
35. COMMITMENTS AND CONTINGENCIES						53
36. MATERIAL ACCOUNTING POLICIES						53


Cenovus Energy Inc. – 2024 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 Accounting 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 four 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 meets 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.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2024. 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 their evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2024.

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, 2024, as stated in their Report of Independent Registered Public Accounting Firm dated February 19, 2025. PricewaterhouseCoopers LLP has provided such opinions.


/s/ Jonathan M. McKenzie			/s/ Karamjit S. Sandhar
Jonathan M. McKenzie			Karamjit S. Sandhar
President & Chief Executive Officer			Executive Vice-President & Chief Financial Officer
Cenovus Energy Inc.			Cenovus Energy Inc.

February 19, 2025


Cenovus Energy Inc. – 2024 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, 2024 and 2023, and the related consolidated statements of comprehensive income (loss), of equity and of cash flows for the years then ended, 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, 2024, 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, 2024 and 2023, and its financial performance and its cash flows for the years then ended 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, 2024, 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. – 2024 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.

Impact of Crude Oil and Natural Gas Reserves (together, the Reserves) on Property, Plant and Equipment (PP&E), Net within the Oil Sands and Offshore Segments

As described in Notes 1, 3, 9, 16 and 36 to the Consolidated Financial Statements, Management assesses its cash-generating units (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 depreciation, depletion and amortization (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. 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 those proved or proved plus probable reserves. As of December 31, 2024, the Company had $24.6 billion and $3.4 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company recognized $3.7 billion of DD&A expense and noted no indicators of impairment related to PP&E in the Oil Sands and Offshore segments in the year ended December 31, 2024. Estimating reserves requires the use of significant assumptions and judgments by Management related to expected future production volumes, future development and operating expenses, as well as forward commodity prices. Management’s estimates of reserves used for 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 on PP&E, net, within 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 (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to expected future production volumes, future development and operating expenses, as well as forward commodity prices.

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 and the calculation of DD&A expenses related to PP&E in the Oil Sands and Offshore segments. These procedures also included, among others, testing Management’s process for determining DD&A expense for the Oil Sands and Offshore segments, which included for certain properties (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of the underlying data used in Management’s estimates of reserves; (iii) assessing the reasonability of the significant assumptions related to expected future production volumes, future development and operating expenses, as well as forward commodity prices, 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 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 for certain properties within the Oil Sands and Offshore segments, 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 expected future production volumes, future development and operating expenses, as well as forward commodity prices 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.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			5

Impairment Assessment of PP&E for each of the Wood River, Toledo, and Lima CGUs within the U.S. Refining Segment

As described in Notes 1, 3, 9, 16 and 36 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 including net impairment losses, may exceed its recoverable amount. If indicators of impairment exist, the recoverable amount of the CGU is estimated as the greater of value-in-use and fair value less costs of disposal (FVLCOD). As of December 31, 2024, the Company had $5.5 billion of PP&E assets net of accumulated DD&A including net impairment losses relating to the U.S. Refining segment, of which the majority related to the Wood River, Toledo, and Lima CGUs. Management identified indicators of impairment for these CGUs and performed impairment assessments for each of these CGUs as of December 31, 2024. The recoverable amounts of these CGUs were determined to be greater than their carrying amounts and no impairment charge was recorded. Management determined the recoverable amounts of these CGUs based on their FVLCOD using discounted after-tax cash flows models requiring the use of significant assumptions and judgments by Management related to refined product production, forward crude oil prices, forward crack spreads, net of renewable identification numbers (RINs), future operating expenses, future capital expenditures and discount rates.

The principal considerations for our determination that performing procedures relating to the impairment assessment of PP&E for each of the Wood River, Toledo, and Lima CGUs within the U.S. Refining segment is a critical audit matter are (i) the significant amount of judgment required by Management when developing the recoverable amounts for these 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 refined product production, forward crude oil prices, forward crack spreads, net of RINs, future operating expenses, future capital expenditures and discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

/s/ PricewaterhouseCoopers LLP


Chartered Professional Accountants
Calgary, Alberta, Canada
February 19, 2025
We have served as the Company’s auditor since 2008.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			6


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the years ended December 31,

($ millions, except per share amounts)


	Notes	2024	2023




Revenues (1)	1	54,277	52,204
Expenses	1
Purchased Product, Transportation and Blending (1)		36,641	34,856
Operating		6,841	6,352
(Gain) Loss on Risk Management	32	58	61
Depreciation, Depletion, Amortization and Exploration Expense (1)	15,16,17	4,940	4,686
(Income) Loss From Equity-Accounted Affiliates	18	(66)	(51)
General and Administrative	6	794	688
Finance Costs, Net (1)	7	514	538
Integration, Transaction and Other Costs		166	85
Foreign Exchange (Gain) Loss, Net	8	462	(67)
(Gain) Loss on Divestiture of Assets (1)	5	(119)	20
Re-measurement of Contingent Payments	23	30	59
Other (Income) Loss, Net		(55)	(63)
Earnings (Loss) Before Income Tax		4,071	5,040
Income Tax Expense (Recovery)	10	929	931
Net Earnings (Loss)		3,142	4,109

Other Comprehensive Income (Loss), Net of Tax	28
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits	26	14	(44)
Change in the Fair Value of Equity Instruments at FVOCI (2)	32	71	56
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		1,020	(274)
Total Other Comprehensive Income (Loss), Net of Tax		1,105	(262)
Comprehensive Income (Loss)		4,247	3,847

Net Earnings (Loss) Per Common Share ($)	11
Basic		1.68	2.15
Diluted		1.67	2.09

(1)Revised presentation as of January 1, 2024. See Note 4.

(2)Fair value through other comprehensive income (loss) (“FVOCI”).

See accompanying Notes to the Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			7


CONSOLIDATED BALANCE SHEETS

As at December 31,

($ millions)


	Notes	2024	2023

Assets
Current Assets
Cash and Cash Equivalents	12	3,093	2,227

Accounts Receivable and Accrued Revenues	13	2,614	3,035
Income Tax Receivable		231	416
Inventories	14	4,496	4,030

Total Current Assets		10,434	9,708
Restricted Cash	24	241	211
Exploration and Evaluation Assets, Net	1,15	484	738
Property, Plant and Equipment, Net	1,16	38,568	37,250
Right-of-Use Assets, Net	1,17	1,950	1,680
Income Tax Receivable		25	25
Investments in Equity-Accounted Affiliates	18	399	366
Other Assets	19	451	318
Deferred Income Taxes	10	1,064	696
Goodwill	1,20	2,923	2,923
Total Assets		56,539	53,915

Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities	21	6,242	5,480
Income Tax Payable		396	88
Short-Term Borrowings	22	173	179
Long-Term Debt	22	192	—
Lease Liabilities	17	359	299
Contingent Payments	23	—	164

Total Current Liabilities		7,362	6,210
Long-Term Debt	22	7,342	7,108
Lease Liabilities	17	2,568	2,359

Decommissioning Liabilities	24	4,534	4,155
Other Liabilities	25	919	1,183
Deferred Income Taxes	10	4,045	4,188
Total Liabilities		26,770	25,203
Shareholders’ Equity		29,754	28,698
Non-Controlling Interest		15	14
Total Liabilities and Equity		56,539	53,915

Commitments and Contingencies	35

See accompanying Notes to the Consolidated Financial Statements.


/s/ Alexander J. Pourbaix			/s/ Jane E. Kinney
Alexander J. Pourbaix			Jane E. Kinney
Director			Director
Cenovus Energy Inc.			Cenovus Energy Inc.

February 19, 2025


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			8


CONSOLIDATED STATEMENTS OF EQUITY

($ millions)


	Shareholders’ Equity
	Common Shares	Treasury Shares	Preferred Shares	Warrants	Paid in Surplus	Retained Earnings	AOCI (1)	Total
	(Note 27)	(Note 27)	(Note 27)	(Note 27)	(Note 27)		(Note 28)







As at December 31, 2022	16,320	—	519	184	2,691	6,392	1,470	27,576
Net Earnings (Loss)	—	—	—	—	—	4,109	—	4,109
Other Comprehensive Income (Loss), Net of Tax	—	—	—	—	—	—	(262)	(262)
Total Comprehensive Income (Loss)	—	—	—	—	—	4,109	(262)	3,847

Common Shares Issued Under Stock Option Plans	58	—	—	—	(12)	—	—	46
Purchase of Common Shares Under NCIB (2)	(373)	—	—	—	(688)	—	—	(1,061)
Warrants Exercised	26	—	—	(8)	—	—	—	18
Warrants Purchased and Cancelled	—	—	—	(151)	—	(562)	—	(713)
Stock-Based Compensation Expense	—	—	—	—	11	—	—	11
Base Dividends on Common Shares	—	—	—	—	—	(990)	—	(990)

Dividends on Preferred Shares	—	—	—	—	—	(36)	—	(36)

As at December 31, 2023	16,031	—	519	25	2,002	8,913	1,208	28,698
Net Earnings (Loss)	—	—	—	—	—	3,142	—	3,142
Other Comprehensive Income (Loss), Net of Tax	—	—	—	—	—	—	1,105	1,105
Total Comprehensive Income (Loss)	—	—	—	—	—	3,142	1,105	4,247

Common Shares Issued Under Stock Option Plans	68	—	—	—	(16)	—	—	52
Purchase of Common Shares Under NCIB (2)	(479)	—	—	—	(966)	—	—	(1,445)
Purchase of Common Shares Under Employee Benefit Plan	—	(43)	—	—	—	—	—	(43)
Preferred Shares Redeemed	—	—	(163)	—	(87)	—	—	(250)

Warrants Exercised	39	—	—	(13)	—	—	—	26

Stock-Based Compensation Expense	—	—	—	—	11	—	—	11

Base Dividends on Common Shares	—	—	—	—	—	(1,255)	—	(1,255)
Variable Dividends on Common Shares	—	—	—	—	—	(251)	—	(251)
Dividends on Preferred Shares	—	—	—	—	—	(36)	—	(36)

As at December 31, 2024	15,659	(43)	356	12	944	10,513	2,313	29,754

(1)Accumulated other comprehensive income (loss) (“AOCI”).

(2)Normal course issuer bid (“NCIB”). For the year ended December 31, 2024, amount includes taxes payable on purchase of shares.

See accompanying Notes to the Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			9


CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,

($ millions)



	Notes	2024	2023

Operating Activities
Net Earnings (Loss)		3,142	4,109
Depreciation, Depletion and Amortization	16,17	4,871	4,644



Deferred Income Tax Expense (Recovery)	10	(474)	(250)
Unrealized (Gain) Loss on Risk Management	32	12	52
Unrealized Foreign Exchange (Gain) Loss	8	550	(210)
Realized Foreign Exchange (Gain) Loss on Non-Operating Items		—	98
(Gain) Loss on Divestiture of Assets (1)	5	(119)	20
Re-measurement of Contingent Payments	23	30	59
Unwinding of Discount on Decommissioning Liabilities	24	225	220
(Income) Loss From Equity-Accounted Affiliates	18	(66)	(51)
Distributions Received From Equity-Accounted Affiliates	18	172	149
Stock-Based Compensation, Net of Payments		(145)	(12)
Other		(34)	(25)
Settlement of Decommissioning Liabilities	24	(234)	(222)
Net Change in Non-Cash Working Capital	34	1,305	(1,193)
Cash From (Used in) Operating Activities		9,235	7,388

Investing Activities
Acquisitions, Net of Cash Acquired	5	(22)	(515)
Capital Investment	1	(5,015)	(4,298)
Proceeds From Divestitures	5	46	12


Net Change in Investments and Other		(80)	(125)
Net Change in Non-Cash Working Capital	34	(55)	(369)
Cash From (Used in) Investing Activities		(5,126)	(5,295)

Net Cash Provided (Used) Before Financing Activities		4,109	2,093

Financing Activities	34
Net Issuance (Repayment) of Short-Term Borrowings		5	58

Repayment of Long-Term Debt	22	—	(1,346)

Principal Repayment of Leases	17	(299)	(288)
Common Shares Issued Under Stock Option Plans		52	46
Purchase of Common Shares Under NCIB	27	(1,445)	(1,061)
Purchase of Common Shares Under Employee Benefit Plan	27	(43)	—
Redemption of Preferred Shares	27	(250)	—
Payment for Purchase of Warrants	27	—	(711)
Proceeds From Exercise of Warrants		26	18
Dividends Paid	11	(1,551)	(1,026)




Other		—	(3)
Cash From (Used in) Financing Activities		(3,505)	(4,313)

Effect of Foreign Exchange on Cash and Cash Equivalents		262	(77)
Increase (Decrease) in Cash and Cash Equivalents		866	(2,297)
Cash and Cash Equivalents, Beginning of Year		2,227	4,524
Cash and Cash Equivalents, End of Year		3,093	2,227

(1)Revised presentation as of January 1, 2024. See Note 4.

See accompanying Notes to the Consolidated Financial Statements.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			10

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc. (“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.”).

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 the New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1, 2, 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.

The Company operates through the following reportable segments:

Upstream Segments

•Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas in Alberta and British Columbia in the Edson, Clearwater and Rainbow Lake operating areas, in addition to the Northern Corridor, which includes Elmworth and Wapiti. The segment also includes 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.

Downstream Segments

•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment also includes the jointly-owned Wood River and Borger refineries, held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.

Corporate and Eliminations


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			11

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

A) Results of Operations – Segment and Operational Information


	Upstream
	Oil Sands		Conventional		Offshore		Total
For the years ended December 31,	2024	2023	2024	2023	2024	2023	2024	2023
Gross Sales
External Sales	21,857	20,608	1,211	1,488	1,572	1,617	24,640	23,713
Intersegment Sales	6,590	5,584	1,848	1,785	—	—	8,438	7,369
	28,447	26,192	3,059	3,273	1,572	1,617	33,078	31,082
Royalties	(3,274)	(3,059)	(76)	(112)	(99)	(99)	(3,449)	(3,270)
Revenues	25,173	23,133	2,983	3,161	1,473	1,518	29,629	27,812
Expenses
Purchased Product	1,851	1,457	1,823	1,695	—	—	3,674	3,152
Transportation and Blending	11,000	10,774	320	298	11	16	11,331	11,088
Operating	2,511	2,716	555	590	423	384	3,489	3,690
Realized (Gain) Loss on Risk Management	20	17	(6)	(5)	—	—	14	12
Operating Margin	9,791	8,169	291	583	1,039	1,118	11,121	9,870
Unrealized (Gain) Loss on Risk Management	(16)	15	4	(19)	—	—	(12)	(4)
Depreciation, Depletion and Amortization	3,117	2,993	442	386	563	487	4,122	3,866
Exploration Expense	2	19	1	6	66	17	69	42
(Income) Loss From Equity- Accounted Affiliates	(14)	6	2	—	(53)	(57)	(65)	(51)
Segment Income (Loss)	6,702	5,136	(158)	210	463	671	7,007	6,017


	Downstream
	Canadian Refining		U.S. Refining		Total
For the years ended December 31,	2024	2023	2024	2023	2024	2023
Gross Sales
External Sales	4,787	5,385	28,299	26,376	33,086	31,761
Intersegment Sales	523	848	9	17	532	865
	5,310	6,233	28,308	26,393	33,618	32,626
Royalties	—	—	—	—	—	—
Revenues	5,310	6,233	28,308	26,393	33,618	32,626
Expenses
Purchased Product	4,483	4,919	25,769	23,354	30,252	28,273
Transportation and Blending	—	—	—	—	—	—
Operating	907	639	2,763	2,562	3,670	3,201
Realized (Gain) Loss on Risk Management	—	—	8	—	8	—
Operating Margin	(80)	675	(232)	477	(312)	1,152
Unrealized (Gain) Loss on Risk Management	—	—	8	(17)	8	(17)
Depreciation, Depletion and Amortization	185	185	462	486	647	671
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	(265)	490	(702)	8	(967)	498


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			12

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024


	Corporate and Eliminations		Consolidated
For the years ended December 31,	2024	2023	2024	2023
Gross Sales
External Sales	—	—	57,726	55,474
Intersegment Sales	(8,970)	(8,234)	—	—
	(8,970)	(8,234)	57,726	55,474
Royalties	—	—	(3,449)	(3,270)
Revenues	(8,970)	(8,234)	54,277	52,204
Expenses
Purchased Product	(7,823)	(6,710)	26,103	24,715
Transportation and Blending	(793)	(947)	10,538	10,141
Purchased Product, Transportation and Blending (1)	(8,616)	(7,657)	36,641	34,856
Operating	(318)	(539)	6,841	6,352
Realized (Gain) Loss on Risk Management	24	(3)	46	9
Unrealized (Gain) Loss on Risk Management	16	73	12	52
Depreciation, Depletion and Amortization	102	107	4,871	4,644
Exploration Expense	—	—	69	42

(Income) Loss From Equity-Accounted Affiliates	(1)	—	(66)	(51)
Segment Income (Loss)	(177)	(215)	5,863	6,300
General and Administrative	794	688	794	688
Finance Costs, Net (1)	514	538	514	538
Integration, Transaction and Other Costs	166	85	166	85
Foreign Exchange (Gain) Loss, Net	462	(67)	462	(67)
(Gain) Loss on Divestiture of Assets (1)	(119)	20	(119)	20
Re-measurement of Contingent Payments	30	59	30	59
Other (Income) Loss, Net	(55)	(63)	(55)	(63)
	1,792	1,260	1,792	1,260
Earnings (Loss) Before Income Tax			4,071	5,040
Income Tax Expense (Recovery)			929	931
Net Earnings (Loss)			3,142	4,109

(1)Revised presentation as of January 1, 2024. See Note 4.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			13

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

B) External Sales by Product


	Upstream
	Oil Sands		Conventional		Offshore		Total
For the years ended December 31,	2024	2023	2024	2023	2024	2023	2024	2023
Crude Oil	21,183	20,022	207	238	321	401	21,711	20,661
Natural Gas and Other	332	271	648	988	925	901	1,905	2,160
NGLs (1)	342	315	356	262	326	315	1,024	892
External Sales	21,857	20,608	1,211	1,488	1,572	1,617	24,640	23,713


	Downstream
	Canadian Refining		U.S. Refining		Total
For the years ended December 31,	2024	2023	2024	2023	2024	2023
Gasoline	429	522	13,792	12,375	14,221	12,897
Distillates (2)	1,484	1,752	10,632	9,612	12,116	11,364
Synthetic Crude Oil	1,814	1,899	—	—	1,814	1,899
Asphalt	548	537	1,029	864	1,577	1,401
Other Products and Services	512	675	2,846	3,525	3,358	4,200
External Sales	4,787	5,385	28,299	26,376	33,086	31,761

(1)Third-party condensate sales are included within NGLs.

(2)Includes diesel and jet fuel.

C) Geographical Information


	Revenues (1)

For the years ended December 31,	2024	2023
Canada	26,791	25,128
United States	26,333	25,943
China	1,153	1,133
Consolidated	54,277	52,204

(1)Revenues by country are classified based on where the operations are located.


	Non-Current Assets (1)
As at December 31,	2024	2023
Canada	37,006	35,876
United States	5,902	5,230
China	1,249	1,608
Indonesia	295	344
Consolidated	44,452	43,058

(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.

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, 2024, Cenovus had two customers (2023 – two) 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 $17.7 billion and $8.1 billion, respectively (2023 – $18.0 billion and $7.1 billion, respectively), and are reported across all of the Company’s operating segments.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			14

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

D) Assets by Segment


	E&E Assets		PP&E		ROU Assets
As at December 31,	2024	2023	2024	2023	2024	2023
Oil Sands	461	729	24,646	24,443	1,018	849
Conventional	15	—	2,230	2,209	57	1
Offshore	8	9	3,365	2,798	95	102
Canadian Refining	—	—	2,511	2,469	39	28
U.S. Refining	—	—	5,538	5,014	342	268
Corporate and Eliminations	—	—	278	317	399	432
Consolidated	484	738	38,568	37,250	1,950	1,680


	Goodwill		Total Assets
As at December 31,	2024	2023	2024	2023
Oil Sands	2,923	2,923	31,668	31,673
Conventional	—	—	2,610	2,429
Offshore	—	—	4,089	3,511
Canadian Refining	—	—	2,901	2,960
U.S. Refining	—	—	9,517	8,660
Corporate and Eliminations	—	—	5,754	4,682
Consolidated	2,923	2,923	56,539	53,915

E) Capital Expenditures (1)



For the years ended December 31,	2024	2023
Capital Investment
Oil Sands	2,714	2,382
Conventional	421	452
Offshore
Atlantic	1,077	635
Asia Pacific	68	7
Total Upstream	4,280	3,476

Canadian Refining	208	145
U.S. Refining	488	602
Total Downstream	696	747

Corporate and Eliminations	39	75
	5,015	4,298






Acquisitions
Oil Sands	9	37
Conventional	13	5


U.S. Refining (2)	—	385

	22	427

Total Capital Expenditures	5,037	4,725

(1)Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the Company's joint ventures.

(2)In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) 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 Toledo of $368 million. See Note 5.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			15

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

These Consolidated Financial Statements are presented in Canadian dollars, which is the Company's functional and presentation currency. Certain Cenovus subsidiaries operate in countries other than Canada and have functional currencies other than the Canadian dollar. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements were prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”) and interpretations of the International Financial Reporting Interpretations Committee.

These Consolidated Financial Statements were prepared on a historical cost basis, except as detailed in the Company’s accounting policies as disclosed in Note 36.

These Consolidated Financial Statements were approved by the Board of Directors effective February 19, 2025.



3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

The timely preparation of the Consolidated Financial Statements in accordance with IFRS Accounting Standards requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, 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

Identification of Cash-Generating Units

Assessment of Impairment Indicators or Impairment Reversals

Exploration and Evaluation Assets


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			16

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

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.

Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with BP Products North America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo, as defined under IFRS 10, “Consolidated Financial Statements”, and, accordingly, Toledo 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.

•WRB has third-party debt facilities to cover short-term working capital requirements.

B) Key Sources of Estimation Uncertainty

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 estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads, net of renewable identification numbers (“RINs”), and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate market expectations and the evolving worldwide demand for energy.

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 expected future production volumes, future development and operating expenses, forward commodity prices, estimated royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and depreciation, depletion and amortization (“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 independent qualified reserves evaluators (“IQREs”).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			17

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

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 quantity of reserves, expected future production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, net of RINs, future operating expenses, future capital expenditures and discount rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

Income Tax Provisions



4. UPDATES TO ACCOUNTING POLICIES

The following presentation changes were made with comparative periods being re-presented:

•Gross sales and royalties were aggregated and presented as ‘Revenues’.

•Purchased product and transportation and blending were aggregated and presented as ‘Purchased Product, Transportation and Blending’.

•Depreciation, depletion and amortization, and exploration expense were aggregated and presented as ‘Depreciation, Depletion, Amortization and Exploration Expense’.

•Finance costs and interest income were aggregated and presented as ‘Finance Costs, Net’.

•Revaluation (gain) loss and (gain) loss on divestiture of assets were aggregated and presented as ‘(Gain) Loss on Divestiture of Assets’.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			18

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



5. ACQUISITIONS AND DIVESTITURES

A) Acquisitions

i) BP-Husky Refining LLC

On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash, including cost of working capital.

The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at fair value 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 Assumed


As at						February 28, 2023
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash						69
Accounts Receivable and Accrued Revenues						3
Inventories						387
Property, Plant and Equipment						770
Right-of-Use Assets						33
Other Assets						10
Accounts Payable and Accrued Liabilities						(139)

Lease Liabilities						(33)
Decommissioning Liabilities						(5)
Other Liabilities						(73)
Total Identifiable Net Assets						1,022

iii) Goodwill


As at						February 28, 2023
Total Purchase Consideration						514
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo						508
Fair Value of Identifiable Net Assets						(1,022)
Goodwill						—

Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC

The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss in (gain) loss on divestiture of assets of $34 million ($23 million, after tax) on the re-measurement of its pre-existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign currency translation adjustments.

iv) Transaction Costs

For the year ended December 31, 2023, transaction costs of $11 million related to the Toledo Acquisition were recognized in net earnings (loss).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			19

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

B) Divestitures

The Company closed a transaction with Athabasca Oil Corporation (“Athabasca”) to create the jointly-controlled Duvernay Energy Corporation (“Duvernay”). Cenovus contributed non-monetary assets with a fair value of $94 million and cash of $18 million, before closing adjustments, in exchange for a 30 percent equity interest in Duvernay. The Company recognized an investment of $84 million in Duvernay and a before-tax gain on divestiture of assets of $65 million (after-tax gain – $50 million), reflecting the difference between the carrying value and fair value of contributed assets to the extent of Athabasca’s share.

The Company also closed the sale of non-core assets in its Conventional segment for net proceeds of $39 million and recorded a before-tax gain of $51 million (after-tax gain – $39 million).



6. GENERAL AND ADMINISTRATIVE



For the years ended December 31,	2024	2023
Salaries and Benefits	269	249
Administrative and Other	399	342
Stock-Based Compensation Expense (Recovery) (Note 29)	126	97

	794	688



7. FINANCE COSTS, NET



For the years ended December 31,	2024	2023
Interest Expense – Short-Term Borrowings and Long-Term Debt	307	362
Net Premium (Discount) on Redemption of Long-Term Debt (1)	—	(84)
Interest Expense – Lease Liabilities (Note 17)	162	161
Unwinding of Discount on Decommissioning Liabilities (Note 24)	225	220
Other	35	32
Capitalized Interest	(45)	(20)
Finance Costs	684	671
Interest Income	(170)	(133)
	514	538

(1)Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.



8. FOREIGN EXCHANGE (GAIN) LOSS, NET



For the years ended December 31,	2024	2023
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	442	(231)
Other	108	21
Unrealized Foreign Exchange (Gain) Loss	550	(210)
Realized Foreign Exchange (Gain) Loss	(88)	143
	462	(67)



9. IMPAIRMENT CHARGES AND REVERSALS

A) Upstream Cash-Generating Units

Impairment Charges

The Company tested CGUs with associated goodwill for impairment as at December 31, 2024, and 2023, and there were no impairments. No impairment indicators were identified for the remaining CGUs as at December 31, 2024, and 2023.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			20

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs with associated goodwill were estimated using fair value less costs of disposal (“FVLCOD”). Key assumptions used to estimate the present value of future net cash flows from reserves include expected future production volumes, quantity of reserves, forward commodity prices, and future development and operating expenses, all consistent with Cenovus’s IQREs, as well as discount rates. 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, 2024, and December 31, 2023. All reserves were evaluated by the Company’s IQREs as at December 31, 2024, and 2023.

Crude Oil, NGLs and Natural Gas Prices

The forward commodity prices as at December 31, 2024, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:


	2025	2026	2027	2028	2029	Average Annual Increase Thereafter (percent)
West Texas Intermediate (“WTI”) (US$/bbl) (1)	71.58	74.48	75.81	77.66	79.22	2.00
Western Canadian Select at Hardisty (2) (C$/bbl)	82.69	84.27	83.81	85.70	87.45	2.00
Condensate at Edmonton (C$/bbl)	100.14	100.72	100.24	102.73	104.79	2.00
Alberta Energy Company Natural Gas (C$/Mcf) (3)	2.36	3.33	3.48	3.69	3.76	2.00

(1)Barrel ("bbl").

(2)Western Canadian Select at Hardisty (“WCS”).

(3)One thousand cubic feet (“Mcf”).

The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:


	2024	2025	2026	2027	2028	Average Annual Increase Thereafter (percent)
WTI (US$/bbl)	73.67	74.98	76.14	77.66	79.22	2.00
WCS (C$/bbl)	76.74	79.77	81.12	82.88	85.04	2.00
Condensate at Edmonton (C$/bbl)	96.79	98.75	100.71	102.72	104.78	2.00
Alberta Energy Company Natural Gas (C$/Mcf)	2.20	3.37	4.05	4.13	4.21	2.00

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 14 percent (2023 – 14 percent).

Sensitivities

A one percent (2023 – one percent) increase in the discount rate or a five percent (2023 – five percent) decrease in forward commodity price estimates would not impact the results of the impairment tests performed.

B) Downstream Cash-Generating Units

i) 2024 Impairment Charges and Reversals

As at December 31, 2024, lower forward Chicago 3-2-1 crack spreads, net of RINs, that would result in lower margins for refined products was identified as an indicator of impairment for the Lima, Toledo and Wood River CGUs. As a result, these CGUs were tested for impairment.

The recoverable amounts of the Lima, Toledo and Wood River CGUs were in excess of their respective carrying amounts and no impairment was recorded. There were no indicators of impairment for the remaining downstream CGUs and no indicators of impairment reversal for the Superior and Borger CGUs.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			21

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

Key Assumptions

The recoverable amount (Level 3) of each of the 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 refined product production, forward crude oil prices, forward crack spreads, net of RINs, future capital expenditures, future operating costs and discount rates. Forward prices are based on third-party consultant forecasts.

Crude Oil and Select Refining Benchmark Prices

As at December 31, 2024, the forward prices used to determine future cash flows were:


(US$/bbl)	2025	2026	2027	2028	2029
WTI	77.68	77.07	78.74	81.51	83.14

Differential WTI – WCS	(14.17)	(15.34)	(15.71)	(16.62)	(17.11)
Chicago 3-2-1 Crack Spread	20.01	21.97	22.60	23.87	24.66
Renewable Identification Numbers	6.79	7.31	8.05	8.69	9.03

Subsequent estimated cash flows were determined using a pricing growth rate between one percent and six percent up to the year 2034.

Discount Rates

Discounted future cash flows were determined by applying a discount rate between 15 percent and 16 percent based on the individual characteristics of the CGU and on the economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or in forward prices would have on the impairment amount as at December 31, 2024, for the U.S. Refining CGUs:

Increase (Decrease) to Impairment Amount

One Percent Increase in

the Discount Rate

Five Percent Decrease in the Forward Prices

Lima and Wood River CGUs

214

619

For the Toledo CGU, a one percent increase in the discount rate or a five percent decrease in forward prices would not result in an impairment.

ii) 2023 Impairment Charges and Reversals

As at December 31, 2023, there were no indicators of impairment or impairment reversals for the Company's downstream CGUs.



10. INCOME TAXES

A) Income Tax Expense (Recovery)



For the years ended December 31,	2024	2023
Current Tax
Canada	1,141	1,041
United States	9	(109)
Asia Pacific	214	224
Other International	39	25
Total Current Tax Expense (Recovery)	1,403	1,181
Deferred Tax Expense (Recovery)	(474)	(250)
	929	931


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			22

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

The following table reconciles income taxes calculated at the consolidated combined federal and provincial Canadian statutory rate with the recorded income taxes:


For the years ended December 31,	2024	2023
Earnings (Loss) Before Income Tax	4,071	5,040
Canadian Statutory Rate (percent)	23.7	23.7
Expected Income Tax Expense (Recovery)	965	1,194
Effect on Taxes Resulting From:
Statutory and Other Rate Differences	(34)	(38)
Non-Taxable Capital (Gains) Losses	45	(15)
Non-Recognition of Capital (Gains) Losses	45	(30)
Adjustments Arising From Prior Year Tax Filings	(31)	(16)
Recognition of U.S. Tax Basis	(77)	(115)


Other	16	(49)
Total Tax Expense (Recovery)	929	931
Effective Tax Rate (percent)	22.8	18.5

For the year ended December 31, 2024, Pillar Two taxes did not have a material impact on net earnings. The Company is not expecting a material impact from jurisdictions where we operate that have not enacted Pillar Two legislation.

B) Deferred Income Tax Assets and Liabilities

The breakdown of deferred income tax assets and deferred income tax liabilities, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows:


As at December 31, 2024	2024	2023
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months	(29)	(315)
Deferred Income Tax Assets to be Settled After More Than Twelve Months	(1,269)	(1,174)
	(1,298)	(1,489)
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled Within Twelve Months	68	138
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months	4,211	4,843
	4,279	4,981
Net Deferred Income Tax Liability	2,981	3,492

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 assets and liabilities, without taking into consideration the offsetting of balances within the same tax jurisdiction, was:


Deferred Income Tax Assets	Unused Tax Losses	Other	Total
As at December 31, 2022	(156)	(622)	(778)
Charged (Credited) to Earnings	(777)	54	(723)

Charged (Credited) to Other Comprehensive Income	19	(7)	12
As at December 31, 2023	(914)	(575)	(1,489)
Charged (Credited) to Earnings	242	(9)	233

Charged (Credited) to Other Comprehensive Income	(66)	24	(42)
As at December 31, 2024	(738)	(560)	(1,298)


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			23

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024


Deferred Income Tax Liabilities	PP&E	Other	Total
As at December 31, 2022	4,460	55	4,515
Charged (Credited) to Earnings	495	(22)	473
Charged (Credited) to Other Comprehensive Income	(7)	—	(7)
As at December 31, 2023	4,948	33	4,981
Charged (Credited) to Earnings	(716)	9	(707)
Charged (Credited) to Other Comprehensive Income	5	—	5
As at December 31, 2024	4,237	42	4,279


Net Deferred Income Tax Liabilities			Total
As at December 31, 2022			3,737
Charged (Credited) to Earnings			(250)
Charged (Credited) to Other Comprehensive Income			5
As at December 31, 2023			3,492
Charged (Credited) to Earnings			(474)

Charged (Credited) to Other Comprehensive Income			(37)
As at December 31, 2024			2,981

The deferred income tax asset of $1.1 billion as at December 31, 2024 (December 31, 2023 – $696 million) represents net deductible temporary differences in the U.S. jurisdiction, which have been fully recognized, as the probability of realization is expected due to forecasted taxable income. No deferred tax liability was recognized as at December 31, 2024, or December 31, 2023, 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,	2024	2023
Canada	10,086	8,547
United States	9,905	8,058
Asia Pacific	351	347

	20,342	16,952

As at December 31, 2024, the above tax pools included $197 million (December 31, 2023 – $126 million) of Canadian federal non-capital losses and $3.0 billion (December 31, 2023 – $3.7 billion) of U.S. net operating losses. These losses expire no earlier than 2043.

As at December 31, 2024, the Company had Canadian net capital losses totaling $85 million (December 31, 2023 – $59 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $362 million (December 31, 2023 – $141 million) of deductible temporary differences associated with unrealized foreign exchange losses on its U.S. denominated debt.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			24

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



11. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Common Share – Basic and Diluted



For the years ended December 31,	2024	2023
Net Earnings (Loss)	3,142	4,109
Effect of Cumulative Dividends on Preferred Shares	(36)	(36)
Net Earnings (Loss) – Basic	3,106	4,073
Effect of Stock-Based Compensation	3	(12)
Net Earnings (Loss) – Diluted	3,109	4,061

Basic – Weighted Average Number of Shares (thousands)	1,850,193	1,895,487
Dilutive Effect of Warrants	4,483	22,223


Dilutive Effect of Stock-Based Compensation	8,540	22,135
Diluted – Weighted Average Number of Shares (thousands)	1,863,216	1,939,845

Net Earnings (Loss) Per Common Share – Basic ($)	1.68	2.15
Net Earnings (Loss) Per Common Share – Diluted (1) ($)	1.67	2.09

(1)For the year ended December 31, 2024, net earnings of $16 million (2023 – $nil) and 9.8 million common shares (2023 – 1.6 million), related to the assumed exercise of stock-based compensation, were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive.

B) Common Share Dividends


	2024		2023
For the years ended December 31,	Per Share	Amount	Per Share	Amount
Base Dividends	0.680	1,255	0.525	990
Variable Dividends	0.135	251	—	—
Total Common Share Dividends Declared and Paid	0.815	1,506	0.525	990

The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.

On February 19, 2025, the Company’s Board of Directors declared a first quarter base dividend of $0.180 per common share, payable on March 31, 2025, to common shareholders of record as at March 14, 2025.

C) Preferred Share Dividends


For the years ended December 31,	2024	2023
Series 1 First Preferred Shares	7	7
Series 2 First Preferred Shares	2	2
Series 3 First Preferred Shares	12	12
Series 5 First Preferred Shares	9	9
Series 7 First Preferred Shares	6	6
Total Preferred Share Dividends Declared	36	36

The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.

For the year ended December 31, 2024, the Company paid $45 million in preferred share dividends (December 31, 2023 – $36 million).

On February 19, 2025, the Company’s Board of Directors declared first quarter dividends of $6 million payable on March 31, 2025, to preferred shareholders of record as at March 14, 2025.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			25

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



12. CASH AND CASH EQUIVALENTS


As at December 31,	2024	2023
Cash	2,723	2,109
Short-Term Investments	370	118
	3,093	2,227

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.




13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES


As at December 31,	2024	2023
Trade and Accruals	2,378	2,722
Prepaids and Deposits	187	242

Joint Operations Receivables	40	49
Other	9	22
	2,614	3,035



14. INVENTORIES


As at December 31,	2024	2023
Product
Crude Oil	2,297	2,084
Diluent	401	379
Natural Gas and NGLs	77	68
Refined Products	1,176	1,073

Total Product	3,951	3,604
Parts and Supplies	545	426
	4,496	4,030

For the year ended December 31, 2024, approximately $42.8 billion of produced and purchased inventory was recorded as an expense (2023 – approximately $39.1 billion).

As at December 31, 2024, the Company had no inventory write-downs. As at December 31, 2023, the Company recorded non-cash inventory write-downs of $86 million and $3 million in refined products and crude oil inventory, respectively. The non-cash inventory write-downs were included in purchased product, transportation and blending expense.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			26

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



15. EXPLORATION AND EVALUATION ASSETS, NET


			Total
As at December 31, 2022			685
Acquisition			31
Additions			84
Transfer to PP&E (Note 16)			(60)
Write-downs			(29)
Change in Decommissioning Liabilities			28
Exchange Rate Movements and Other			(1)
As at December 31, 2023			738
Acquisition			7
Additions			65
Transfer to PP&E (Note 16)			(285)
Write-downs			(37)
Change in Decommissioning Liabilities			(5)
Exchange Rate Movements and Other			1
As at December 31, 2024			484


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			27

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



16. PROPERTY, PLANT AND EQUIPMENT, NET


	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Refining Assets	Other Assets (1)	Total
COST
As at December 31, 2022	43,528	254	12,132	1,825	57,739
Acquisitions (Note 5) (2)	11	—	770	—	781
Additions	3,392	14	719	89	4,214
Transfer from E&E (Note 15)	60	—	—	—	60
Change in Decommissioning Liabilities	542	—	21	18	581
Divestitures (Note 5) (2)	(17)	—	(633)	(17)	(667)

Exchange Rate Movements and Other	(91)	4	(239)	(7)	(333)
As at December 31, 2023	47,425	272	12,770	1,908	62,375
Acquisitions	15	—	—	—	15
Additions	4,215	3	661	71	4,950
Transfer from E&E (Note 15)	285	—	—	—	285
Change in Decommissioning Liabilities	312	2	4	(5)	313
Divestitures (Note 5)	(270)	—	—	(1)	(271)
Exchange Rate Movements and Other	108	3	890	2	1,003

As at December 31, 2024	52,090	280	14,325	1,975	68,670

ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2022	14,302	106	5,547	1,285	21,240
Depreciation, Depletion and Amortization	3,692	19	554	86	4,351
Divestitures (Note 5) (2)	(8)	—	(299)	(12)	(319)

Exchange Rate Movements and Other	(11)	4	(135)	(5)	(147)
As at December 31, 2023	17,975	129	5,667	1,354	25,125
Depreciation, Depletion and Amortization	3,949	11	539	81	4,580


Divestitures (Note 5)	(208)	—	—	—	(208)
Exchange Rate Movements and Other	133	1	469	2	605

As at December 31, 2024	21,849	141	6,675	1,437	30,102

CARRYING VALUE

As at December 31, 2023	29,450	143	7,103	554	37,250
As at December 31, 2024	30,241	139	7,650	538	38,568

(1)Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2)In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million.

Assets Under Construction

PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A:


As at December 31,	2024	2023
Crude Oil and Natural Gas Properties	3,359	2,507
Refining Assets	400	243
	3,759	2,750


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			28

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



17. LEASES

A) Right-of-Use Assets, Net


	Real Estate	Transportation and Storage Assets (1)	Refining Assets	Other Assets (2)	Total
COST
As at December 31, 2022	599	1,840	174	74	2,687
Acquisitions (Note 5) (3)	1	24	8	—	33
Additions	1	56	—	—	57




Divestitures (Note 5) (3)	—	—	(19)	—	(19)
Exchange Rate Movements and Other	(13)	44	(2)	(4)	25
As at December 31, 2023	588	1,964	161	70	2,783

Additions	2	317	—	51	370




Exchange Rate Movements and Other	2	111	17	4	134

As at December 31, 2024	592	2,392	178	125	3,287

ACCUMULATED DEPRECIATION
As at December 31, 2022	127	645	58	12	842
Depreciation	36	223	22	12	293
Divestitures (Note 5) (3)	—	—	(12)	—	(12)


Exchange Rate Movements and Other	(7)	(5)	(3)	(5)	(20)
As at December 31, 2023	156	863	65	19	1,103
Depreciation	35	198	21	37	291


Exchange Rate Movements and Other	2	(62)	8	(5)	(57)

As at December 31, 2024	193	999	94	51	1,337

CARRYING VALUE

As at December 31, 2023	432	1,101	96	51	1,680
As at December 31, 2024	399	1,393	84	74	1,950

(1)Includes a pipeline, storage tanks, railcars, vessels, barges, a natural gas processing plant and caverns.

(2)Includes assets in the commercial fuels business, fleet vehicles, camps and other equipment.

(3)In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million.

B) Lease Liabilities


	2024	2023
Lease Liabilities, Beginning of Year	2,658	2,836
Acquisitions (Note 5) (1)	—	33
Additions	363	57
Interest Expense (Note 7)	162	161
Lease Payments	(461)	(449)


Divestitures (Note 5) (1)	—	(11)


Exchange Rate Movements and Other	205	31
Lease Liabilities, End of Year	2,927	2,658
Less: Current Portion	359	299
Long-Term Portion	2,568	2,359

(1)In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million.

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. 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. – 2024 Consolidated Financial Statements			29

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



18. JOINT ARRANGEMENTS

A) Joint Operations

Cenovus has a number of joint operations in the Upstream segments. As at December 31, 2024, the Company also has a 50 percent interest in WRB in the U.S. Refining segment. 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.

As at December 31, 2024, Toledo is 100 percent controlled by Cenovus and has been consolidated. Refer to Note 5 for more information on this transaction.

B) Joint Ventures

Husky-CNOOC Madura Ltd.

The Company holds a 40 percent interest in the jointly-controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture is recorded in (income) loss from equity-accounted affiliates.

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations


For the years ended December 31,	2024	2023
Revenue	736	615
Expenses	605	545
Net Earnings (Loss)	131	70

Balance Sheet


As at December 31,	2024	2023
Current Assets (1)	441	334
Non-Current Assets	1,594	1,751
Current Liabilities	188	140
Non-Current Liabilities	1,046	1,188
Net Assets	801	757

(1)Includes cash and cash equivalents of $108 million (December 31, 2023 – $111 million).

For the year ended December 31, 2024, the Company’s share of income from the equity-accounted affiliate was $53 million (2023 – $57 million). As at December 31, 2024, the carrying amount of the Company’s share of net assets was $294 million (December 31, 2023 – $344 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, 2024, the Company received $107 million in distributions from HCML (2023 – $93 million) and paid $nil in contributions (2023 – $35 million).

Other Joint Ventures

The Company has interests in a number of individually immaterial joint ventures, which include HMLP and Duvernay. The Company’s aggregate share of equity investment income (loss) related to these joint ventures are recorded in (income) loss from equity-accounted affiliates.

Summarized aggregate financial information is shown below:


For the years ended December 31,	2024	2023

Cenovus's Share of Net Earnings (Loss)	(16)	(1)
Cenovus's Share of Other Comprehensive Income (Loss)	(2)	(2)
Cenovus's Share of Total Other Comprehensive Income (Loss)	(18)	(3)

As at December 31, 2024, the aggregate carrying value of the Company's investment in these joint ventures was $105 million (December 31, 2023 – $22 million).

For the year ended December 31, 2024, the Company received $65 million in distributions from HMLP (2023 – $56 million) and paid $51 million in contributions (2023 – $62 million).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			30

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



19. OTHER ASSETS


As at December 31,	2024	2023
Private Equity Investments (Note 32)	219	131
Precious Metals	92	76
Long-Term Receivables and Prepaids	68	50
Net Investment in Finance Leases	61	61
Intangible Assets	11	—
	451	318



20. GOODWILL

For the years ended December 31, 2024, and December 31, 2023, no additions, disposals or impairments of goodwill were recognized.

The carrying amount of goodwill is allocated to the following CGUs:


As at December 31,	2024	2023
Primrose (Foster Creek)	1,171	1,171
Christina Lake	1,101	1,101
Lloydminster Thermal	651	651

	2,923	2,923



21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES


As at December 31,	2024	2023
Accruals	4,902	3,931
Trade	1,005	1,075
Joint Operations Payable	110	75
Employee Long-Term Incentives	132	284
Interest	72	69


Provisions for Onerous and Unfavourable Contracts	11	18
Other	10	28
	6,242	5,480



22. DEBT AND CAPITAL STRUCTURE

For the year ended December 31, 2024, the annualized weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings, was 4.5 percent (2023 – 4.7 percent).

A) Short-Term Borrowings


As at December 31,	Notes	2024	2023
Uncommitted Demand Facilities	i	—	—

WRB Uncommitted Demand Facilities	ii	173	179
Total Debt Principal		173	179

i) Uncommitted Demand Facilities

As at December 31, 2024, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2023 – $1.7 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, 2024, there were outstanding letters of credit aggregating to $355 million (December 31, 2023 – $364 million) and no direct borrowings (December 31, 2023 – $nil).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			31

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

ii) WRB Uncommitted Demand Facilities

WRB has uncommitted demand facilities of US$450 million (December 31, 2023 – US$450 million) that may be used to cover short-term working capital requirements, of which Cenovus’s proportionate share is 50 percent. As at December 31, 2024, US$240 million was drawn on these facilities, of which Cenovus’s proportionate share was US$120 million (C$173 million). As at December 31, 2023, Cenovus's proportionate share of drawings was US$135 million (C$179 million).

B) Long-Term Debt


As at December 31,	Notes	2024	2023
Committed Credit Facility	i	—	—
U.S. Dollar Denominated Unsecured Notes	ii	5,470	5,028
Canadian Dollar Unsecured Notes	ii	2,000	2,000
Total Debt Principal		7,470	7,028
Debt Premiums (Discounts), Net, and Transaction Costs		64	80
Long-Term Debt		7,534	7,108
Less: Current Portion		192	—
Long-Term Portion		7,342	7,108

i) Committed Credit Facility

On June 26, 2024, Cenovus renewed its existing committed credit facility to extend the maturity dates by more than one year. The committed credit facility consists of a $2.2 billion tranche maturing on June 26, 2027, and a $3.3 billion tranche maturing on June 26, 2028. As at December 31, 2024, no amount was drawn on the credit facility (December 31, 2023 – $nil).

The committed credit facility may include Canadian overnight repo rate average loans, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

ii) U.S. Dollar Denominated and Canadian Dollar Denominated Unsecured Notes

The principal amounts of the Company’s outstanding unsecured notes are:


	2024		2023
As at December 31,	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Denominated Unsecured Notes




5.38% due July 15, 2025	133	192	133	176
4.25% due April 15, 2027	373	537	373	493
4.40% due April 15, 2029	183	262	183	241
2.65% due January 15, 2032	500	720	500	661
5.25% due June 15, 2037	333	479	333	441
6.80% due September 15, 2037	191	275	191	253
6.75% due November 15, 2039	652	938	652	862
4.45% due September 15, 2042	91	131	91	121
5.20% due September 15, 2043	27	39	27	36
5.40% due June 15, 2047	569	818	569	752
3.75% due February 15, 2052	750	1,079	750	992
	3,802	5,470	3,802	5,028
Canadian Dollar Unsecured Notes

3.60% due March 10, 2027		750		750
3.50% due February 7, 2028		1,250		1,250
		2,000		2,000
Total Unsecured Notes		7,470		7,028

For the year ended December 31, 2023, the Company purchased US$1.0 billion in principal of its outstanding unsecured notes.

As at December 31, 2024, 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 agreement, not to exceed 65 percent. The Company is below this limit.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			32

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

C) Mandatory Debt Payments


	U.S. Dollar Unsecured Notes		Canadian Dollar Unsecured Notes	Total
As at December 31, 2024	US$ Principal	C$ Principal Equivalent	C$ Principal	C$ Principal and Equivalent
2025	133	192	—	192
2026	—	—	—	—
2027	373	537	750	1,287
2028	—	—	1,250	1,250
2029	183	262	—	262
Thereafter	3,113	4,479	—	4,479
	3,802	5,470	2,000	7,470

D) Capital Structure

Cenovus’s capital structure consists of shareholders’ equity and 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, steward working capital, 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, 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.

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 $4.0 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 or the strengthening or weakening of the Canadian dollar relative to the U.S. dollar.

On November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			33

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

Net Debt to Adjusted EBITDA


As at December 31,	2024	2023
Short-Term Borrowings	173	179
Current Portion of Long-Term Debt	192	—
Long-Term Portion of Long-Term Debt	7,342	7,108
Total Debt	7,707	7,287
Less: Cash and Cash Equivalents	(3,093)	(2,227)
Net Debt	4,614	5,060

Net Earnings (Loss)	3,142	4,109
Add (Deduct):
Finance Costs, Net (1)	514	538
Income Tax Expense (Recovery)	929	931
Depreciation, Depletion and Amortization	4,871	4,644
Exploration and Evaluation Asset Write-downs	37	29
(Income) Loss From Equity-Accounted Affiliates	(66)	(51)
Unrealized (Gain) Loss on Risk Management	12	52
Foreign Exchange (Gain) Loss, Net	462	(67)
(Gain) Loss on Divestiture of Assets (1)	(119)	20
Re-measurement of Contingent Payments	30	59
Other (Income) Loss, Net	(55)	(63)
Adjusted EBITDA (2)	9,757	10,201

Net Debt to Adjusted EBITDA (times)	0.5	0.5

(1)Revised presentation as of January 1, 2024. See Note 4.

(2)Calculated on a trailing twelve-month basis.

Net Debt to Adjusted Funds Flow


As at December 31,	2024	2023
Net Debt	4,614	5,060

Cash From (Used in) Operating Activities	9,235	7,388
(Add) Deduct:
Settlement of Decommissioning Liabilities	(234)	(222)
Net Change in Non-Cash Working Capital	1,305	(1,193)
Adjusted Funds Flow (1)	8,164	8,803

Net Debt to Adjusted Funds Flow (times)	0.6	0.6

(1)Calculated on a trailing twelve-month basis.

Net Debt to Capitalization


As at December 31,	2024	2023
Net Debt	4,614	5,060
Shareholders’ Equity	29,754	28,698
Capitalization	34,368	33,758

Net Debt to Capitalization (percent)	13	15


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			34

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



23. CONTINGENT PAYMENTS

In connection with the transaction with BP Canada Energy Group ULC (“bp Canada”) to purchase the remaining 50 percent interest in Sunrise Oil Sands Partnership (“SOSP”) (the “Sunrise Acquisition”), 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 price in a quarter exceeded $52.00 per barrel. The quarterly payment was 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 was equal to or greater than $52.00 per barrel. If the average WCS price was less than $52.00 per barrel, no payment would be made for that quarter. On August 31, 2024, the variable payment obligation ended.

In the year ended December 31, 2024, the Company made payments of $301 million for the quarterly payment periods ending November 30, 2023, February 29, 2024, May 31, 2024, and August 31, 2024.


	2024	2023
Contingent Payments, Beginning of Year	164	419

Liabilities Settled or Payable	(194)	(314)
Re-measurement	30	59
Contingent Payments, End of Year	—	164



24. DECOMMISSIONING LIABILITIES


	2024	2023
Decommissioning Liabilities, Beginning of Year	4,155	3,559
Liabilities Incurred	24	14
Liabilities Acquired (Note 5) (1)	—	5
Liabilities Settled	(234)	(221)

Liabilities Disposed (Note 5) (1)	(72)	(5)
Change in Estimated Future Cash Flows	276	330
Change in Discount Rates	132	265
Unwinding of Discount on Decommissioning Liabilities (Note 7)	225	220

Exchange Rate Movements and Other	28	(12)
Decommissioning Liabilities, End of Year	4,534	4,155

As at December 31, 2024, the undiscounted amount of estimated future cash flows required to settle the obligation is $15.6 billion (December 31, 2023 – $15.0 billion). Most of these obligations are not expected to be paid for several years, or decades, and will be funded through general resources when they become due. The Company plans to settle approximately $203 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 were discounted using a credit-adjusted risk-free rate of 5.2 percent (December 31, 2023 – 5.5 percent) and assumes an inflation rate of two percent (December 31, 2023 – 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, 2024, the Company had $241 million in long-term restricted cash (December 31, 2023 – $211 million).

Sensitivities

Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:


	Sensitivity	2024		2023
As at December 31,	Range	Increase	Decrease	Increase	Decrease
Credit-Adjusted Risk-Free Rate	± one percent	(487)	595	(387)	515
Inflation Rate	± one percent	615	(507)	519	(392)


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			35

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



25. OTHER LIABILITIES


As at December 31,	2024	2023
Renewable Volume Obligation, Net (1)	284	397
Pension and Other Post-Employment Benefit Plan	269	276
Employee Long-Term Incentives	96	100
Provisions for Onerous and Unfavourable Contracts	66	72
Provision for West White Rose Expansion Project (2)	54	156
Drilling Provisions	3	25


Other	147	157
	919	1,183

(1)The gross amounts of the renewable volume obligation (“RVO”) and RINs asset were $652 million and $368 million, respectively (December 31, 2023 – $785 million and $388 million, respectively).

(2)Cenovus expects to draw down the provision by $54 million in the next 12 months.



26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS

The Company provides the majority of employees with a defined contribution pension plan (“DC Pension Plan”). The Company also provides other post-employment benefit (“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 a small group of 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 actuarial valuations of its registered defined benefit pension plans with regulators on a periodic basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2023, and the next required actuarial valuation will be as at December 31, 2026. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2024, and the next required actuarial valuation will be dated January 1, 2025.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			36

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

A) Plan Obligations, Assets and Funded Status


	DB Pension Plan		OPEB Plans
	2024	2023	2024	2023
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year	202	172	249	174

Current Service Costs	14	10	2	14
Past Service Costs - Curtailment and Plan Amendments	—	—	—	10
Interest Costs (1)	9	9	12	10
Benefits Paid	(12)	(8)	(9)	(9)
Plan Participant Contributions	3	3	—	—
Re-measurements:
(Gains) Losses From Experience Adjustments	—	4	1	1

(Gains) Losses From Changes in Financial Assumptions	(3)	13	(6)	50
Exchange Rate Movements and Other	1	(1)	3	(1)
Defined Benefit Obligation, End of Year	214	202	252	249

Plan Assets
Fair Value of Plan Assets, Beginning of Year	178	147	—	—

Employer Contributions	11	18	9	9
Plan Participant Contributions	3	3	—	—
Benefits Paid	(12)	(7)	(9)	(9)
Interest Income (1)	8	8	—	—
Re-measurements:
Return on Plan Assets Excluding Interest Income	11	10	—	—
Exchange Rate Movements and Other	2	(1)	—	—
Fair Value of Plan Assets, End of Year	201	178	—	—

Defined Benefit Pension and OPEB Asset (Liability) (2)	(13)	(24)	(252)	(249)

(1)Based on the discount rate of the defined benefit obligation at the beginning of the year.

(2)Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities.

The weighted average duration of the obligations for the DB Pension Plan and OPEB plans are 16 years and 14 years, respectively.

B) Costs


	DB Pension Plan and DC Pension Plan		OPEB Plans
For the years ended December 31,	2024	2023		2024	2023
Defined Benefit Plan Cost
Current Service Costs	14	10		2	14
Past Service Costs – Curtailments and Plan Amendments	—	—		—	10
Net Interest Costs	1	1		12	10
Re-measurements:
Return on Plan Assets Excluding Interest Income	(11)	(10)		—	—
(Gains) Losses From Experience Adjustments	—	4		1	1

(Gains) Losses From Changes in Financial Assumptions	(3)	13		(6)	50
Defined Benefit Plan Cost (Recovery)	1	18		9	85
Defined Contribution Plan Cost (1)	107	99		—	—
Total Plan Cost	108	117		9	85

(1)Includes defined contribution and U.S. 401(k) plans.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			37

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

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 that 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. 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, as represented by fair value hierarchy levels are as follows:


As at December 31,	2024	2023
Level 1 – Cash and Cash Equivalents	3	5
Level 2 – Equity and Fixed Income Funds	185	161
Level 3 – Real Estate Funds and Other	13	12
	201	178

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 the direction of the Management Pension Committees 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, 2025, the Company expects to contribute $12 million to the DB Pension Plan.

The OPEB plans are funded on an as required basis. For the year ended December 31, 2025, the Company expects to contribute $12 million to the OPEB plans.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

The principal weighted average actuarial assumptions used to determine benefit obligations are as follows:


	Defined Benefit Plan		OPEB Plans
For the years ended December 31,	2024	2023		2024	2023
Discount Rate (percent)	4.65	4.58		4.85	4.65
Future Salary Growth Rate (percent)	3.95	4.00		N/A	N/A
Average Longevity (years)	88.4	88.4		88.4	88.4
Health Care Cost Trend Rate (percent)	N/A	N/A		5.24	5.24

Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			38

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

Sensitivities

The sensitivity of the DB Pension Plan and OPEB plan obligations to a one percent change in future salary growth rate, health care cost trend rate, or a one year change in assumed life expectancy is nominal. A one percent change in discount rate, while holding all other assumptions constant, would result in a sensitivity to change as follows:


	2024		2023
As at December 31,	Increase	Decrease	Increase	Decrease

Discount Rate	(56)	69	(54)	66

Actual experience may result in a number of assumptions changing simultaneously, and the changes in some assumptions may be correlated. When calculating the sensitivity of the DB Pension Plan and the OPEB plan obligations to significant actuarial assumptions, the same methodologies have been applied as when valuing the obligations to be recognized on the Consolidated Balance Sheets.



27. 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


	2024		2023
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	1,871,868	16,031	1,909,190	16,320

Issued Upon Exercise of Warrants	3,982	39	2,610	26
Issued Under Stock Option Plans	5,049	68	3,679	58
Purchase of Common Shares under NCIB	(55,861)	(479)	(43,611)	(373)
Outstanding, End of Year	1,825,038	15,659	1,871,868	16,031

As at December 31, 2024, there were 48.8 million (December 31, 2023 – 45.5 million) common shares available for future issuance under the stock option plan.

C) Normal Course Issuer Bid

For the year ended December 31, 2024, the Company purchased and cancelled 55.9 million common shares (2023 – 43.6 million) through the NCIB. The shares were purchased at a volume weighted average price of $25.38 per common share (2023 – $24.32) for a total of $1.4 billion (2023 – $1.1 billion). Paid in surplus was reduced by $966 million (2023 – $688 million), representing the excess of the purchase price of the common shares over their average carrying value of $939 million (2023 – $688 million) and taxes paid of $27 million (2023 – $nil).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			39

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

D) Treasury Shares

In 2024, Cenovus established an employee benefit plan trust (the “Trust”). The Trust, through an independent trustee, acquires Cenovus’s common shares on the open market, which are held to satisfy the Company’s obligations under certain stock-based compensation plans.


	2024
	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	—	—
Purchase of Common Shares Under Employee Benefit Plan	2,000	43


Outstanding, End of Year	2,000	43

E) Issued and Outstanding – Preferred Shares

First Preferred Shares


	2024		2023
	Number of Preferred Shares (thousands)	Amount	Number of Preferred Shares (thousands)	Amount
Outstanding, Beginning of Year	36,000	519	36,000	519
Preferred Shares Redeemed	(10,000)	(163)	—	—
Outstanding, End of Year	26,000	356	36,000	519

On December 31, 2024, Cenovus exercised its right to redeem all 10.0 million of the Company’s series 3 preferred shares at a price of $25.00 per share, for a total of $250 million. Paid in surplus was reduced by $87 million, representing the excess of the purchase price of the series 3 preferred shares over their carrying value.

The Company had the following preferred shares outstanding as at December 31, 2024:


As at December 31, 2024	Dividend Reset Date	Dividend Rate (percent)	Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	10,740
Series 2 First Preferred Shares (1)	Quarterly	5.21	1,260

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 6.77 percent from December 31, 2023, to March 30, 2024 (December 31, 2022, to March 30, 2023 – 5.86 percent); 6.71 percent from March 31, 2024, to June 29, 2024 (March 31, 2023, to June 29, 2023 – 6.29 percent); 6.60 percent from June 30, 2024, to September 29, 2024 (June 30, 2023, to September 29, 2023 – 6.29 percent); and 5.94 percent from September 30, 2024, to December 30, 2024 (September 30, 2023, to December 30, 2023 – 6.89 percent).

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 should the Company elect to not redeem the 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 March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares (if any) 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 (if any) 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 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), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, 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), 3.57 percent (series 6) and 3.52 percent (series 8).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			40

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

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.

Second Preferred Shares

There were no second preferred shares outstanding as at December 31, 2024 (December 31, 2023 – nil).

F) Issued and Outstanding – Warrants


	2024		2023
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	7,625	25	55,720	184

Exercised	(3,982)	(13)	(2,610)	(8)
Purchased and Cancelled	—	—	(45,485)	(151)
Outstanding, End of Year	3,643	12	7,625	25

The exercise price of the warrants is $6.54 per share. The warrants expire on January 1, 2026.

On June 14, 2023, Cenovus purchased and cancelled 45.5 million warrants. The price for each warrant purchased represented a price of $22.18 per common share, less the warrant exercise price, for a total of $711 million. Retained earnings was reduced by $560 million, representing the excess of the purchase price of the warrants over their average carrying value, and $2 million in transaction costs.

G) 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 the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIB, the excess or deficiency of treasury shares over their average carrying value to settle the employee long-term incentive (“LTI”) liability, and stock-based compensation expense related to the Company’s net settlement rights (“NSRs”) discussed in Note 29.


	Retained Earnings Prior to Ovintiv Split	Stock-Based Compensation	Total
As at December 31, 2022	2,395	296	2,691
Stock-Based Compensation Expense	—	11	11
Purchase of Common Shares Under NCIB	(688)	—	(688)
Common Shares Issued on Exercise of Stock Options	—	(12)	(12)
As at December 31, 2023	1,707	295	2,002
Stock-Based Compensation Expense	—	11	11
Purchase of Common Shares Under NCIB	(966)	—	(966)
Preferred Shares Redeemed	(87)	—	(87)

Common Shares Issued on Exercise of Stock Options	—	(16)	(16)
As at December 31, 2024	654	290	944


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			41

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)


	Pension and Other Post-Retirement Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
As at December 31, 2022	99	29	1,342	1,470
Other Comprehensive Income (Loss), Before Tax	(58)	63	(286)	(281)
Reclassification on Divestiture (Note 5)	—	—	12	12
Income Tax (Expense) Recovery	14	(7)	—	7
As at December 31, 2023	55	85	1,068	1,208
Other Comprehensive Income (Loss), Before Tax	19	81	1,020	1,120

Income Tax (Expense) Recovery	(5)	(10)	—	(15)
As at December 31, 2024	69	156	2,088	2,313



29. STOCK-BASED COMPENSATION PLANS

Cenovus has a number of stock-based compensation plans that include NSRs, Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”).

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 NSR, 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 of the underlying option.

Stock Options With Associated Net Settlement Rights

The weighted average unit fair value of NSRs granted during the year ended December 31, 2024, was $5.20 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 (percent)			3.51
Expected Dividend Yield (percent)			2.37
Expected Volatility (1) (percent)			23.64
Expected Life (years)			5.39

(1)Expected volatility has been based on historical share volatility of the Company.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			42

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

For the year ended December 31, 2024, 793 thousand NSRs, with a weighted average exercise price of $11.97, were exercised and settled for 562 thousand common shares.


	Number of Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
For the year ended December 31, 2024	(thousands)	($/unit)
Outstanding, Beginning of Year	11,895	13.66
Granted	2,427	23.90
Exercised	(5,251)	10.77
Forfeited	(416)	23.16
Expired	(2)	24.60
Outstanding, End of Year	8,653	17.83


	Outstanding			Exercisable
As at December 31, 2024	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 ($/unit)	(thousands)	(years)	($/unit)	(thousands)	($/unit)
5.00 to 9.99	1,486	2.47	8.87	1,486	8.87
10.00 to 14.99	2,004	2.08	11.70	1,902	11.69
15.00 to 19.99	1,560	4.13	19.88	902	19.88
20.00 to 24.99	3,373	5.75	23.84	448	24.14
25.00 to 29.99	230	6.46	27.21	3	27.71

	8,653	4.06	17.83	4,741	13.55

Cenovus Replacement Stock Options

For the year ended December 31, 2024, 577 thousand Cenovus replacement stock options, with a weighted average exercise price of $7.48, were exercised and net settled for cash and 37 thousand Cenovus replacement stock options were exercised with a weighted average price of $5.17 and settled for 29 thousand common shares.

The Company recorded a liability of $5 million as at December 31, 2024, (December 31, 2023 – $12 million) for Cenovus replacement stock options based on the fair value at year end using the Black-Scholes-Merton valuation model.

As at December 31, 2024, there were 348 thousand outstanding and exercisable Cenovus replacement stock options, with a remaining life of 0.47 years and a weighted average exercise price of $3.54.


	Number of Cenovus Replacement Stock Options	Weighted Average Exercise Price
For the year ended December 31, 2024	(thousands)	($/unit)
Outstanding, Beginning of Year	1,005	6.49

Exercised	(614)	7.34

Expired	(43)	18.35
Outstanding, End of Year	348	3.54

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. The 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. PSUs granted under the Performance Share Unit Plan for Local Employees in the Asia Pacific region may only be settled in cash.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			43

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

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 $80 million as at December 31, 2024, (December 31, 2023 – $238 million) 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, 2024.


			Number of Performance Share Units
For the year ended December 31, 2024			(thousands)
Outstanding, Beginning of Year			10,243
Granted			6,368
Vested and Paid Out			(8,903)
Forfeited			(742)
Units Granted in Lieu of Base Dividends			244
Outstanding, End of Year			7,210

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 vest over three years. RSUs granted under the Performance Share Unit Plan for Local Employees in the Asia Pacific region may only be settled in cash.

The Company recorded a liability of $105 million as at December 31, 2024, (December 31, 2023 – $97 million) 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, 2024.


			Number of Restricted Share Units
For the year ended December 31, 2024			(thousands)
Outstanding, Beginning of Year			7,234
Granted			3,393
Vested and Paid Out			(2,286)
Forfeited			(466)
Units Granted in Lieu of Base Dividends			273
Outstanding, End of Year			8,148

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 settled in cash and 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 $38 million as at December 31, 2024 (December 31, 2023 – $37 million) 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.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			44

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024


			Number of Deferred Share Units
For the year ended December 31, 2024			(thousands)
Outstanding, Beginning of Year			1,691
Granted to Directors			126
Granted			72
Units Granted in Lieu of Dividends			58
Redeemed			(186)
Outstanding, End of Year			1,761

E) Total Stock-Based Compensation


For the years ended December 31,	2024	2023
Stock Options With Associated Net Settlement Rights	12	11
Cenovus Replacement Stock Options	1	(5)
Performance Share Units	48	47
Restricted Share Units	60	46
Deferred Share Units	5	(2)
Total Stock-Based Compensation Expense (Recovery)	126	97



30. EMPLOYEE SALARIES AND BENEFIT EXPENSES


For the years ended December 31,	2024	2023
Salaries, Bonuses and Other Short-Term Employee Benefits	1,526	1,344
Pension and Post-Employment Benefits	119	125
Stock-Based Compensation (Note 29)	126	97

Termination Benefits	41	14
	1,812	1,580



31. 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,	2024	2023
Salaries, Director Fees and Other Short-Term Benefits	47	40
Pension and Post-Employment Benefits	4	3
Stock-Based Compensation	48	40

Termination Benefits	11	—
	110	83

B) Other Related Party Transactions

The Company charges HMLP for construction and management services and incurs costs for the use of HMLP’s pipeline systems, as well as transportation and storage services. Access fees and transportation and storage services are based on contractually agreed rates with HMLP.

The following table summarizes revenues and associated expenses related to HMLP:


For the years ended December 31,	2024	2023
Revenues from Construction and Management Services	155	160
Transportation Expenses	278	295


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			45

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024



32. 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, certain portions of other assets and other liabilities, 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 debt was determined based on period-end trading prices of long-term debt on the secondary market (Level 2). As at December 31, 2024, the carrying value of Cenovus’s long-term debt was $7.5 billion and the fair value was $6.9 billion (December 31, 2023 carrying value – $7.1 billion, fair value – $6.6 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 in other assets. Fair value is determined based on recent market activity which may include equity transactions of the entity when available (Level 3).

The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:


	2024	2023
Fair Value, Beginning of Year	131	55
Acquisitions	7	13
Changes in Fair Value	81	63
Fair Value, End of Year	219	131

B) Fair Value of Risk Management Assets and Liabilities

Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable and accrued liabilities (for short-term positions), other assets and other liabilities (for long-term positions). Changes in fair value are recorded in (gain) loss on risk management.

The Company’s risk management assets and liabilities consist of condensate and refined product futures; crude oil and natural gas futures and swaps; and renewable power, power and foreign exchange contracts. The Company may also enter into forwards and options to manage commodity, foreign exchange and interest rate exposures.

Crude oil, natural gas, condensate, refined products and power contracts 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 is calculated using external valuation models that incorporate observable market data and foreign exchange forward curves (Level 2).

The fair value of renewable power contracts is 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, which consists of individuals who are knowledgeable and have experience in fair value techniques.

Summary of Risk Management Positions


	2024			2023
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	9	10	(1)	11	19	(8)
Power Contracts	6	—	6	2	—	2
Renewable Power Contracts	5	—	5	18	—	18
Foreign Exchange Rate Contracts	—	3	(3)	—	—	—
	20	13	7	31	19	12


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			46

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:


As at December 31,	2024	2023
Level 2 – Prices Sourced From Observable Data or Market Corroboration	2	(6)
Level 3 – Prices Sourced From Partially Unobservable Data	5	18
	7	12

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:


	2024	2023
Fair Value of Contracts, Beginning of Year	12	46

Change in Fair Value of Contracts in Place at Beginning of Year	(20)	—
Change in Fair Value of Contracts Entered Into During the Year	(30)	(45)
Fair Value of Contracts Realized During the Year	46	9
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	(1)	2
Fair Value of Contracts, End of Year	7	12

Offsetting Financial Assets and Liabilities

Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same.


	2024			2023
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	38	31	7	71	59	12
Amount Offset	(18)	(18)	—	(40)	(40)	—
Net Amount	20	13	7	31	19	12

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, 2024, $18 million was pledged as cash collateral (December 31, 2023 – $47 million).

C) Earnings Impact of (Gains) Losses From Risk Management Positions


For the years ended December 31,	2024	2023
Realized (Gain) Loss	46	9
Unrealized (Gain) Loss	12	52
(Gain) Loss on Risk Management	58	61

Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

D) Fair Value of Contingent Payments

i) 2024 Fair Value

The variable payment (Level 3) associated with the transaction with the Sunrise Acquisition ended on August 31, 2024. The final payment was made in October 2024.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			47

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

ii) 2023 Fair Value

The variable payment (Level 3) associated with the Sunrise Acquisition was carried at fair value in the contingent payments. Fair value was estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumed 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 that was discounted using a credit-adjusted risk-free rate. Fair value of the variable payment was 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, 2023, the fair value of the variable payment was estimated to be $164 million applying a credit-adjusted risk-free rate of 5.6 percent.

As at December 31, 2023, average WCS forward pricing for the remaining term of the variable payment was $71.86 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 39.4 percent and 5.8 percent, respectively.

As at December 31, 2023, changes in WCS forward prices, with fluctuations in all other variables held constant, could have impacted earnings before income tax as follows:

Sensitivity Range

Increase

Decrease

WCS Forward Prices

± $10.00 per barrel

(21)



33. 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, such as renewable power contracts or power swaps, to manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions.

To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts.

As at December 31, 2024, the fair value of risk management positions was a net asset of $7 million (see Note 32). As at December 31, 2024, there were foreign exchange contracts with a notional value of US$250 million and no interest rate contracts or cross currency interest rate swap contracts outstanding. As at December 31, 2023, there were no forward exchange contracts, interest rate contracts or cross currency interest rate swap contacts outstanding.

Net Fair Value of Risk Management Positions

As at December 31, 2024

Notional Volumes (1) (2)

Terms (3)

Weighted

Average

Price (2)

Fair Value Asset (Liability)

WTI Contracts Related to Blending (4)

WTI Fixed – Sell

1.6 MMbbls

January 2025 - November 2025

US$70.18/bbl

(3)

WTI Fixed – Buy

0.3 MMbbls

January 2025 - November 2025

US$72.80/bbl

(1)

Power Contacts

Renewable Power Contracts

Other Financial Positions (5)

Foreign Exchange Rate Contracts

(3)

Total Fair Value

(1)Million barrels ("MMbbls").

(2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month.

(3) Includes individual contracts with varying terms, the longest of which is 14 months.

(4) WTI contracts related to blending are used to help manage price exposure to condensate used for blending.

(5) Includes risk management positions related to WCS, heavy oil, light oil and condensate differentials, benchmark delivery location spreads, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts and the Company’s U.S. refining and marketing activities.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			48

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

A) Commodity Price and Foreign Exchange 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, condensate, refined product and power risk management contracts, and may enter into options, forward or swaps. In addition, various crude oil, natural gas and condensate basis contracts for both price and location may be used. These derivative instruments are used to partially mitigate exposure to the commodity price risk on its crude oil and condensate transactions 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 8). As at December 31, 2024, Cenovus had US$3.8 billion in U.S. dollar debt (December 31, 2023 – US$3.8 billion).

iii) Commodity Price and Foreign Exchange Rate Sensitivities

The following tables summarize 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 tables 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, 2024	Sensitivity Range	Increase	Decrease
Crude Oil and Condensate Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	—	—
Crude Oil and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	20	(20)
WCS (Hardisty) Differential Price	± US$2.50/bbl Applied to WCS Differential Hedges Tied to Production	(6)	6
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(3)	3
Natural Gas Commodity Price	± US$0.50/Mcf Applied to Natural Gas Hedges Tied to Production	—	—
Natural Gas Basis Price	± US$0.25/Mcf Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$10.00/MWh (2) Applied to Power Hedges	46	(46)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	24	(28)

(1)Excluding WCS at Hardisty.

(2)One thousand kilowatts of electricity per hour (“MWh”).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			49

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024


As at December 31, 2023	Sensitivity Range	Increase	Decrease
Crude Oil and Condensate Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	(1)	1
Crude Oil and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	(4)	4
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tie to Production	—	—
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(3)	3
Natural Gas Commodity Price	± $1.00/Mcf Applied to Natural Gas Hedges Tied to Production	—	—
Natural Gas Basis Price	± US$0.50/Mcf Applied to Natural Gas Basis Hedges	—	—
Power Commodity Price	± C$20.00/MWh Applied to Power Hedges	92	(92)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	—	—

(1)Excluding WCS at Hardisty.

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,	2024	2023
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate	196	197
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate	(196)	(197)

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, 2024, approximately 79 percent (December 31, 2023 – 83 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 96 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss (“ECL”) on these accounts was 0.4 percent as at December 31, 2024 (December 31, 2023 – 0.4 percent).

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.

As disclosed in Note 22, 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 a WTI price of US$45.00 per barrel to manage the Company’s overall debt position.

As at December 31, 2024, the Company’s sources of capital included:

•$3.1 billion in cash and cash equivalents.

•$5.5 billion available on its committed credit facility.

•$1.3 billion available on its uncommitted demand facilities, of which $1.1 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit.

•US$105 million (C$151 million) on the Company’s proportionate share of the uncommitted demand facilities from WRB.

•The base shelf prospectus, availability of which is dependent on market conditions.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			50

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

Undiscounted cash outflows relating to financial liabilities are:


As at December 31, 2024	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,242	—	—	—	6,242
Short-Term Borrowings	173	—	—	—	173

Lease Liabilities (2)	538	824	645	2,606	4,613
Long-Term Debt (2)	526	1,910	1,989	7,286	11,711

As at December 31, 2023	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	5,480	—	—	—	5,480
Short-Term Borrowings	179	—	—	—	179
Contingent Payments	168	—	—	—	168
Lease Liabilities (2)	438	712	569	2,635	4,354
Long-Term Debt (2)	313	792	3,007	7,145	11,257

(1)Includes current risk management liabilities.

(2)Principal and interest, including current portion, if applicable.



34. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital


As at December 31,	2024	2023
Total Current Assets	10,434	9,708
Total Current Liabilities	7,362	6,210
Working Capital	3,072	3,498

B) Changes in Non-Cash Working Capital


For the years ended December 31,	2024	2023
Accounts Receivable and Accrued Revenues	547	314
Income Tax Receivable	199	(295)
Inventories	(117)	216
Accounts Payable and Accrued Liabilities	299	(685)
Income Tax Payable	322	(1,112)
Total Change in Non-Cash Working Capital	1,250	(1,562)

Net Change in Non-Cash Working Capital – Operating Activities	1,305	(1,193)
Net Change in Non-Cash Working Capital – Investing Activities	(55)	(369)
Total Change in Non-Cash Working Capital	1,250	(1,562)

C) Cash Flows Related to Interest and Taxes


For the years ended December 31,	2024	2023
Interest Paid	356	402
Interest Received	163	130
Income Taxes Paid	868	2,595


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			51

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

D) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:


	Dividends Payable	Warrants	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2022	9	—	115	8,691	2,836
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	58	—	—


Repayment of Long-Term Debt	—	—	—	(1,346)	—
Principal Repayment of Leases	—	—	—	—	(288)



Dividends Paid	(1,026)	—	—	—	—
Payment for Purchase of Warrants	—	(711)	—	—	—
Finance and Transaction Costs	—	(2)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	—	(84)	—
Finance and Transaction Costs	—	2	—	(19)	—
Lease Acquisitions	—	—	—	—	33
Lease Additions	—	—	—	—	57
Base Dividends Declared on Common Shares	990	—	—	—	—

Dividends Declared on Preferred Shares	36	—	—	—	—
Warrants Purchased and Cancelled	—	711	—	—	—
Exchange Rate Movements and Other	—	—	6	(134)	20


As at December 31, 2023	9	—	179	7,108	2,658
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	5	—	—


Principal Repayment of Leases	—	—	—	—	(299)
Dividends Paid	(1,551)	—	—	—	—

Non-Cash Changes:
Finance and Transaction Costs	—	—	—	(16)	—

Lease Additions	—	—	—	—	363
Base Dividends Declared on Common Shares	1,255	—	—	—	—
Variable Dividends Declared on Common Shares	251	—	—	—	—
Dividends Declared on Preferred Shares	36	—	—	—	—
Exchange Rate Movements and Other	—	—	(11)	442	205
As at December 31, 2024	—	—	173	7,534	2,927


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			52

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024




35. 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, 2024	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	2,122	1,947	1,921	1,904	1,815	14,551	24,260
Product Purchases	14	—	—	—	—	—	14

Real Estate	63	63	61	59	63	532	841
Obligation to Fund HCML	104	105	98	56	44	105	512
Other Long-Term Commitments	411	191	187	158	117	589	1,653
Total Commitments	2,714	2,306	2,267	2,177	2,039	15,777	27,280


As at December 31, 2023	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	2,018	1,927	1,680	1,663	1,641	15,738	24,667
Product Purchases	617	—	—	—	—	—	617
Real Estate	57	57	59	63	58	604	898
Obligation to Fund HCML	94	94	94	89	52	90	513
Other Long-Term Commitments	417	194	184	175	166	965	2,101
Total Commitments	3,203	2,272	2,017	1,990	1,917	17,397	28,796

(2)As at December 31, 2024, includes $1.8 billion related to transportation and storage commitments with HMLP (December 31, 2023 – $2.1 billion).

There were outstanding letters of credit aggregating to $355 million (December 31, 2023 – $364 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.



36. MATERIAL ACCOUNTING POLICIES

A) Revenue Recognition

Revenue is based on the consideration specified in a contract and is recorded when control of the product or service passes to the customer in accordance with terms of the contract. Performance obligations are largely satisfied at a point in time upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products. 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. Performance obligations for crude oil and natural gas processing revenue, transportation services and transloading services are satisfied over time as the service is provided. Revenue associated with crude oil and natural gas processing, transportation services and transloading services are generally based on fixed price contracts.

Revenues are typically collected in the month following delivery. Therefore, Cenovus has elected to apply the practical expedient to not adjust consideration for the effects of a financing component. The Company does not disclose information about remaining performance obligations with 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.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			53

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded as non-monetary exchanges on a net basis.

Cenovus has take-or-pay contracts where customers are required to take, or pay for, minimum quantities. If a customer has a right to defer delivery to a later date, Cenovus’s performance obligation has not been satisfied. Revenue is deferred and recognized only when the product is delivered, or the deferral provision can no longer be extended.

B) Purchased Product, Transportation and Blending

Purchased Product

Purchased product includes the costs of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market.

Transportation and Blending

Costs paid for the transportation of crude oil, NGLs and natural gas, and the cost of diluent used in blending are recognized when the product is sold.

C) Employee Benefit Plans

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component. OPEB plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, employees and retirees may contribute. In some plans, benefits are not funded before employees retire.

The cost of the defined contribution pension plan 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 estimated cost is based on length of service and reflects Management’s best estimate of salary escalation, longevity rates, employees’ retirement age and expected future health care costs. The liability for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets.

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 salaries of the employees providing the service are recorded. Interest costs on the net obligation (asset) are included as part of pension benefit costs. Remeasurement changes, including actuarial gains or losses related to the plan assets and defined benefit obligation, the effect of changes to the asset ceiling and return on plan assets are recognized in OCI when they occur.

D) Deferred Income Taxes

Cenovus follows the liability method of accounting for deferred income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting basis and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets will be realized, or liabilities will be settled. The effect of a change in the enacted tax rate or laws is recognized in net earnings (loss) in the period that the change occurs, except when it relates to items recorded in 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.

E) Inventories

Product inventories are valued at the lower of cost, using a first-in, first-out, or weighted average cost basis, and net realizable value. Parts and supplies are valued at the lower of weighted average cost and net realizable value. The cost of inventory includes purchase costs, direct production costs, and DD&A. Net realizable value is the estimated selling price in the ordinary course of business less expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized in net earnings (loss).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			54

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

F) Exploration and Evaluation Assets

E&E assets consist of exploratory projects for crude oil, NGLs and natural gas that are pending the determination of proved reserves. The costs to acquire non-producing oil and gas properties, licenses to explore, drilling exploratory wells and the costs to evaluate the commercial potential of the resources are initially capitalized as E&E assets. Costs incurred prior to obtaining the legal right to explore an area (pre-exploration costs) are recorded as exploration expense when incurred.

Once technical feasibility and commercial viability of an E&E asset is established, the carrying value is transferred to PP&E. If Management does not consider an E&E asset to be technically feasible and commercially viable, the related capital costs are written off as exploration expense.

G) Property, Plant and Equipment

PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals. Capitalized costs include the purchase price, construction or development expenditures, directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs. Costs incurred to install the asset and make it ready for its intended use are also capitalized. Expenditures that improve the productive capacity or extend the life of an asset are capitalized, while maintenance costs and repairs are expensed as incurred.

Crude Oil and Natural Gas Properties

Development and production assets are capitalized by area. Costs includes all expenditures associated with the development of crude oil and natural gas properties and related infrastructure, as well as expenditures transferred from E&E assets.

Development and production assets are depleted using the unit-of-production method based on estimated reserves determined using forward prices and costs. The unit-of-production depletion rate takes into account expenditures incurred to date, together with the future development expenditures required to develop reserves. Onshore assets are depleted based on estimated proved reserves. Offshore assets are depleted based on estimated proved developed producing reserves or proved plus probable reserves.

Refining Assets

The Company’s refineries and plants are composed of highly integrated and interdependent crude oil and other feedstock processing facilities and supporting infrastructure. Where facilities and equipment, including major components, are significant in relation to the total cost of the assets and have different useful lives, they are depreciated on a straight-line basis over the estimated service life of each component. Major components are depreciated as follows:

•Land improvements and buildings: 10 to 40 years.

•Office equipment and vehicles: 3 to 15 years.

•Rail facilities: 10 to 40 years.

•Refining equipment: 5 to 60 years.

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. Land is not depreciated.

H) Impairments of Assets

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 of an asset or CGU may exceed its recoverable amount. Goodwill is tested for impairment at least annually. E&E assets are also tested for impairment immediately prior to being transferred to PP&E.

Cenovus allocates E&E assets to a related CGU containing development and production assets when 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 CGUs that benefited from the historical business combinations.

The recoverable amount of the asset or CGU is estimated as the greater of value-in-use (“VIU”) and FVLCOD. VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of an asset or CGU. 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. The FVLCOD for upstream assets is estimated based on the discounted after-tax cash flows of reserves using forward prices, future operating costs and future capital expenditures consistent with Cenovus’s IQREs, and may consider an evaluation of comparable asset transactions. FVLCOD for downstream assets is estimated based on discounted after-tax cash flows of refined product production, forward crude oil prices, forward crack spreads, net of RINs, future capital expenditures, future operating costs and discount rates. Forward prices are based on third-party consultant forecasts.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			55

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

If the recoverable amount of the asset or CGU is less than the carrying amount, an impairment loss is recognized. The impairment loss first reduces the goodwill allocated to a CGU, if any, and then reduces the carrying amount of the remaining assets in the CGU. Impairment losses on PP&E and ROU assets are recognized as additional DD&A. 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 indicators that the impairment losses may no longer exist or may have decreased. If such indications exist, the carrying amount of the asset or CGU 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 in prior periods. The reversal is recognized as a reduction to DD&A.

Impairment of Financial Assets

At each reporting date, the Company assesses the expected credit losses associated with its financial assets measured at amortized cost. For accounts receivable, Cenovus measures loss allowances at an amount equal to lifetime ECLs. ECLs are estimated as the difference between the cash flows due to the Company and the cash flows the Company expects to receive, discounted at the effective interest rate on initial recognition. Changes in ECLs are recognized in other income (loss).

I) Leases

As Lessee

The Company recognizes an ROU asset and a lease liability when the leased asset is available for use.

Lease liabilities are measured at the present value of lease payments and estimated costs to dismantle and remove the underlying leased asset. Lease liabilities are discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company’s incremental borrowing rate. Lease payments include fixed payments, as well as variable payments based on an index or rate. Lease liabilities are re-measured when there is a change in the future lease payments due to a change in an index or rate. Re-measurement will also occur if there is a change in the expected residual value guarantee or if the Company reconsiders the exercise of a purchase, extension or termination option that is within its control. When the lease liability is re-measured, an adjustment is also made to the carrying amount of the ROU asset.

The ROU asset is initially measured at cost, which includes the initial measurement of the lease liability and initial direct costs. The cost is depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term.

Leases with a term of less than twelve months, or leases of an asset with a low value, are recognized over the lease term as an operating, transportation, or general and administrative expense. The Company has elected not to separate non-lease components for storage tanks.

As Lessor

Leases where the Company transfers substantially all of the risks and rewards from ownership of an underlying asset are classified as financing leases. 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. Cenovus recognizes lease payments for operating leases as income on a straight-line basis over the term of the lease as other income.

J) 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.

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 (loss). 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 is not re-measured and settlements are recorded in 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 (loss).


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			56

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

K) Provisions

A provision is recognized if the Company has a present legal or constructive obligation as a result of a past event. It must be possible to reliably estimate the obligation and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, the expected future cash flows of a provision are discounted using a credit-adjusted risk-free rate. The increase in the provision due to the passage of time is recognized as a finance expense.

Decommissioning Liabilities

The Company will be required to retire its 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. When a disturbance occurs, the Company recognizes a decommissioning liability equal to the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. The initial estimate of the liability is added to the cost of the related asset and amortized over the useful life of the asset. Changes in the provision arising from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. Actual expenditures incurred are charged against the liability.

Renewable Fuel Obligations

The Company’s U.S. refining operations incur an RVO, which the Company settles annually using RINs. After considering RINs on hand, the RVO is measured at the expected market price, or on a contracted forward rate, if applicable, 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. RINs are not amortized. A net RIN position is presented in other assets and a net RVO position is included in other liabilities.

L) Share Capital and Warrants

Common shares, treasury shares and preferred shares are classified as equity. When the Company purchases its own common shares, share capital is reduced by the weighted average carrying value of the shares purchased. Any difference between the purchase price and the carrying value is recorded to paid in surplus. No gain or loss is recognized on the purchase, sale, issuance or cancellation of equity instruments. Common shares and preferred shares are cancelled upon purchase.

Common shares purchased under the employee benefit plan are measured at their cost to acquire and are recorded as treasury shares. When the treasury shares are distributed under the employee benefit plan, the treasury shares are reduced by their weighted average carrying value with the excess or deficiency from the settled employee LTI liability recognized in paid in surplus.

Transaction costs directly attributable to the issue or repurchase of common shares, treasury shares and preferred shares are recognized as a deduction from equity, net of any income taxes.

Warrants are classified as equity and are 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.

M) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans that include stock options with associated NSRs, Cenovus replacement stock options, PSUs, RSUs and DSUs. Stock-based compensation costs are recorded in general and administrative expenses.

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. 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 are recorded as share capital.


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			57

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2024

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. Fair value fluctuations are recognized in stock-based compensation in the period they occur. Cenovus has certain PSU and RSU plans that may be settled in cash or common shares at the Company's option and certain plans that are settled in cash.

N) Financial Instruments

Financial assets are classified and measured as follows based on the objective of the business model for managing the instrument or group of instruments, and the contractual terms of the cash flows. Financial liabilities are measured at amortized cost or fair value through profit or loss as noted below.


Classification						Instrument Type
Amortized Cost						Cash and cash equivalents, restricted cash, accounts receivable and accrued revenues, accounts payable and accrued liabilities, short-term borrowings, lease liabilities and long-term debt.
Fair Value Through Profit or Loss						Risk management assets and liabilities, and contingent payments.
Fair Value Through Other Comprehensive Income (Loss)						Certain equity investments not held for trading for which an irrevocable election was made at initial recognition.

All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the financial instrument.

Cenovus uses observable market inputs as much as possible when estimating the fair value of financial instruments. Inputs are categorized into the following levels based on how observable the inputs are:

•Level 1: Quoted prices in active markets for identical assets and liabilities.

•Level 2: Inputs other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly.

•Level 3: Unobservable inputs for the asset or liability.

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.

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.

Derivative financial instruments are measured at fair value through profit or loss unless designated for hedge accounting. Derivative instruments not designated as hedges are recorded using mark-to-market accounting whereby any changes in fair value are recorded as a gain or loss on risk management. The estimated fair value of derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

O) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

Presentation and Disclosure in Financial Statements

Financial Instruments


Cenovus Energy Inc. – 2024 Consolidated Financial Statements			58

EX-99.4 5 a2024supplementaryinformat.htm EX-99.4 Document

Exhibit 99.4

Cenovus Energy Inc.

Supplementary Information – Oil and Gas Activities (unaudited)

For the Year Ended December 31, 2024

(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 as issued by the International Accounting Standards Board (the “IFRS Accounting Standards”). 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, 2024, 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 2024 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 18, 2025, with an effective date of December 31, 2024.


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. Reserves data tables may not sum due to rounding.

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
2023
Beginning of year		4,021		68		55		1,538		4,399
Technical revisions and improved recovery		(33)		(2)		(3)		(14)		(40)
Revisions due to price		160		(3)		(2)		(40)		148
Total revisions to prior estimates		127		(5)		(5)		(54)		109
Extensions and discoveries		85		4		3		134		115
Purchase of reserves in place		7		—		—		—		7
Sale of reserves in place		—		—		—		(3)		(1)
Production		(163)		(10)		(6)		(205)		(214)
End of year		4,077		56		47		1,411		4,415
Developed		781		50		37		1,083		1,049
Undeveloped		3,296		6		10		328		3,367
Total		4,077		56		47		1,411		4,415
2024
Beginning of year		4,077		56		47		1,411		4,415
Technical revisions and improved recovery		(67)		—		—		(60)		(76)
Revisions due to price		(90)		—		(11)		(399)		(168)
Total revisions to prior estimates		(157)		—		(11)		(458)		(244)
Extensions and discoveries		103		61		2		49		173
Purchase of reserves in place		—		—		—		—		—
Sale of reserves in place		—		(1)		(2)		(26)		(8)
Production		(170)		(10)		(7)		(210)		(222)
End of year		3,853		105		28		766		4,115
Developed		671		44		23		677		852
Undeveloped		3,182		61		5		89		3,263
Total		3,853		105		28		766		4,115


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
2023
Beginning of year		—		—		11		314		64
Technical revisions and improved recovery		—		—		1		(1)		1
Total revisions to prior estimates		—		—		1		(1)		1
Production		—		—		(3)		(65)		(14)
End of year		—		—		9		248		51
Developed		—		—		9		248		51
Undeveloped		—		—		—		—		—
Total		—		—		9		248		51

2024
Beginning of year		—		—		9		248		51
Technical revisions and improved recovery		—		—		3		45		11
Revisions due to price		—		—		(1)		1		(1)
Total revisions to prior estimates		—		—		2		46		10
Production		—		—		(3)		(69)		(15)
End of year		—		—		8		225		46
Developed		—		—		8		225		46
Undeveloped		—		—		—		—		—
Total		—		—		8		225		46

Total Consolidated Entities
2023
Beginning of year		4,021		68		66		1,852		4,463
Technical revisions and improved recovery		(33)		(2)		(2)		(15)		(39)
Revisions due to price		160		(3)		(2)		(40)		148
Total revisions to prior estimates		127		(5)		(4)		(55)		109
Extensions and discoveries		85		4		3		134		115
Purchase of reserves in place		7		—		—		—		7
Sale of reserves in place		—		—		—		(3)		(1)
Production		(163)		(10)		(9)		(270)		(227)
End of year		4,077		56		56		1,659		4,466
Developed		781		50		46		1,331		1,099
Undeveloped		3,296		6		10		328		3,367
Total		4,077		56		56		1,659		4,466


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)
2024
Beginning of year		4,077		56		56		1,659		4,466
Technical revisions and improved recovery		(67)		—		3		(14)		(66)
Revisions due to price		(90)		—		(12)		(397)		(168)
Total revisions to prior estimates		(157)		—		(9)		(412)		(234)
Extensions and discoveries		103		61		2		49		173
Purchase of reserves in place		—		—		—		—		—
Sale of reserves in place		—		(1)		(2)		(26)		(8)
Production		(170)		(10)		(10)		(279)		(237)
End of year		3,853		105		37		991		4,160
Developed		671		44		32		902		898
Undeveloped		3,182		61		5		89		3,263
Total		3,853		105		37		991		4,160

Equity-Accounted Affiliates
Indonesia
2023
Beginning of year		—		—		2		124		23
Technical revisions and improved recovery		—		—		—		14		2
Revisions due to price		—		—		—		—		—
Total revisions to prior estimates		—		—		—		14		2
Extensions and discoveries		—		—		—		10		2
Production		—		—		(1)		(21)		(4)
End of year		—		—		2		126		23
Developed		—		—		2		126		23
Undeveloped		—		—		—		—		—
Total		—		—		2		126		23

2024
Beginning of year		—		—		2		126		23
Technical revisions and improved recovery		—		—		—		18		3
Revisions due to price		—		—		—		(7)		(1)
Total revisions to prior estimates		—		—		—		11		2
Extensions and discoveries		—		—		—		—		—
Production		—		—		—		(29)		(5)
End of year		—		—		2		108		20
Developed		—		—		2		108		20
Undeveloped		—		—		—		—		—
Total		—		—		2		108		20


Cenovus Energy Inc.			5			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)
Canada
2024
Beginning of year		—		—		—		—		—
Technical revisions and improved recovery		—		—		—		—		—
Revisions due to price		—		—		—		—		—
Total revisions to prior estimates		—		—		—		—		—
Purchase of reserves in place		—		7		1		18		11
Production		—		—		—		(1)		—
End of year		—		7		1		17		11
Developed		—		1		—		2		1
Undeveloped		—		6		1		15		9
Total		—		7		1		17		11

(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.

Changes to Reserves

The explanation of significant year-over-year changes in the Company’s net proved reserves for the years ended December 31, 2024, and December 31, 2023, is set forth below.

Year ended December 31, 2024

The changes to the Company's net proved bitumen reserves in 2024 are explained as follows:

•Technical revisions and improved recovery: Decreases to recovery factors at Christina Lake and Foster Creek and changes to the Lloydminster thermal development plan resulted in a decrease in net proved reserves of 157 million barrels. Increased forecast capital and operating costs reduced royalties payable for the Oil Sands segment, which resulted in an increase in net proved reserves of 90 million barrels.

•Revisions due to price: Increased bitumen prices increased royalties payable for the Oil Sands segment, which resulted in a decrease in net proved reserves.

•Extensions and discoveries: Continuing development and development plan updates at Christina Lake, Foster Creek and Lloydminster thermal increased net proved reserves.

The changes to the Company's net proved reserves of crude oil, natural gas liquids and natural gas in 2024 are explained as follows:

•Technical revisions and improved recovery: Increases to original natural gas in place volumes for China and Indonesia were partially offset by updates to the Conventional segment development plans, increasing net proved reserves.

•Revisions due to price: Lower product pricing for the Conventional segment, China and Indonesia decreased net proved reserves.

•Extensions and discoveries: Continuing development of the West White Rose project and development within the Conventional segment and Lloydminster conventional heavy oil increased net proved reserves.

•Purchase of reserves in place: The acquisition of an equity interest in Duvernay Energy Corporation increased net proved reserves.

•Sale of reserves in place: The sale of minor interests within the Conventional segment decreased net proved reserves.


Cenovus Energy Inc.			6			Supplementary Information – Oil and Gas Activities (unaudited)

Year ended December 31, 2023

The changes to the Company's net proved bitumen reserves in 2023 are explained as follows:

•Technical revisions and improved recovery: Decreases to recovery factors at Christina Lake and Foster Creek, offset by improved recovery performance at Lloydminster thermal resulted in a decrease in net proved reserves of 83 million barrels. Increased forecast capital and operating costs reduced royalties payable for the Oil Sands segment, which resulted in an increase in net proved reserves of 50 million barrels.

•Revisions due to price: Lower bitumen prices reduced royalties payable for the Oil Sands segment, which resulted in an increase in net proved reserves.

•Extensions and discoveries: Regulatory approvals at Foster Creek and Lloydminster thermal increased net proved reserves.

•Purchase of reserves in place: An acquisition in the Oil Sands segment increased net proved reserves.

The changes to the Company's net proved reserves of crude oil, natural gas liquids and natural gas in 2023 are explained as follows:

•Technical revisions and improved recovery: Updates to the Conventional segment development plans were partially offset by improved recovery performance in the Offshore segment, decreasing net proved reserves.

•Revisions due to price: Lower product pricing within the Conventional segment and Lloydminster conventional heavy oil decreased net proved reserves.

•Extensions and discoveries: Development within the Conventional segment increased 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.

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 in place.


	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)
2024		81.17		75.48		83.57		97.32		99.90		2.13		1.26
2023		83.17		78.22		81.15		100.50		103.67		2.64		2.78

(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.


Cenovus Energy Inc.			7			Supplementary Information – Oil and Gas Activities (unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves


	Year Ended December 31, 2024
		Consolidated Entities				Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
Future cash inflows		281,442		3,605	285,047		1,304		664
Less future:
Production costs		71,082		815	71,897		697		205
Development costs		35,027		145	35,172		—		248
Asset retirement obligation payments (1)		7,668		53	7,721		45		7
Income taxes		37,901		578	38,479		225		49
Future net cash flows		129,764		2,014	131,778		337		155
Less 10 percent annual discount for estimated timing of cash flow		78,271		356	78,627		83		97
Discounted future net cash flow		51,493		1,658	53,151		254		58


	Year Ended December 31, 2023
		Consolidated Entities				Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
Future cash inflows		270,046		4,005	274,051		1,494	—
Less future:
Production costs		76,463		617	77,080		784	—
Development costs		34,682		169	34,851		2	—
Asset retirement obligation payments (1)		7,382		64	7,446		30	—
Income taxes		34,273		720	34,993		272	—
Future net cash flows		117,246		2,435	119,681		406	—
Less 10 percent annual discount for estimated timing of cash flow		73,666		421	74,087		84	—
Discounted future net cash flow		43,580		2,014	45,594		322	—

(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.			8			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, 2024
	Consolidated Entities						Equity-Accounted Affiliates
($ millions)	Canada		China			Total	Indonesia	Canada
Balance, beginning of year		43,580		2,014		45,594	322	—
Changes resulting from:
Sales of oil and gas produced during the period, net of operating costs (1)		(10,092)		(1,029)		(11,121)	(229)	(14)
Extensions, discoveries and improved recovery, net of related cost		7,205		—		7,205	—	—
Purchases of proved reserves in place		1		—	1		—	285
Sales of proved reserves in place		(12)		—		(12)	—	—
Net change in prices and production costs (1)		15,293		(157)		15,136	29	8
Revisions to quantity estimates		(4,283)		489		(3,794)	40	—
Accretion of discount		5,080		178		5,258	38	—
Changes in estimated future development costs		(4,961)		(19)		(4,980)	7	(217)
Costs incurred		4,185		30		4,215	(5)	20
Other		(511)		246		(265)	50	4
Net change in income taxes		(3,992)		(94)		(4,086)	2	(28)
Balance, end of year		51,493		1,658		53,151	254	58


	Year Ended December 31, 2023
	Consolidated Entities					Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia	Canada
Balance, beginning of year		55,844		2,603	58,447	277	—
Changes resulting from:
Sales of oil and gas produced during the period, net of operating costs (1)		(8,848)		(1,022)	(9,870)	(197)	—
Extensions, discoveries and improved recovery, net of related cost		4,990		—	4,990	38	—
Purchases of proved reserves in place		60		—	60	—	—
Sales of proved reserves in place		(2)		—	(2)	—	—
Net change in prices and production costs (1)		(14,192)		109	(14,083)	153	—
Revisions to quantity estimates		(437)		41	(396)	57	—
Accretion of discount		6,302		260	6,562	35	—
Changes in estimated future development costs		(4,770)		(112)	(4,882)	(15)	—
Costs incurred		3,389		3	3,392	14	—
Other		(1,037)		198	(839)	38	—
Net change in income taxes		2,281		(66)	2,215	(78)	—
Balance, end of year		43,580		2,014	45,594	322	—

(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.			9			Supplementary Information – Oil and Gas Activities (unaudited)

OTHER FINANCIAL INFORMATION

Results of Operations


	Year Ended December 31, 2024
	Consolidated Entities					Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
External sales		23,390		1,250	24,640		339		24
Intersegment sales		8,438		—	8,438		—		—
Royalties, purchased product, transportation and blending and realized risk management		(18,372)		(96)	(18,468)		(55)		(4)
Oil and gas sales, net of royalties, purchased product, transportation and blending and realized risk management		13,456		1,154	14,610		284		20
Less:
Operating costs and accretion of asset retirement obligations		3,563		138	3,701		58		6
Depreciation, depletion and amortization		3,627		495	4,122		113		17
Exploration expense		19		50	69		3		—
Operating income		6,247		471	6,718		110		(3)
Income taxes		1,706		215	1,921		44		(1)
Results of operations		4,541		256	4,797		66		(2)


	Year Ended December 31, 2023
	Consolidated Entities					Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia	Canada
External sales		22,496		1,217	23,713	317	—
Intersegment sales		7,369		—	7,369	—	—
Royalties, purchased product, transportation and blending and realized risk management		(17,438)		(84)	(17,522)	(74)	—
Oil and gas sales, net of royalties, purchased product, transportation and blending and realized risk management		12,427		1,133	13,560	243	—
Less:
Operating costs and accretion of asset retirement obligations		3,773		124	3,897	49	—
Depreciation, depletion and amortization		3,402		464	3,866	78	—
Exploration expense		37		5	42	2	—
Operating income		5,215		540	5,755	114	—
Income taxes		1,311		221	1,532	46	—
Results of operations		3,904		319	4,223	68	—


Cenovus Energy Inc.			10			Supplementary Information – Oil and Gas Activities (unaudited)

Capitalized Costs


	Year Ended December 31, 2024
	Consolidated Entities					Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
Proved oil and gas properties		48,755		3,335	52,090		479	275
Unproved oil and gas properties (1)		476		8	484		—	—
Total capital cost		49,231		3,343	52,574		479	275
Accumulated depreciation, depletion and amortization		19,754		2,095	21,849		234	145
Net capitalized costs		29,477		1,248	30,725		245	130


	Year Ended December 31, 2023
	Consolidated Entities					Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
Proved oil and gas properties		44,342		3,083	47,425		436		—
Unproved oil and gas properties (1)		729		9	738		—		—
Total capital cost		45,071		3,092	48,163		436		—
Accumulated depreciation, depletion and amortization		16,487		1,488	17,975		157		—
Net capitalized costs		28,584		1,604	30,188		279		—

(1) Unproved oil and gas properties include exploration and evaluation assets for which no proved reserves have been recognized.

Costs Incurred


	Year Ended December 31, 2024
	Consolidated Entities						Equity-Accounted Affiliates
($ millions)	Canada		China		Total		Indonesia		Canada
Acquisitions
Unproved (1)		7		—		7		—	—
Proved (2) (3)		15		—		15		—	—
Total acquisitions		22		—		22		—	—
Exploration costs		27		38		65		—	—
Development costs		4,185		30		4,215		(5)	20
Total costs incurred		4,234		68		4,302		(5)	20


	Year Ended December 31, 2023
	Consolidated Entities						Equity-Accounted Affiliates
($ millions)	Canada		China		Total		Indonesia		Canada
Acquisitions
Unproved (1)		31		—		31		—	—
Proved (2) (3)		11		—		11		—	—
Total acquisitions		42		—		42		—	—
Exploration costs		80		4		84		—	—
Development costs		3,389		3		3,392		14	—
Total costs incurred		3,511		7		3,518		14	—

(1)An unproved property is a property to which no proved or probable reserves have been specifically attributed.

(2)A proved property is a property to which proved and probable reserves have been specifically attributed.

(3)Asset retirement costs are included in the year of acquisition.


Cenovus Energy Inc.			11			Supplementary Information – Oil and Gas Activities (unaudited)

EX-99.5 6 ex995ye2024ceo302certifica.htm EX-99.5 Document

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, Jonathan M. McKenzie, 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 20, 2025


			/s/ Jonathan M. McKenzie
			Jonathan M. McKenzie President & Chief Executive Officer

EX-99.6 7 ex996ye2024cfo302certifica.htm EX-99.6 Document

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, Karamjit S. Sandhar, 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 20, 2025


			/s/ Karamjit S. Sandhar
			Karamjit S. Sandhar Executive Vice-President & Chief Financial Officer (Principal Financial Officer)

EX-99.7 8 ex997ye2024ceo906certifica.htm EX-99.7 Document

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, 2024, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jonathan M. McKenzie, 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 20, 2025


			/s/ Jonathan M. McKenzie
			Jonathan M. McKenzie President & Chief Executive Officer

EX-99.8 9 ex998ye2024cfo906certifica.htm EX-99.8 Document

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, 2024, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Karamjit S. Sandhar, 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 20, 2025


			/s/ Karamjit S. Sandhar
			Karamjit S. Sandhar Executive Vice-President & Chief Financial Officer

EX-99.9 10 ex999pwcconsentform40f.htm EX-99.9 Document

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, 2024 of Cenovus Energy Inc. of our report dated February 19, 2025, relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in Exhibit 99.3 incorporated by reference in 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. 333-275322), Form S-8 (File Nos. 333-163397, 333-251886 and 333-283967) and Form-3D (File No. 333-202165) of Cenovus Energy Inc. of our report dated February 19, 2025 referred to above. We also consent to the reference to us under the heading “Interests of Experts” in the Annual Information Form, filed as Exhibit 99.1 to this Annual Report on Form 40-F, which is incorporated by reference in such Registration Statements.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta, Canada

February 20, 2025

PricewaterhouseCoopers LLP

111 5th Ave SW, Calgary, Alberta, Canada T2P 5L3

T: +1 403 509 7500, F: +1 403 781 1825

“PwC” refers to PricewaterhouseCoopers LLP/s.r.l./s.e.n.c.r.l., an Ontario limited liability partnership.

EX-99.10 11 ex9910mcdanielconsentform.htm EX-99.10 Document

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, 2024, 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, 2024 and Cenovus Energy Inc.’s registration statements on Form F-10 (File No. 333-275322), Form S-8 (File Nos. 333-163397, 333-251886 and 333-283967) 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 20, 2025

2000, Eighth Avenue Place, East Tower, 525 – 8 Avenue SW, Calgary, AB, T2P 1G1 Tel: (403) 262-5506 www.mcdan.com

EX-99.11 12 ex9911gljconsentform40f.htm EX-99.11 Document

Exhibit 99.11

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

Yours truly,

GLJ LTD.

“Originally Signed By”

Jodi L. Anhorn, M. Sc., P. Eng.

President and Chief Executive Officer

Calgary, Alberta

February 20, 2025

1920, 401 – 9th Ave SW Calgary, AB, Canada T2P 3C5 I teI 403-266-9500 I gIjpc.com

EX-99.97 13 ex97clawbackpolicy.htm EX-99.97 Document

Exhibit 97

Clawback Policy

Effective date: November 3, 2023

Last updated: November 1, 2023

Last reviewed: November 1, 2023

Purpose

This Clawback Policy (“Policy”) provides for the clawback of incentive-based compensation granted to Executive Officers of Cenovus Energy Inc. (the “Corporation”) in certain circumstances. Appendix A to this Policy is incorporated herein by reference and is intended to comply with the listing requirements of the New York Stock Exchange (“NYSE”) regarding clawback of incentive-based compensation pursuant to Rule 10D-1 under the U.S. Securities Exchange Act of 1934, as amended (the "U.S. Securities Exchange Act").

Definitions

“Board” means the board of directors of the Corporation;

“Executive Officer” means the Corporation’s current or former President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer (or if there is no such officer, then the Controller), any Vice-President of the Corporation in charge of a principal business unit, division or function, and any other current or former officer or person who performs or performed a significant policy-making function for the Corporation, including executive officers of Corporation subsidiaries;

“Incentive-Based Compensation” means, with respect to an Executive Officer, any annual incentive or other performance-based compensation awards (whether vested or not, paid or unpaid), including without limitation any cash bonus or equity incentive award under the Corporation’s short- and long-term incentive programs, plans and policies for eligible officers and employees of the Corporation (and any amounts attributable to such awards, including proceeds of sale);

“Repayment Amount” means the after-tax amount (as determined by the Board in its sole discretion): (a) in the case of 1 below, of Incentive-Based Compensation that was paid or granted to an Executive Officer in excess of the Incentive-Based Compensation that would have been paid or granted to that Executive Officer during the three fiscal years preceding such Restatement less Erroneously Awarded Compensation (as defined in Appendix A to this Policy) that is recovered by the Corporation in accordance with Appendix A to this Policy; or (b) in the case of 2 below, by which the Executive Officer was, directly or indirectly, financially enriched during the period of three years prior to the admission of the Executive Officer or the filing and service of a civil claim, statement of claim or equivalent commencement document, as applicable, in respect of any action of the Executive Officer; provided however that in no circumstances shall the Repayment Amount exceed the after-tax amount of such Incentive-Based Compensation originally paid or granted to the Executive Officer; and

“Securities Laws” means all applicable laws, regulations, rules, blanket rulings, orders, policies or instruments of any securities regulatory authority, securities commission, the Toronto Stock Exchange, the New York Stock Exchange or like body in Canada and/or the United States, as applicable from and after the date of this Policy.

Clawback

In addition, and without limitation, to recourse available to the Corporation pursuant to Appendix A to this Policy, in the event that:

1. (a) any Incentive-Based Compensation paid or granted to an Executive Officer was calculated based upon, or contingent on, the achievement of certain financial results that were subsequently the subject of, or affected by, a Restatement (as defined in Appendix A to this Policy);

(b) the Executive Officer engaged in intentional misconduct or fraud that caused, or materially contributed to, the need for the Restatement, as admitted by the Executive


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Exhibit 97

Officer or, in the absence of such admission, as determined by a court of competent jurisdiction in a final judgement that cannot, or will not, be appealed; and

(c) the Incentive-Based Compensation paid or granted to, or that would have been received by, the Executive Officer would have been lower had the financial statements materially complied with Securities Laws; or

2. as admitted by the Executive Officer or, in the absence of such admission, as determined by a court of competent jurisdiction in a final judgement that cannot, or will not, be appealed, an Executive Officer has been financially enriched, directly or indirectly, as a result of the Executive Officer:

(a) engaging in fraud or theft of a financial nature; or

(b) failing to disclose a material conflict of interest;

that, in either case, has affected the business, reputation, operations or capital of the Corporation in a manner which has, directly or indirectly, resulted in a material decrease in the market price or value of securities of the Corporation;

(each, a “Triggering Event”),

the Board may, to the fullest extent permitted by applicable law and to the extent it determines that it is in the Corporation’s best interest to do so (in its sole discretion), require the Executive Officer to repay all or any portion of any Incentive Based Compensation paid or granted to the Executive Officer and/or cancel and terminate all or any portion of unvested Incentive-Based Compensation paid or granted to the Executive Officer.

Any Repayment Amount shall be paid, in cash, by the Executive Officer within 60 days (or another period as determined by the Board) of receipt by the Executive Officer from the Corporation of written notice requiring reimbursement of the Repayment Amount. To the extent that the Repayment Amount is not so paid to the Corporation, in addition to any other legal remedy that the Corporation may have, the Corporation may set off and deduct any Repayment Amount from and against any amounts that may be owing from time to time by the Corporation to the Executive Officer, including, without limitation, bonus, Incentive-Based Compensation, deferred compensation, and severance in a manner consistent with Section 409A of the Internal Revenue Code, if applicable, and, for greater certainty, the Corporation shall have the right to cancel any other outstanding Incentive-Based Compensation with a value equivalent to the outstanding Repayment Amount, as determined by the Board in its sole discretion. The determination of the Board with respect to the form(s) of recovery need not be uniform with respect to one or more Executive Officers.

For the avoidance of doubt, a restatement of the Corporation’s financial statements due to a change in accounting policies or principles shall not constitute a Triggering Event.

For the avoidance of doubt, this Policy applies to Incentive-Based Compensation received by the Executive Officer on or after January 1, 2022 (attributable to financial statements filed for the 2021 fiscal year and years following), except where an Executive Officer has an existing agreement with the Corporation that contains clawback provisions, in which case this Policy applies with immediate effect.

Further, each award agreement or any other document setting forth the terms and conditions of any annual incentive or other performance-based award granted to an Executive Officer shall be deemed to include the provisions of this Policy (including, for greater certainty, the provisions of Appendix A to this Policy).

Should there be any conflict between this Policy and the clawback provisions of any other agreement in place with the Executive Officer, the provisions of this Policy (including, for greater certainty, the provisions of Appendix A to this Policy) shall apply.


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Exhibit 97

The remedy specified in this Policy shall not be exclusive and shall be in addition to every other right or remedy at law or in equity that may be available to the Corporation. Without limiting the generality of this Policy and the provisions herein, measures for recovery of certain amounts of incentive-based compensation, as required under the NYSE listing standards, are set forth in Appendix A to this Policy.

The provisions of this Policy apply to the fullest extent of the law; provided however, to the extent that any provisions of this Policy are found to be unenforceable or invalid under any applicable law, such provision will be applied to the maximum extent permitted, and shall automatically be deemed amended in a manner consistent with its objectives to the extent necessary to conform to any limitations required under applicable law.

Board Discretion

Unless otherwise provided for in Appendix A to this Policy, the Board has the exclusive power and full and final authority to make all determinations deemed necessary or advisable for the administration of this Policy, including, without limitation, any determination as to whether the Policy applies, including:

•whether the non-compliance of the Corporation with any financial reporting requirement that results in a Restatement was material; and

•whether Incentive-Based Compensation paid or granted to the Executive Officer would have been lower had the financial statements materially complied with Securities Laws;

and if so, the Repayment Amount.

In determining whether to require repayment of the Repayment Amount and, if so, the Repayment Amount, the Board may take into account any considerations as it deems appropriate, including: (i) the likelihood of success in seeking repayment under applicable law relative to the effort involved; (ii) whether the assertion of a repayment claim may prejudice the interests of the Corporation in any related proceeding or investigation, or otherwise; (iii) whether the expense of seeking repayment is likely to exceed the amount sought or likely to be recovered; (iv) any pending or threatened legal proceedings relating to any acts or omissions giving rise, directly or indirectly, to the Restatement, and any actual or anticipated resolution (including any settlement) relating thereto; and (v) such other factors as it may deem appropriate under the circumstances.

Before the Board determines to seek repayment of the Repayment Amount, the Board may, in its sole discretion, provide to the applicable Executive Officer written notice of, and the opportunity to be heard at, a meeting of the Board (which may be in-person, by video conference, by means of telephone or other communication facility or by a combination of any of the foregoing, as determined by the Board in its sole discretion) held after a reasonable period of time.

In determining the after-tax portion of the Repayment Amount, the Board may take into account its good faith estimate of the tax paid or payable by such Executive Officer in respect of the Incentive-Based Compensation, as applicable, its good faith estimate of the value of any tax deduction or other tax relief available to such Executive Officer in respect of any repayment, in any of the forms sought, on account of the Repayment Amount, and such other factors as it may consider reasonable in the circumstances.

All such action, interpretations and determinations that are taken or made by the Board in good faith will be final, conclusive and binding. Subject to the Canada Business Corporations Act or any other legislation governing the Corporation and otherwise as provided for in Appendix A to this Policy, the Board may delegate to the Human Resources and Compensation Committee of the Board, on such terms as it considers appropriate, all or any part of the powers, duties and functions relating to the administration of this Policy.


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Exhibit 97

Appendix A – Clawback

This Appendix A to the Policy has been adopted in order to comply with the listing requirements of the New York Stock Exchange ("NYSE"), which were adopted pursuant to Rule 10D-1 of the United States Securities Exchange Act of 1934. This Appendix A shall apply to all Covered Compensation (as defined below) received on or after October 2, 2023. For the avoidance of doubt, recovery of any amount that may be recouped under the general provisions of the Policy to which this Appendix A is attached shall be in addition to and not in lieu of the recovery of Erroneously Awarded Compensation (as defined below) under this Appendix A.

Definitions

For the purposes of this Appendix A, the following terms shall have the meanings set forth below:

“Clawback Period” means the three completed fiscal years immediately preceding the earlier of (1) the date the Board (or a committee thereof) or the officer or officers of the Corporation authorized to take such action if Board action is not required, concludes, or reasonably should have concluded, that the Corporation is required to prepare a Restatement, or (2) the date that a court, regulator, or other legally authorized body directs the Corporation to prepare a Restatement. In addition, the Clawback Period includes any transition period (that results from a change in the Corporation’s fiscal year) within or immediately following those three completed fiscal years. However, a transition period between the last day of the Corporation’s previous fiscal year end and the first day of its new fiscal year that comprises a period of nine to twelve months would be deemed a completed fiscal year.

“Covered Compensation” means any compensation (including cash and equity compensation) that is granted, earned or vested based wholly or in part upon the attainment of any financial reporting measure. For the avoidance of doubt, Covered Compensation does not include (1) base salary, (2) compensation awarded based solely on service to the Corporation (such as a time-vested awards of restricted share units (RSUs) and options), or (3) compensation awarded based solely on subjective standards, strategic measures (such as upon completion of a corporate transaction) or operational measures (such as attainment of a certain market share). To the extent an Executive Officer receives a salary increase earned wholly or in part on the attainment of a financial reporting measure performance goal, such salary increase will be subject to recovery under this Appendix A”.

“Erroneously Awarded Compensation” means the amount of Covered Compensation received by an Executive Officer that exceeds the amount of Covered Compensation that otherwise would have been received had it been determined based on the Restatement, which shall be calculated on a pre-tax basis.

“Financial reporting measure” means a measure that is determined and presented in accordance with the accounting principles used in preparing the Corporation’s financial statements, and any measures that are derived wholly or in part from such measures. For the avoidance of doubt, stock price and total shareholder return are financial reporting measures.

“Restatement” means any accounting restatement of the Corporation’s financial results due to material non-compliance of the Corporation with any financial reporting requirement under Securities Laws, including any required accounting restatement to correct a material error to previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period.

Recovery of Erroneously Awarded Compensation upon Restatement

Notwithstanding anything contained in the general Policy to which this Appendix A is attached, in the event that the Corporation is required to prepare a Restatement, then the Board shall require each Executive Officer to repay and/or forfeit the Erroneously Awarded Compensation received by such Executive Officer during the Clawback Period and shall promptly provide written notice to each


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Exhibit 97

Executive Officer containing the amount of the Erroneously Awarded Compensation received by such Executive Officer and a demand for repayment or return of such amount, as applicable. Covered Compensation shall be deemed “received” in the fiscal period during which the applicable financial reporting measure specified in the Covered Compensation award is attained, even if the payment or grant occurs after the end of that fiscal period. This Appendix A applies to all Covered Compensation received by a person (i) after beginning service as an Executive Officer (including Covered Compensation derived from an award authorized before the individual is newly hired as an Executive Officer, e.g. inducement grants), (ii) who served as an Executive Officer at any time during the performance period for that Covered Compensation, (iii) while the Corporation has a class of securities listed on a national securities exchange or a national securities association, and (iv) during the Clawback Period.

The Board shall have the discretion to cancel awards, withhold payments or take such other action as it deems appropriate to recoup all Erroneously Awarded Compensation from the Executive Officers. To the extent the Erroneously Awarded Compensation represents an award which has previously been deferred, such deferred compensation award shall be forfeited. Without otherwise limiting the Board’s authority to recover the Erroneously Awarded Compensation hereunder, the Corporation shall have the authority to unilaterally forfeit an Executive Officer’s deferred compensation, subject to compliance with Section 409A of the Internal Revenue Code, if applicable.

Where Covered Compensation is based only in part on the achievement of a financial reporting measure performance goal, the Corporation will determine the portion of the original Covered Compensation based on or derived from the financial reporting measure which was restated and will recalculate the affected portion based on the financial reporting measure as restated to determine the difference between the greater amount based on the original financial statements and the lesser amount that would have been received based on the Restatement. The Erroneously Awarded Compensation will be calculated on a pre-tax basis to ensure that the Corporation recovers the full amount of Covered Compensation that was erroneously awarded.

For Covered Compensation based on stock price or total shareholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in a Restatement: (a) the amount shall be based on a reasonable estimate of the effect of the accounting restatement on the stock price or total shareholder return upon which the Covered Compensation was received; and (b) the Corporation shall maintain and provide documentation of the determination of that reasonable estimate to the NYSE. Clawback of Erroneously Awarded Compensation shall be without regard to any fault, misconduct, responsibility or involvement of the Executive Officer in the material non-compliance of the Corporation with any financial reporting requirement under Securities Laws.

The Board will take such action as it deems appropriate, in its sole and absolute discretion, to reasonably promptly clawback the Erroneously Awarded Compensation, unless the Human Resources and Compensation Committee of the Board determines that it would be impracticable to recover such amount because (1) the direct costs of enforcing recovery would exceed the Erroneously Awarded Compensation amount to be recovered subsequent to making a reasonable and documented attempt at recovery; or (2) recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Corporation, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder, based on opinion of counsel; or (3) if the recovery of the Covered Compensation would violate the home-country laws of the Corporation based on an opinion of home country counsel, which opinion must be provided to the NYSE.

Additional Recovery upon restatements as a result of misconduct under SOX Section 304

In addition to the provisions in this Appendix A, if the Corporation is, as a result of misconduct, required to prepare a Restatement, then in accordance with Section 304 of the Sarbanes-Oxley Act of 2002 (“SOX”), the Board shall have the discretion to require the Chief Executive Officer and Chief Financial Officer (at the time the financial document embodying such financial reporting requirement was originally issued) to reimburse the Corporation for (1) any bonus or other incentive-based or equity-


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Exhibit 97

based compensation received from the Corporation during the 12-month period following the first public issuance or filing with the Commission (whichever first occurs) of such financial document and (2) any profits realized from the sale of securities of the Corporation during that 12-month period. Such repayment shall be without regard to the knowledge, engagement or involvement of the Chief Executive Officer or Chief Financial Officer in the misconduct.

To the extent that the provisions of this Appendix A on Recovery of Erroneously Awarded Compensation upon Restatement (the “Rule 10D-1 Clawback Requirements”) provide for recovery of Covered Compensation recoverable by the Corporation pursuant to SOX and/or any other recovery obligations, the amount such Executive Officer has already reimbursed the Corporation shall be credited to the required recovery under the Rule 10D-1 Clawback Requirements.

General

The Corporation will not indemnify or provide insurance to cover any repayment of Covered Compensation in accordance with this Appendix A to the Policy.

This Appendix A is in addition to (and not in lieu of) any right of repayment, forfeiture or right of offset against any Executive Officer that is required pursuant to any other statutory repayment requirement, regardless of whether implemented at any time prior to or following the adoption of this Appendix A.


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