40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 FORM 40-F

(Check one)

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

OR

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

For the fiscal year ended December 31, 2025    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)<br><br>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<br>common share purchase rights)	CVE	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.

1,883,400,091

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

☑	Yes	☐	No

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

☑	Yes	☐	No

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

Emerging growth company ☐

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

☐

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

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

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

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

The annual report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the Registrant’s Registration Statements under the Securities Act of 1933, as amended: Form F-10 (File No. 333-291853), 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, 2025.

(b)Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2025.

(c)Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2025.

(d)Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2025.

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, 2025, 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, 2025, 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, 2025, 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, 2025, 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, Chana L. Martineau 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, Chana L. Martineau, 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, 2025, 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, 2025, 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, 2025, 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 Commitments and Obligations” in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2025, 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, Chana L. Martineau 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 19, 2026    /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, 2025.
99.2	Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2025.
99.3	Consolidated Annual Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2025.
99.4	Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2025.
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)

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

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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 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

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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.

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

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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

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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 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.

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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-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.

INTERNAL USE ONLY<br><br>LAST UPDATED NOVEMBER 1, 2023	CENOVUS ENERGY	Page 7 of #NUM_PAGES#

Document

Exhibit 99.1

Cenovus Energy Inc.

Annual Information Form

For the Year Ended December 31, 2025

February 18, 2026

(Canadian Dollars)

Annual Information Form
For the year ended December 31, 2025		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	10
DOWNSTREAM	11
CANADIAN REFINING	11
U.S. REFINING	13
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	16
DEVELOPMENT OF PROVED AND PROBABLE UNDEVELOPED RESERVES	27
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	43
AUDIT COMMITTEE	47
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	49
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	49
TRANSFER AGENTS AND REGISTRARS	49
MATERIAL CONTRACTS	50
ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER	50
INTERESTS OF EXPERTS	50
ADDITIONAL INFORMATION	50
ACCOUNTING MATTERS	51
ABBREVIATIONS AND CONVERSIONS	51
FORWARD-LOOKING INFORMATION	52
APPENDIX A — REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS	55
APPENDIX B — REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION	56
APPENDIX C — AUDIT COMMITTEE MANDATE	57

In this Annual Information Form (“AIF”), dated February 18, 2026, 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 18, 2026. 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 2025 Management’s Discussion and Analysis (“annual 2025 MD&A”). This section of the annual 2025 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 December 31, 2025 audited Consolidated Financial Statements (“Consolidated Financial Statements”), annual 2025 MD&A, annual report 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. – 2025 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 “Husky Arrangement”) under the Business Corporations Act (Alberta). In connection with the Husky 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. On November 13, 2025, Cenovus closed the acquisition of MEG Energy Corp. (“MEG”) through a plan of arrangement (the “MEG Acquisition”) under the Business Corporations Act (Alberta), pursuant to which MEG became a wholly-owned subsidiary of Cenovus.

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, 2025, are as follows:

	Percentage Owned (1)	Jurisdiction of Incorporation,<br><br>Continuance, Formation or<br><br>Organization
FCCL Partnership (“FCCL”)	100	Alberta
Sunrise Oil Sands Partnership	100	Alberta
Husky Oil Limited Partnership	100	Alberta
MEG Energy Corp. (2)	100	Alberta
Husky Marketing and Supply Company	100	Delaware
Husky Energy Marketing Partnership	100	Alberta
Cenovus Energy Marketing Services Ltd.	100	Alberta
Lima Refining Company	100	Delaware
Ohio Refining Company LLC	100	Delaware

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

(2)On January 1, 2026, Cenovus amalgamated with its wholly-owned subsidiary MEG by way of vertical short-form amalgamation.

WRB Refining LP (“WRB”) was considered a material subsidiary prior to its divestiture on September 30, 2025.

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, 2025, and (ii) less than 10 percent of the Company’s consolidated revenues for the year ended December 31, 2025. 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, 2025, or total consolidated revenues for the year ended December 31, 2025.

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. Our common shares are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”). Our cumulative redeemable preferred shares series 1 and 2 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 North America 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. – 2025 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:

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 of Directors (the “Board”) and Claude Mongeau was appointed Lead Independent Director.

•Toledo Refinery acquisition. On February 28, 2023, Cenovus closed the acquisition of the remaining 50 percent interest in the Toledo Refinery 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 common share purchase warrants (“Cenovus Warrants”), for a total of $711 million.

•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 normal course issuer bid (“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 unit (“FPSO”). Retrofit work on the SeaRose FPSO, which commenced early in 2024, was completed. The vessel returned to the field and was reconnected in the fourth quarter of 2024.

◦West White Rose. Cenovus achieved mechanical completion of the topsides and the concrete gravity structure.

◦Narrows Lake tie-back. Cenovus reached mechanical completion on the Narrows Lake pipeline to Christina Lake.

•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.

•Achieved Net Debt target. On achieving our Net Debt target of $4.0 billion in the third quarter of 2024, Cenovus increased target returns to shareholders, stewarding to 100 percent of Excess Free Funds Flow over time.

•Increased base dividend. On May 1, 2024, Cenovus increased the Company’s 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.

•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 exercised the right to redeem 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. – 2025 Annual Information Form	4

2025

•MEG Acquisition. On November 13, 2025, Cenovus completed the acquisition of MEG. Purchase consideration for the MEG Acquisition included $3.4 billion in cash partially funded through the receipt of a $2.7 billion term loan facility, and the issuance of 143.9 million Cenovus common shares with a fair value of $3.7 billion. The MEG Acquisition provides Cenovus with additional oil sands assets directly adjacent to the Company’s Christina Lake asset and are reported under our Christina Lake results.

•Growth projects.

◦West White Rose. Topsides were placed atop the concrete gravity structure and the Company completed subsea tie-ins to its existing production system at the SeaRose FPSO. Hookup and commissioning of the platform continued to progress and was substantially completed in the fourth quarter of 2025.

◦Narrows Lake tie-back. Cenovus completed commissioning of the Narrows Lake tie-back to Christina Lake and achieved first oil in the third quarter of 2025.

◦Foster Creek optimization. All major process units at the Foster Creek optimization project were brought online and the project was completed ahead of schedule.

•Divestiture of interest in WRB. On September 30, 2025, the Company divested its entire 50 percent interest in the jointly-owned Wood River and Borger refineries held through WRB (the “WRB Divestiture”) for proceeds of US$1.3 billion (C$1.9 billion) after closing adjustments.

•Debt issuances and repayments.

◦Term loan facility. The Company obtained a $2.7 billion term loan to fund a portion of the cash consideration of the MEG Acquisition. The term loan matures on February 28, 2029.

◦Senior notes offerings. On November 20, 2025, in connection with the closing of the MEG Acquisition and upcoming debt maturities, the Company closed public offerings in Canada and the U.S. of $2.6 billion of senior unsecured notes. The proceeds of the offerings were used to fund the redemption of select senior unsecured notes and for general corporate purposes.

◦Senior note repayment and redemptions. The Company repaid US$133 million in principal of senior unsecured notes due in 2025, in full, and redeemed US$973 million in principal of senior unsecured notes due in 2027 and 2029, in full, including the senior unsecured notes assumed in the MEG Acquisition. The Company also redeemed $750 million in principal of senior unsecured notes due in 2027, in full.

•Increased base dividend. On May 7, 2025, Cenovus increased the base dividend per common share from $0.180 to $0.200, or $0.800 annually, starting in the second quarter of 2025.

•Preferred share redemptions. On March 31, 2025, and June 30, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company's series 5 preferred shares and all 6.0 million of the Company's series 7 preferred shares, respectively, in each case at a price of $25.00 per share, for a total of $350 million.

•Renewal of NCIB. On November 7, 2025, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 120.3 million common shares during the period from November 11, 2025, to November 10, 2026. For the year ended December 31, 2025, the Company purchased and cancelled 89.4 million common shares.

•Update to shareholder returns framework. Upon closing of the MEG Acquisition, Cenovus adjusted its shareholder returns framework. While Net Debt is above $6.0 billion, the Company will target to return approximately 50 percent of Excess Free Funds Flow to shareholders. While Net Debt is between $6.0 billion and $4.0 billion, Cenovus will target to return approximately 75 percent of Excess Free Funds Flow to shareholders. The remainder will be allocated toward deleveraging under either scenario. The allocation of Excess Free Funds Flow to shareholder returns may be accelerated, deferred or reallocated between quarters at Management’s discretion.

Cenovus Energy Inc. – 2025 Annual Information Form	5
DESCRIPTION OF THE BUSINESS
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BUSINESS SEGMENTS

As at December 31, 2025, 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, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets, as well as Christina Lake, which includes the results of the MEG Acquisition completed in November 2025. 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 Limited (“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.

Cenovus Energy Inc. – 2025 Annual Information Form	6

•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. On September 30, 2025, Cenovus divested its entire 50 percent interest in the jointly-owned Wood River and Borger refineries held through WRB with operator Phillips 66. The U.S. Refining segment included the WRB results up to the date of divestiture. Cenovus markets its own and third-party refined products.

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, 2025, consolidated gross sales were $52.8 billion (2024 – $57.7 billion). The following table summarizes products with external sales that exceeded 15 percent of total external sales.

	2025		2024
	External Sales<br><br>($ millions)	Percent of External Sales<br><br>(percent)	External Sales<br><br>($ millions)	Percent of External Sales<br><br>(percent)
Crude Oil	20,831	39	21,711	38
Gasoline	11,874	23	14,221	25
Distillates (1)	10,592	20	12,116	21

(1)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 in Alberta and Saskatchewan; Toledo and Lima in Ohio; and Superior in 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 the U.S. Midwest Petroleum Administration of Defense District (“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.

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 the 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. – 2025 Annual Information Form	7

UPSTREAM

Oil Sands

As at December 31, 2025, Cenovus held bitumen and heavy oil rights of approximately 1.8 million gross acres (1.7 million net acres), and other petroleum and natural gas rights of approximately 3.2 million gross acres (2.9 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.

Production by Asset

	2025	2024
Bitumen and Heavy Oil Production by Asset (Mbbls/d)
Foster Creek	206.1	196.0
Christina Lake	254.3	234.2
Sunrise	53.8	49.6
Lloydminster Thermal	102.6	111.5
Lloydminster Conventional Heavy Oil	25.1	17.6
Natural Gas Production by Asset (MMcf/d)
Foster Creek	2.1	2.2
Lloydminster Conventional Heavy Oil	11.7	8.9

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.

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 operations. 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.

During the year ended December 31, 2025, Cenovus completed the MEG Acquisition. Results include the impact of the MEG Acquisition effective November 13, 2025.

Cenovus operates one 100-megawatt and two 85-megawatt natural gas-fired cogeneration facilities at Christina Lake. The steam and power generated by these facilities is used within the SAGD operations. 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. Cenovus completed the commissioning of the Narrows Lake tie-back and achieved first oil in the third quarter of 2025 from Narrows Lake, providing sustaining pad locations for production into the Christina Lake plant.

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.

Cenovus Energy Inc. – 2025 Annual Information Form	8

Lloydminster Thermal

Lloydminster thermal consists of 11 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.

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.

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

Production by Product

	2025	2024
Production by Product (1)
Light Crude Oil (2) (Mbbls/d)	5.0	5.5
NGLs (Mbbls/d)	21.2	21.1
Conventional Natural Gas (MMcf/d)	579.3	565.1

(1)Includes values attributable to Cenovus’s 30 percent equity interest in the jointly-controlled Duvernay Energy Corporation (“Duvernay”) joint venture.

(2)Light crude oil corresponds to light crude oil and medium crude oil combined as defined by National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). Cenovus does not produce medium crude oil.

Cenovus’s Conventional assets include approximately 3.9 million net acres in Alberta and British Columbia with an average working interest of 79 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. 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 100 percent working interest in a 90-megawatt natural-gas fired cogeneration facility along with multiple field facilities, compressor stations and pipelines.

Cenovus holds a 30 percent equity interest in Duvernay with the remaining interest held by Athabasca Oil Corporation.

Cenovus Energy Inc. – 2025 Annual Information Form	9

Offshore

Production by Product

	2025	2024
Production by Product
Atlantic
Terra Nova — Light Crude Oil (1) (Mbbls/d)	7.6	8.0
White Rose — Light Crude Oil (1) (Mbbls/d)	5.6	—
China
NGLs (Mbbls/d)	6.3	9.3
Conventional Natural Gas (MMcf/d)	191.8	199.5
Indonesia (2)
NGLs (Mbbls/d)	1.3	1.7
Conventional Natural Gas (MMcf/d)	87.5	85.8

(1)Light crude oil corresponds to light crude oil and medium crude oil combined as defined by NI 51-101. Cenovus does not produce medium crude oil.

(2)Includes values attributable to Cenovus’s 40 percent equity interest in HCML.

Asia Pacific

China

Liwan Gas Project

The Liwan Gas project is a deepwater natural gas development located approximately 300 kilometers southeast of Hong Kong in the Pearl River Mouth basin of the South China Sea. It includes the Liwan 3-1 and Liuhua 34-2 fields with a 49 percent working interest, and the Liuhua 29-1 field with a 75 percent working interest, with the remainder owned by China National Offshore Oil Corporation (“CNOOC”) through subsidiaries.

The three fields share a subsea production system, subsea pipeline transportation and onshore gas processing infrastructure. Cenovus operates the deepwater infrastructure, while 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 and compresses NGLs to transport the natural gas to commercial markets in mainland China.

Block 29/34 and Block 15/33

Cenovus holds the production sharing contract (“PSC”) for exploration Block 29/34, which is adjacent to the Liuhua 34-2 Production Area, located in the South China Sea.

During the exploration phase, Cenovus operates Block 29/34 with a 100 percent working interest. Upon commercial discovery, CNOOC may acquire up to a 51 percent working interest during the development and production phases by funding its proportionate share of all development costs. As at December 31, 2025, Block 29/34 was in the exploration phase and under evaluation.

Cenovus held the PSC for exploration block 15/33, located in the Pearl River Mouth Basin of the South China Sea and was the operator of Block 15/33 with a 100 percent working interest as at December 31, 2025. On January 12, 2026, Cenovus divested its entire interest in Block 15/33.

Block DW-1, Taiwan Area

The Company and CPC Corporation have rights to Block DW-1 through a joint agreement. The block covers approximately 7,700 square kilometres and is located offshore of the southwest Taiwan Area. Cenovus holds a 75 percent working interest during exploration. CPC Corporation may participate in future development programs up to a 50 percent working interest by funding its proportionate share of all development costs. The current exploration period expires on December 17, 2027.

Indonesia

Madura Strait

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

The Madura Strait PSC operates four producing shallow water fields, namely BD, MDA, MBH and MAC, and contains shallow water MDK and MBF fields, which may be developed in the future depending on gas demand and project economics.

Cenovus Energy Inc. – 2025 Annual Information Form	10

Liman

Located onshore in East Java, Indonesia, the Company holds a 100 percent working interest in the Liman contract area during the exploration phase. In December 2025, Cenovus sent a letter of relinquishment to the Government of Indonesia with plans to relinquish the contract area.

Atlantic Canada

Terra Nova Field

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 areas: Graben, East Flank and Far East. Cenovus has a 34 percent working interest and Suncor Energy Inc. is the operator.

White Rose Field and Satellite Extensions

Located 350 kilometres offshore Newfoundland and Labrador on the eastern flank of the Jeanne d’Arc Basin, Cenovus operates 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 that will produce back to the SeaRose FPSO. The West White Rose project is anticipated to have peak production of 80.0 thousand barrels per day (Cenovus’s working interest share — 45.0 thousand barrels per day).

In 2025, the topsides were placed atop the concrete gravity structure and the subsea tie-ins to the existing production system were completed. The remainder of the platform hookup and commissioning work was substantially completed in the fourth quarter of 2025.

East Coast Exploration

The Company holds working interests ranging from six percent to 100 percent in multiple discovery areas. As at December 31, 2025, Cenovus held a 72.5 percent working interest in an exploration licence within the Jeanne d’Arc Basin that expired in January 2026.

DOWNSTREAM

Canadian Refining

The following table summarizes key operational results at the Lloydminster Upgrader and Lloydminster Refinery:

	2025	2024
Operable Capacity (Mbbls/d)	108.0	108.0
Total Processed Inputs (1) (Mbbls/d)	119.4	96.6
Crude Oil Unit Throughput (Mbbls/d)	110.7	90.5
Crude Unit Utilization (percent)	103	84
Total Production (2) (Mbbls/d)	127.3	103.1
Synthetic Crude Oil	52.0	41.0
Asphalt	17.9	15.7
Diesel	15.2	10.8
Other	37.2	30.8
Ethanol	5.0	4.8

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

(2)Results reflect operations at the Lloydminster Upgrader, Lloydminster Refinery and the ethanol plants.

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 owned by Cenovus. The Lloydminster Upgrader produces synthetic crude oil HSB, ultra-low sulphur diesel and other ancillary products. Diesel is transported via railcar and truck, and HSB is sold via pipeline into the primary markets in Canada. Synthetic crude oil is sold into the Alberta market or used as refinery feedstock in the U.S. Refining segment. In addition, the Lloydminster 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.

Cenovus Energy Inc. – 2025 Annual Information Form	11

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 sold directly as industrial products or transferred to the Lloydminster Upgrader and further refined into diesel or the HSB stream. 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. The Lloydminster Refinery has a working tank capacity of 1.5 million barrels.

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 the following four asphalt terminals:

Location	Storage Capacity (Mbbls)
Winnipeg, Manitoba	115.0
Yorkton, Saskatchewan	60.0
Kamloops, British Columbia	45.0
Edmonton, Alberta	35.0

The Company also owns an emulsion plant located in Saskatoon, Saskatchewan (storage capacity – 5.0 thousand barrels).

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 13.4 thousand barrels per day in 2025 (2024 – 12.5 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 130.0 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. The Company continues to evaluate the viability of a carbon capture and sequestration project to achieve lower carbon intensity ethanol production at the Minnedosa ethanol plant.

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, 2025:

	British<br><br>Columbia	Alberta	Saskatchewan	Manitoba	Ontario	Quebec	Nova Scotia	Total
Cardlocks	17	21	2	6	16	1	1	64
Bulk Plants	3	6	2	1	—	—	—	12
Travel Centres	12	15	3	3	19	—	—	52
Total	32	42	7	10	35	1	1	128		Cenovus Energy Inc. – 2025 Annual Information Form	12
---	---

U.S. Refining

The following table summarizes key operational results for the U.S. Refining segment:

	2025	2024
Operable Capacity (1) (Mbbls/d)	549.9	612.3
Total Processed Inputs (2) (Mbbls/d)	548.1	581.4
Crude Oil Unit Throughput (Mbbls/d)	515.9	556.4
Heavy Crude Oil	197.9	219.6
Light/Medium Crude Oil	318.0	336.8
Crude Unit Utilization (1) (percent)	94	91
Total Production (Mbbls/d)	559.9	590.0
Gasoline	266.7	280.5
Distillates (3)	195.3	209.1
Asphalt	23.9	28.3
Other	74.0	72.1

(1)For the year ended December 31, 2025, reported operable capacity and crude unit utilization reflects the weighted average impact of the WRB Divestiture, which closed on September 30, 2025.

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

(3)Includes diesel and jet fuel.

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. 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. 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

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”) and Access Western Blend (“AWB”) produced at Christina Lake and CLB produced at Foster Creek, in addition to other third-party high TAN crude oil. The refinery also processes HSB produced at the Lloydminster Upgrader. Crude oil feedstocks are received via the Mid-Valley, Marathon and Enbridge Mainline Pipelines. The refinery produces gasoline, diesel, jet fuel and other products. 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 and Canada.

Various amounts of feedstocks, intermediates and finished products can be transferred between the Lima and Toledo refineries, allowing for better optimization of both assets.

Superior Refinery

The Superior Refinery is located in Superior, Wisconsin, approximately 250 kilometres northeast of Minneapolis, Minnesota. 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, 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 region and to local areas via trucks that are loaded at the Superior Terminal and Duluth Products Terminal. Asphalt is loaded at the Superior rail and truck loading facilities, and transported to markets in various U.S. states.

Non-Operated Wood River and Borger Refineries

On September 30, 2025, Cenovus closed the WRB Divestiture, selling its 50 percent interest in WRB, which held the Wood River and Borger refineries.

Cenovus Energy Inc. – 2025 Annual Information Form	13

Storage and Distribution Network

The Company has refined product storage and an asphalt distribution network composed of five terminals. The Superior Products Terminal in Superior, Wisconsin (where refined products are unloaded) and the following:

Terminal	Location	Storage Capacity (Mbbls)
Duluth Products	Duluth/Esko, Minnesota	180.0
Rhinelander Asphalt	Rhinelander, Wisconsin	157.0
Crookston Asphalt	Crookston, Minnesota	136.0
Duluth Marine	Duluth, Minnesota	14.0

The Superior Refinery controls the maintenance and performance of these five terminals and has a working tank capacity of 2.5 million barrels. The Company also markets fuels, asphalt and marine fuel from independently operated terminals located in the states of Minnesota, Wisconsin, Ohio and Colorado.

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 2025 MD&A, which 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 2025 MD&A, which 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, 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 sustainability 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. Ethics and compliance training is delivered to staff based on role, and others as needed. 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 Cenovus’s Ethics & Compliance team, Legal team or 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.

Cenovus Energy Inc. – 2025 Annual Information Form	14

The Human Rights Policy formalizes our commitment to human rights, guided by the principles of the United Nations 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 acceptance and belonging goals, as well as information about safety performance and approach to governance.

The CSR report differs from previous Environmental, Social and Governance reports published by the Company in that it does not include information regarding Cenovus’s environmental performance and plans due to changes to Canada’s Competition Act in June 2024.

EMPLOYEES

The following table summarizes Cenovus’s full-time equivalent (“FTE”) employees:

As at December 31,	2025
Upstream Operations	3,163
Downstream Operations	2,286
Corporate (1)	1,762
Total FTE Employees	7,211

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

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 2025 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 2025 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 NI 51-101.

As at December 31, 2025, 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 95 percent of Cenovus’s total proved reserves located in Canada (in Alberta, Saskatchewan, and Newfoundland and Labrador), China and Indonesia. GLJ evaluated approximately five percent of the Company’s total proved reserves, located in Alberta and British Columbia, Canada.

The Safety, Sustainability and Reserves Committee (“SSR”) composed entirely of independent directors reviews, among other things, the qualifications and appointment of the IQREs, the procedures for providing information to the IQREs and the procedures relating to the disclosure of information with respect to oil and gas activities. The SSR 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.

Cenovus Energy Inc. – 2025 Annual Information Form	15

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. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. 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. Readers should review the definitions and information contained in Additional Notes to Data Tables and Other Oil and Gas Information, Definitions and Pricing Assumptions sections in conjunction with the reserves disclosure. For additional information, see the section entitled Risk Management and Risk Factors in the Company’s annual 2025 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 17, 2026, with an effective date of December 31, 2025. McDaniel’s and GLJ’s preparation dates of the information are January 19, 2026, and January 6, 2026, 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. Estimates of FNR have been presented on a before and after income tax basis.

Additional Notes to Data Tables and Other Oil and Gas Information

•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 provisions for interest and general and administrative expenses.

•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).

•Unless otherwise indicated, Canada includes values attributable to Cenovus’s 30 percent equity interest in Duvernay and Indonesia includes values attributable to Cenovus’s 40 percent equity interest in HCML. 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 income 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.

Cenovus Energy Inc. – 2025 Annual Information Form	16

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.

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 ERCE and is used to estimate FNR associated with the reserves disclosed herein. This forecast is dated January 1, 2026. The inflation forecast was applied uniformly to prices beyond the forecast interval and to all future costs. For historical prices realized during the year ended December 31, 2025, see the Production History and Per-Unit Results section in this AIF.

	Crude Oil and NGLs					Natural Gas
Year	WTI Cushing Oklahoma<br><br>(US$/bbl)	Edmonton Par Price 40 API<br><br>(C$/bbl)	Western Canadian Select<br><br>(C$/bbl)	Edmonton C5+<br><br>(C$/bbl)	Brent<br><br>(US$/bbl)	AECO<br><br>(C$/MMBtu)	China (1)<br><br>(US$/Mcf)	Indonesia (1)<br><br>(US$/Mcf)	Inflation Rate<br><br>(%/year)	Exchange Rate<br><br>(US$/C$)
2026	59.92	77.54	65.13	80.01	63.92	3.00	8.52	7.34	0.0	0.7275
2027	65.10	83.60	70.43	86.19	69.13	3.30	8.89	7.44	2.0	0.7367
2028	70.28	90.17	76.90	92.83	74.36	3.49	9.03	7.57	2.0	0.7400
2029	71.93	92.32	78.71	95.04	76.10	3.58	8.99	7.70	2.0	0.7400
2030	73.37	94.17	80.29	96.94	77.62	3.65	8.81	7.83	2.0	0.7400
2031	74.84	96.06	81.90	98.89	79.17	3.72	8.97	7.97	2.0	0.7400
2032	76.34	97.98	83.53	100.86	80.76	3.80	9.43	8.04	2.0	0.7400
2033	77.87	99.93	85.20	102.88	82.37	3.88	9.70	—	2.0	0.7400
2034	79.42	101.93	86.91	104.94	84.02	3.95	—	—	2.0	0.7400
2035	81.01	103.97	88.65	107.04	85.70	4.03	—	—	2.0	0.7400
2036	82.63	106.05	90.42	109.18	87.41	4.11	—	—	2.0	0.7400
2037+	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	—	—	2.0	0.7400

(1)Prices derived from natural gas sales agreements are used to estimate the FNR related to conventional natural gas reserves in China and Indonesia.

Cenovus Energy Inc. – 2025 Annual Information Form	17

Summary of Oil and Gas Reserves as at December 31, 2025

Gross Reserves	Bitumen<br><br>(MMbbls)	Light and Medium Oil<br><br>(MMbbls)	NGLs<br><br>(MMbbls)	Conventional<br><br>Natural Gas<br><br>(Bcf)	Total<br><br>(MMBOE)
Canada
Proved
Developed Producing	1,143	21	39	1,071	1,381
Developed Non-Producing	23	1	1	31	31
Undeveloped	4,531	65	10	339	4,662
Total Proved	5,697	87	50	1,441	6,074
Probable	3,227	71	24	754	3,448
Total Proved Plus Probable	8,924	158	74	2,196	9,522
China
Proved
Developed Producing	—	—	8	195	41
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	8	195	41
Probable	—	—	3	72	15
Total Proved Plus Probable	—	—	11	267	55
Indonesia
Proved
Developed Producing	—	—	1	109	19
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	1	109	19
Probable	—	—	1	51	9
Total Proved Plus Probable	—	—	2	160	29
Total Company
Proved
Developed Producing	1,143	21	48	1,375	1,441
Developed Non-Producing	23	1	1	31	31
Undeveloped	4,531	65	10	339	4,662
Total Proved	5,697	87	59	1,745	6,135
Probable	3,227	71	28	878	3,472
Total Proved Plus Probable	8,924	158	87	2,622	9,607
Cenovus Energy Inc. – 2025 Annual Information Form	18
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Net Reserves	Bitumen<br><br>(MMbbls)	Light and Medium Oil<br><br>(MMbbls)	NGLs<br><br>(MMbbls)	Conventional<br><br>Natural Gas<br><br>(Bcf)	Total<br><br>(MMBOE)
---	---	---	---	---	---
Canada
Proved
Developed Producing	892	20	34	1,004	1,113
Developed Non-Producing	18	1	1	29	25
Undeveloped	3,524	63	8	312	3,646
Total Proved	4,434	83	43	1,345	4,784
Probable	2,353	61	20	689	2,548
Total Proved Plus Probable	6,787	144	63	2,033	7,333
China
Proved
Developed Producing	—	—	7	184	38
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	7	184	38
Probable	—	—	2	68	14
Total Proved Plus Probable	—	—	9	253	52
Indonesia
Proved
Developed Producing	—	—	1	78	14
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	—	—	1	78	14
Probable	—	—	—	29	5
Total Proved Plus Probable	—	—	1	106	19
Total Company
Proved
Developed Producing	892	20	42	1,266	1,165
Developed Non-Producing	18	1	1	29	25
Undeveloped	3,524	63	8	312	3,646
Total Proved	4,434	83	51	1,607	4,836
Probable	2,353	61	22	786	2,567
Total Proved Plus Probable	6,787	144	74	2,392	7,403
Cenovus Energy Inc. – 2025 Annual Information Form	19
---	---

Summary of Net Present Value of Future Net Revenue as at December 31, 2025

	Discounted at % per year					Unit Value Discounted at 10% (1)
Before Income Taxes ($ millions)	0%	5%	10%	15%	20%	$/BOE
Canada
Proved
Developed Producing	24,298	25,654	23,783	21,762	19,966	21.37
Developed Non-Producing	835	697	593	515	453	24.01
Undeveloped	138,450	64,256	35,381	21,954	14,762	9.70
Total Proved	163,584	90,607	59,757	44,231	35,181	12.49
Probable	146,848	45,141	21,170	13,200	9,583	8.31
Total Proved Plus Probable	310,432	135,748	80,927	57,432	44,763	11.04
China
Proved
Developed Producing	1,977	1,800	1,653	1,529	1,425	43.57
Developed Non-Producing	—	—	—	—	—	—
Undeveloped	—	—	—	—	—	—
Total Proved	1,977	1,800	1,653	1,529	1,425	43.57
Probable	857	707	594	506	438	43.52
Total Proved Plus Probable	2,834	2,507	2,246	2,036	1,862	43.55
Indonesia
Proved
Developed Producing	324	294	269	248	230	19.32
Developed Non-Producing	—	—	—	—	—	—
Undeveloped	—	—	—	—	—	—
Total Proved	324	294	269	248	230	19.32
Probable	239	196	164	139	120	32.17
Total Proved Plus Probable	563	490	433	387	349	22.77
Total Company
Proved
Developed Producing	26,600	27,748	25,705	23,539	21,620	22.07
Developed Non-Producing	835	697	593	515	453	24.01
Undeveloped	138,450	64,256	35,381	21,954	14,762	9.70
Total Proved	165,885	92,701	61,679	46,008	36,835	12.75
Probable	147,944	46,044	21,928	13,846	10,140	8.54
Total Proved Plus Probable	313,829	138,745	83,607	59,854	46,975	11.29

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

Cenovus Energy Inc. – 2025 Annual Information Form	20
	Discounted at % per year
---	---	---	---	---	---
After Income Taxes (1) ($ millions)	0%	5%	10%	15%	20%
Canada
Proved
Developed Producing	19,263	21,246	19,837	18,181	16,680
Developed Non-Producing	686	567	479	412	361
Undeveloped	106,654	48,776	26,417	16,101	10,620
Total Proved	126,602	70,588	46,732	34,694	27,660
Probable	112,479	34,247	16,011	9,979	7,242
Total Proved Plus Probable	239,081	104,835	62,743	44,673	34,902
China
Proved
Developed Producing	1,546	1,405	1,288	1,189	1,106
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	1,546	1,405	1,288	1,189	1,106
Probable	652	537	450	383	330
Total Proved Plus Probable	2,198	1,941	1,737	1,572	1,436
Indonesia
Proved
Developed Producing	214	194	178	164	152
Developed Non-Producing	—	—	—	—	—
Undeveloped	—	—	—	—	—
Total Proved	214	194	178	164	152
Probable	153	126	106	90	78
Total Proved Plus Probable	367	320	284	254	230
Total Company
Developed Producing	21,023	22,845	21,302	19,534	17,938
Developed Non-Producing	686	567	479	412	361
Undeveloped	106,654	48,776	26,417	16,101	10,620
Total Proved	128,362	72,187	48,197	36,047	28,918
Probable	113,284	34,910	16,566	10,452	7,650
Total Proved Plus Probable	241,646	107,096	64,763	46,499	36,568

(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, 2025.

Cenovus Energy Inc. – 2025 Annual Information Form	21

Total Undiscounted Future Net Revenue as at December 31, 2025

($ 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	462,382	102,452	131,968	51,119	13,260	163,584	36,981	126,602
Total Proved Plus Probable	814,922	194,998	209,248	85,641	14,603	310,432	71,351	239,081
China
Total Proved	3,011	231	673	79	51	1,977	431	1,546
Total Proved Plus Probable	4,105	315	820	85	52	2,834	636	2,198
Indonesia
Total Proved	1,237	348	530	—	35	324	110	214
Total Proved Plus Probable	1,873	649	626	—	36	563	196	367
Total Company
Total Proved	466,630	103,031	133,170	51,199	13,346	165,885	37,523	128,362
Total Proved Plus Probable	820,900	195,962	210,693	85,726	14,691	313,829	72,183	241,646

(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, 2025

Reserves Category	Product Types	Future Net Revenue Before Income Taxes Discounted at 10% per Year<br><br>($ millions)	Unit Value<br><br>Discounted at 10% per Year (1)<br><br>($/BOE)
Total Proved	Bitumen	58,272	13.14
	Light and Medium Oil (2)	1,165	10.30
	Conventional Natural Gas (3)	2,242	7.75
	Total	61,679	12.75
Total Proved Plus	Bitumen	76,102	11.21
Probable	Light and Medium Oil (2)	3,837	20.63
	Conventional Natural Gas (3)	3,668	8.52
	Total	83,607	11.29

(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. – 2025 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)	2026	2027	2028	2029	2030	Remainder	Total
Canada
Total Proved	2,896	2,827	2,363	2,432	2,131	38,472	51,119
Total Proved Plus Probable	3,025	2,950	2,690	2,370	2,284	72,322	85,641
China
Total Proved	55	14	5	5	—	—	79
Total Proved Plus Probable	55	14	5	5	6	—	85
Indonesia
Total Proved	—	—	—	—	—	—	—
Total Proved Plus Probable	—	—	—	—	—	—	—
Total Company
Total Proved	2,951	2,840	2,368	2,437	2,131	38,472	51,199
Total Proved Plus Probable	3,080	2,963	2,696	2,376	2,289	72,322	85,726

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. – 2025 Annual Information Form	23

Reserves Reconciliation as at December 31, 2025

Gross Reserves, Total Proved	Bitumen<br><br>(MMbbls)	Light and Medium Oil<br><br>(MMbbls)	NGLs<br><br>(MMbbls)	Conventional<br><br>Natural Gas<br><br>(Bcf)	Total<br><br>(MMBOE)
Canada
As at December 31, 2024	5,179	91	57	1,560	5,587
Extensions and Improved Recovery	277	5	6	206	321
Discoveries	—	—	—	—	—
Technical Revisions	(177)	(1)	(4)	(98)	(200)
Economic Factors	(1)	(1)	(1)	(14)	(5)
Acquisitions	678	—	—	5	679
Dispositions	(24)	—	—	—	(24)
Production (1)	(234)	(7)	(8)	(217)	(285)
As at December 31, 2025	5,697	87	50	1,441	6,074
China
As at December 31, 2024	—	—	9	236	49
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	1	28	6
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(2)	(70)	(14)
As at December 31, 2025	—	—	8	195	41
Indonesia
As at December 31, 2024	—	—	3	154	29
Extensions and Improved Recovery	—	—	—	5	1
Discoveries	—	—	—	—	—
Technical Revisions	—	—	(2)	(18)	(5)
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	(32)	(6)
As at December 31, 2025	—	—	1	109	19
Total Company
As at December 31, 2024	5,179	91	69	1,950	5,664
Extensions and Improved Recovery	277	5	6	211	322
Discoveries	—	—	—	—	—
Technical Revisions	(177)	(1)	(5)	(88)	(198)
Economic Factors	(1)	(1)	(1)	(14)	(5)
Acquisitions	678	—	—	5	679
Dispositions	(24)	—	—	—	(24)
Production (1)	(234)	(7)	(11)	(319)	(305)
As at December 31, 2025	5,697	87	59	1,745	6,135
Cenovus Energy Inc. – 2025 Annual Information Form	24
---	---
Gross Reserves, Probable	Bitumen<br><br>(MMbbls)	Light and Medium Oil<br><br>(MMbbls)	NGLs<br><br>(MMbbls)	Conventional<br><br>Natural Gas<br><br>(Bcf)	Total<br><br>(MMBOE)
---	---	---	---	---	---
Canada
As at December 31, 2024	2,500	77	34	942	2,767
Extensions and Improved Recovery	(22)	2	3	128	4
Discoveries	—	—	—	—	—
Technical Revisions	(46)	(7)	(12)	(313)	(118)
Economic Factors	—	—	—	(3)	(1)
Acquisitions	804	—	—	1	804
Dispositions	(9)	—	—	—	(9)
Production (1)	—	—	—	—	—
As at December 31, 2025	3,227	71	24	754	3,448
China
As at December 31, 2024	—	—	3	83	17
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	—	(11)	(2)
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	—	—
As at December 31, 2025	—	—	3	72	15
Indonesia
As at December 31, 2024	—	—	1	47	9
Extensions and Improved Recovery	—	—	—	4	1
Discoveries	—	—	—	—	—
Technical Revisions	—	—	—	1	—
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	—	—
As at December 31, 2025	—	—	1	51	9
Total Company
As at December 31, 2024	2,500	77	37	1,071	2,793
Extensions and Improved Recovery	(22)	2	3	131	4
Discoveries	—	—	—	—	—
Technical Revisions	(46)	(7)	(12)	(323)	(120)
Economic Factors	—	—	—	(3)	(1)
Acquisitions	804	—	—	1	804
Dispositions	(9)	—	—	—	(9)
Production (1)	—	—	—	—	—
As at December 31, 2025	3,227	71	28	878	3,472
Cenovus Energy Inc. – 2025 Annual Information Form	25
---	---
Gross Reserves, Total Proved Plus Probable	Bitumen<br><br>(MMbbls)	Light and Medium Oil<br><br>(MMbbls)	NGLs<br><br>(MMbbls)	Conventional<br><br>Natural Gas<br><br>(Bcf)	Total<br><br>(MMBOE)
---	---	---	---	---	---
Canada
As at December 31, 2024	7,679	168	90	2,501	8,354
Extensions and Improved Recovery	255	6	9	333	325
Discoveries	—	—	—	—	—
Technical Revisions	(223)	(9)	(17)	(411)	(318)
Economic Factors	(1)	—	(1)	(17)	(5)
Acquisitions	1,482	—	—	6	1,483
Dispositions	(32)	—	—	—	(32)
Production (1)	(234)	(7)	(8)	(217)	(285)
As at December 31, 2025	8,924	158	74	2,196	9,522
China
As at December 31, 2024	—	—	12	319	65
Extensions and Improved Recovery	—	—	—	—	—
Discoveries	—	—	—	—	—
Technical Revisions	—	—	1	18	4
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	(2)	(70)	(14)
As at December 31, 2025	—	—	11	267	55
Indonesia
As at December 31, 2024	—	—	4	200	38
Extensions and Improved Recovery	—	—	—	9	1
Discoveries	—	—	—	—	—
Technical Revisions	—	—	(2)	(17)	(4)
Economic Factors	—	—	—	—	—
Acquisitions	—	—	—	—	—
Dispositions	—	—	—	—	—
Production	—	—	—	(32)	(6)
As at December 31, 2025	—	—	2	160	29
Total Company
As at December 31, 2024	7,679	168	107	3,021	8,457
Extensions and Improved Recovery	255	6	9	342	327
Discoveries	—	—	—	—	—
Technical Revisions	(223)	(9)	(17)	(410)	(318)
Economic Factors	(1)	—	(1)	(17)	(5)
Acquisitions	1,482	—	—	6	1,483
Dispositions	(32)	—	—	—	(32)
Production (1)	(234)	(7)	(11)	(319)	(305)
As at December 31, 2025	8,924	158	87	2,622	9,607

(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. – 2025 Annual Information Form	26

The following developments occurred in 2025 compared with 2024:

•Bitumen gross total proved and gross total proved plus probable reserves increased by 518 million barrels and 1,245 million barrels, respectively. The changes were due to the MEG Acquisition, 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. These increases were partially offset by current year production and negative technical revisions resulting from recovery factor changes at Christina Lake and Foster Creek, and a minor disposition at Lloydminster thermal.

•Light and medium oil gross total proved and gross total proved plus probable reserves decreased by four million barrels and 10 million barrels, respectively. The changes were due to current year production and negative technical revisions due to updates to the Conventional segment development plans. These decreases were partially offset by extensions due to updates to the Conventional segment development plans.

•NGLs gross total proved and gross total proved plus probable reserves decreased by 10 million barrels and 20 million barrels, respectively. The changes were due to current year production, negative technical revisions due to updates to the Conventional segment development plans and negative technical revisions due to reductions to recovery performance in Indonesia. These reductions were partially offset by extensions due to updates to the Conventional segment development plans and technical revisions due to improvements to recovery performance in China.

•Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 205 billion cubic feet and 399 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 negative technical revisions due to reductions to recovery performance in Indonesia. 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 in China and minor acquisitions in the Conventional segment.

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<br><br>(MMbbls)		Light and Medium Oil<br><br>(MMbbls)		NGLs<br><br>(MMbbls)		Conventional<br><br>Natural Gas<br><br>(Bcf)		Total<br><br>(MMBOE)
	First<br><br>Attributed	Total	First<br><br>Attributed	Total	First<br><br>Attributed	Total	First<br><br>Attributed	Total	First<br><br>Attributed	Total
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
2025	660	4,531	3	65	4	10	156	339	693	4,662

Probable Undeveloped (Gross Reserves)

	Bitumen<br><br>(MMbbls)		Light and Medium Oil<br><br>(MMbbls)		NGLs<br><br>(MMbbls)		Conventional<br><br>Natural Gas<br><br>(Bcf)		Total<br><br>(MMBOE)
	First<br><br>Attributed	Total	First<br><br>Attributed	Total	First<br><br>Attributed	Total	First<br><br>Attributed	Total	First<br><br>Attributed	Total
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
2025	774	3,012	2	64	5	15	185	492	812	3,173

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 4,531 million barrels account for approximately 80 percent of the Company’s total gross proved bitumen reserves. Of Cenovus’s 3,227 million barrels of gross probable bitumen reserves, 3,012 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.

Cenovus Energy Inc. – 2025 Annual Information Form	27

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. 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 21 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 are advanced 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, costs, economic conditions, regulatory changes, historical performance and other factors. 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 2025 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. – 2025 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, 2025:

Producing Wells

	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Canada
Oil Sands (1)	3,055	2,928	341	290	3,396	3,218
Conventional (2)	597	428	3,745	2,928	4,342	3,356
Offshore – Atlantic (3)	38	18	—	—	38	18
	3,690	3,374	4,086	3,218	7,776	6,592
International (4)
Offshore – China	—	—	17	10	17	10
Offshore – Indonesia	—	—	13	5	13	5
	—	—	30	15	30	15
Total	3,690	3,374	4,116	3,233	7,806	6,607

(1)Includes 2,193 gross producing wells (2,052 net producing wells) located in Alberta and 1,203 gross producing wells (1,166 net producing wells) located in Saskatchewan.

(2)Includes 3,857 gross producing wells (2,941 net producing wells) located in Alberta and 485 gross producing wells (415 net producing wells) located in British Columbia.

(3)Atlantic wells are located in Newfoundland and Labrador.

(4)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)	7,886	7,163	932	809	8,818	7,972
Conventional (3)	537	467	1,483	1,173	2,020	1,640
Offshore – Atlantic (4)	3	2	—	—	3	2
	8,426	7,632	2,415	1,982	10,841	9,614
International
Offshore – China	—	—	—	—	—	—
Offshore – Indonesia (5)	—	—	1	—	1	—
	—	—	1	—	1	—
Total	8,426	7,632	2,416	1,982	10,842	9,614

(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 3,405 gross non-producing wells (2,986 net non-producing wells) located in Alberta and 5,413 gross non-producing wells (4,986 net non-producing wells) located in Saskatchewan.

(3)Includes 1,886 gross non-producing wells (1,539 net non-producing wells) located in Alberta, 97 gross non-producing wells (69 net non-producing wells) located in British Columbia, 36 gross non-producing wells (31 net non-producing wells) located in Saskatchewan and 1 gross non-producing wells (1 net non-producing wells) in Manitoba.

(4)Atlantic wells are located in Newfoundland and Labrador.

(5)Indonesia wells are located in the Madura Strait BD field.

Cenovus Energy Inc. – 2025 Annual Information Form	29

Exploration and Development Activity

The following tables summarizes Cenovus’s gross and net interest in wells drilled in 2025:

					Offshore (1)
	Oil Sands (2) (3)		Conventional (1) (2)		Atlantic (2)		China		Indonesia		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Crude Oil	419	419	24	20	—	—	—	—	—	—	443	439
Natural Gas	—	—	36	33	—	—	—	—	—	—	36	33
Total	419	419	60	53	—	—	—	—	—	—	479	472

(1)No exploration wells were drilled in the Conventional and Offshore segments.

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

(3)Includes 63 exploration wells drilled in the Oil Sands segment.

During the year ended December 31, 2025, the Company drilled 144 gross stratigraphic test wells (144 net wells), 91 gross observation wells (91 net wells) and 88 gross conventional heavy oil wells (88 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, 2025, 96 gross SAGD well pairs were drilled (96 net well pairs).

During the year ended December 31, 2025, six service wells were drilled in the Oil Sands segment. No service wells or stratigraphic test wells were drilled in the Conventional segment in 2025. No dry holes were drilled in the Oil Sands, Conventional and Offshore segments in 2025.

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 across the Oil Sands segment and the production and de-risking of resource potential for the Conventional segment properties.

Properties With No Attributed Reserves

The following table summarizes Cenovus’s unproved acreage as at December 31, 2025:

(thousands of acres)	Gross	Net
Canada	9,222	7,961
China	1,923	1,440
Indonesia	616	246
Total	11,761	9,647

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 326,054 unproved net acres in Canada that may expire by December 31, 2026, which relate entirely to Crown and freehold properties. The Oil Sands and Conventional segments include 188,579 unproved net acres and the remaining 137,475 unproved net acres relate to an exploration licence in the Offshore segment, which expired in January 2026. There are no expiries for China or Indonesia within the next year.

The Company has a liability of approximately $3 million related to exploration licences in the Atlantic region. The Company has commitments totalling approximately $34 million related to exploration to be completed in China on timelines to be agreed with CNOOC.

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

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 Energy Inc. – 2025 Annual Information Form	30

Cenovus has estimated undiscounted and uninflated future abandonment and reclamation costs for its existing upstream assets of approximately $7.7 billion (approximately $3.2 billion, discounted at 10 percent) as at December 31, 2025, of which the Company expects to pay $590 million in the next three years. Estimated future abandonment and reclamation costs and payment excludes values 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, 2025, $256 million (December 31, 2024 – $241 million) was deposited in restricted accounts in the Company’s Consolidated Financial Statements.

Of the undiscounted future abandonment and reclamation costs to be incurred over the life of Cenovus’s total proved reserves, approximately $13.3 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 2026 guidance dated December 10, 2025, and available on the Company’s website at cenovus.com, the Company expects to pay cash taxes of $1.0 billion to $1.3 billion in 2026. This estimate could vary significantly if underlying assumptions change with respect to commodity prices, capital spending levels, and acquisition and disposition transactions.

Costs Incurred

($ millions)	Canada	China	Indonesia	2025
Acquisitions
Unproved	174	—	—	174
Proved	9,990	—	—	9,990
Total Acquisitions	10,164	—	—	10,164
Exploration Costs	87	—	—	87
Development Costs	4,179	86	—	4,265
Total Costs Incurred	14,430	86	—	14,516
($ millions)	Canada	China	Indonesia	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

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, 2025.

Cenovus Energy Inc. – 2025 Annual Information Form	31

Production Estimates

The following table summarizes the 2026 estimated gross production of Cenovus’s gross reserves for all properties held on December 31, 2025, 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 acquisitions or divestitures.

	Total Proved	Total Proved Plus Probable
Canada
Bitumen (1) (Mbbls/d)	745.6	775.6
Light and Medium Oil (Mbbls/d)	29.9	35.5
NGLs (Mbbls/d)	19.4	20.8
Conventional Natural Gas (MMcf/d)	556.4	597.3
Total (MBOE/d)	887.7	931.5
China
NGLs (Mbbls/d)	7.9	8.6
Conventional Natural Gas (MMcf/d)	168.0	182.6
Total (MBOE/d)	35.9	39.0
Indonesia
NGLs (Mbbls/d)	0.8	1.1
Conventional Natural Gas (MMcf/d)	76.8	83.0
Total (MBOE/d)	13.6	14.9
Total Company
Bitumen (1) (Mbbls/d)	745.6	775.6
Light and Medium Oil (Mbbls/d)	29.9	35.5
NGLs (Mbbls/d)	28.2	30.5
Conventional Natural Gas (MMcf/d)	801.2	862.8
Total (1) (MBOE/d)	937.2	985.4

(1)Includes Foster Creek production of 217.6 thousand barrels per day for total proved and 224.2 thousand barrels per day for total proved plus probable, and Christina Lake production of 354.1 thousand barrels per day for total proved and 365.1 thousand barrels per day for total proved plus probable.

Cenovus Energy Inc. – 2025 Annual Information Form	32

Production History and Per-Unit Results

	2025	Q4	Q3	Q2	Q1
Canada
Bitumen
Foster Creek	206.1	220.1	215.4	186.1	202.7
Christina Lake	254.3	308.9	251.7	217.9	237.8
Sunrise	53.8	60.3	52.4	50.3	52.1
Lloydminster Thermal	102.6	106.9	95.7	97.8	109.9
Lloydminster Conventional Heavy Oil	25.1	28.1	25.4	25.0	21.8
Total Bitumen (1) (Mbbls/d)	641.9	724.3	640.6	577.1	624.3
Light and Medium Oil (Mbbls/d)	18.1	22.3	16.3	17.0	16.8
NGLs (Mbbls/d)	21.2	20.8	23.0	20.4	20.5
Conventional Natural Gas (MMcf/d)	593.1	579.0	606.9	585.7	600.7
Total (MBOE/d)	780.0	863.9	781.0	712.1	761.7
China
NGLs (Mbbls/d)	6.3	5.8	3.1	7.9	8.8
Conventional Natural Gas (MMcf/d)	191.8	195.8	192.5	179.7	199.0
Total (MBOE/d)	38.3	38.4	35.2	37.9	42.0
Indonesia
NGLs (Mbbls/d)	1.3	1.3	1.7	1.6	0.5
Conventional Natural Gas (MMcf/d)	87.5	85.6	90.1	86.0	88.2
Total (MBOE/d)	15.9	15.6	16.7	15.9	15.2
Total Company
Bitumen (1) (Mbbls/d)	641.9	724.3	640.6	577.1	624.3
Light and Medium Oil (Mbbls/d)	18.1	22.3	16.3	17.0	16.8
NGLs (Mbbls/d)	28.8	27.9	27.8	29.9	29.8
Conventional Natural Gas (MMcf/d)	872.4	860.4	889.5	851.4	887.9
Total (1) (MBOE/d)	834.2	917.9	832.9	765.9	818.9

(1)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. Netback per barrel of oil equivalent contains a non-GAAP measure. Netbacks per barrel of oil equivalent reflect our margin on a per-barrel of oil equivalent basis. Per-unit measures are divided by sales volumes.

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. Conventional, Offshore and Asia Pacific Per-Unit Operating Expenses contain non-GAAP measures.

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 2025 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. – 2025 Annual Information Form	33
Canada	Q4	Q3	Q2	Q1
---	---	---	---	---
Foster Creek Bitumen (/bbl)
Sales Price	68.76	79.46	77.96	87.26
Royalties	11.04	16.86	12.23	17.40
Transportation and Blending	10.90	13.13	18.41	15.85
Operating Expenses	8.77	8.57	12.34	9.82
Netback	38.05	40.90	34.98	44.19
Christina Lake Bitumen (/bbl)
Sales Price	60.39	69.92	65.51	75.07
Royalties	11.63	17.49	14.19	18.48
Transportation and Blending	7.71	7.14	6.07	6.12
Operating Expenses	8.73	6.61	8.70	8.76
Netback	32.32	38.68	36.55	41.71
Sunrise Bitumen (/bbl)
Sales Price	67.88	79.50	70.07	87.30
Royalties	3.62	3.41	3.47	4.56
Transportation and Blending	13.81	14.97	15.28	18.07
Operating Expenses	15.36	17.45	20.26	17.55
Netback	35.09	43.67	31.06	47.12
Lloydminster Bitumen (1) (/bbl)
Sales Price	61.69	71.04	69.69	78.93
Royalties	7.37	8.06	8.74	8.61
Transportation and Blending	2.99	3.24	3.28	3.42
Operating Expenses	18.16	22.57	21.12	18.46
Netback	33.17	37.17	36.55	48.44
Total Bitumen (1) (/bbl)
Sales Price	63.82	74.07	70.78	80.99
Royalties	10.02	14.28	11.43	15.03
Transportation and Blending	8.33	9.02	10.18	9.85
Operating Expenses	11.00	11.21	13.60	11.77
Netback	34.47	39.56	35.57	44.34
Light and Medium Oil (/bbl)
Sales Price	79.87	90.52	92.09	99.30
Royalties	5.81	5.13	6.95	5.49
Transportation and Blending	4.93	6.51	6.04	6.02
Operating Expenses	35.35	46.56	42.70	36.90
Netback	33.78	32.32	36.40	50.89
Conventional Natural Gas (2) (/Mcf)
Sales Price	3.69	2.01	2.77	4.11
Royalties	0.09	—	0.04	0.05
Transportation and Blending	0.64	0.68	0.69	0.60
Operating Expenses	1.35	1.72	1.66	1.82
Netback	1.61	(0.39)	0.38	1.64
NGLs (3) (/bbl)
Sales Price	50.40	45.44	47.56	64.91
Royalties	0.82	2.12	2.02	4.70
Transportation and Blending	12.71	9.85	9.69	13.00
Operating Expenses	8.11	10.31	9.93	10.92
Netback	28.76	23.16	25.92	36.29

All values are in US Dollars.

(1)Includes bitumen and heavy crude oil.

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

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

Cenovus Energy Inc. – 2025 Annual Information Form	34
China	Q4	Q3	Q2	Q1
---	---	---	---	---
Conventional Natural Gas (/Mcf)
Sales Price	12.71	12.28	12.29	12.79
Royalties	0.67	0.65	0.65	0.68
Transportation and Blending	—	—	—	—
Operating Expenses	1.62	1.38	1.45	1.00
Netback	10.42	10.25	10.19	11.11
NGLs (/bbl)
Sales Price	87.06	93.57	86.96	97.29
Royalties	13.83	5.38	13.39	13.96
Transportation and Blending	—	—	—	—
Operating Expenses	10.33	8.21	8.72	6.00
Netback	62.90	79.98	64.85	77.33

All values are in US Dollars.

Indonesia	Q4	Q3	Q2	Q1
Conventional Natural Gas (/Mcf)
Sales Price	9.18	8.57	9.19	10.45
Royalties	1.35	1.83	2.07	3.11
Transportation and Blending	—	—	—	—
Operating Expenses	2.60	1.48	1.78	1.79
Netback	5.23	5.26	5.34	5.55
NGLs (/bbl)
Sales Price	95.97	93.23	93.70	117.54
Royalties	28.44	39.01	34.14	40.97
Transportation and Blending	—	—	—	—
Operating Expenses	16.15	9.27	9.28	9.07
Netback	51.38	44.95	50.28	67.50

All values are in US Dollars.

Cenovus Energy Inc. – 2025 Annual Information Form	35
Total Company	Q4	Q3	Q2	Q1
---	---	---	---	---
Bitumen (1) (/bbl)
Sales Price	63.82	74.07	70.78	80.99
Royalties	10.02	14.28	11.43	15.03
Transportation and Blending	8.33	9.02	10.18	9.85
Operating Expenses	11.00	11.21	13.60	11.77
Netback	34.47	39.56	35.57	44.34
Light and Medium Oil (/bbl)
Sales Price	79.87	90.52	92.09	99.30
Royalties	5.81	5.13	6.95	5.49
Transportation and Blending	4.93	6.51	6.04	6.02
Operating Expenses	35.35	46.56	42.70	36.90
Netback	33.78	32.32	36.40	50.89
Conventional Natural Gas (2) (/Mcf)
Sales Price	6.33	4.94	5.48	6.72
Royalties	0.35	0.33	0.38	0.50
Transportation and Blending	0.43	0.46	0.47	0.40
Operating Expenses	1.54	1.62	1.63	1.63
Netback	4.01	2.53	3.00	4.19
NGLs (3) (/bbl)
Sales Price	60.09	53.61	60.44	75.36
Royalties	4.79	4.68	6.76	8.07
Transportation and Blending	9.49	8.18	6.62	8.95
Operating Expenses	8.94	10.01	9.58	9.44
Netback	36.87	30.74	37.48	48.90

All values are in US Dollars.

(1)Includes bitumen and heavy crude oil.

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

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

Cenovus Energy Inc. – 2025 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 18, 2026, the Board declared a first quarter base dividend of $0.200 per common share, payable on March 31, 2026, to common shareholders of record as at March 13, 2026.

On February 18, 2026, the Board declared first quarter preferred share dividends of $2 million, payable on March 31, 2026, to preferred shareholders of record as at March 13, 2026.

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

($ per share)	2025	2024	2023
Base Dividends	0.780	0.680	0.525
Variable Dividends	—	0.135	—

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

($ per share)	2025	2024	2023 (1)
Series 1 First Preferred Shares	0.644	0.644	0.644
Series 2 First Preferred Shares	1.158	1.626	1.584
Series 3 First Preferred Shares (2)	—	1.172	1.172
Series 5 First Preferred Shares (2)	0.287	1.148	1.148
Series 7 First Preferred Shares (2)	0.492	0.984	0.984

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

(2)On March 31, 2025 and June 30, 2025, the Company exercised its right to redeem all series 5 and series 7 preferred shares, respectively. 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 2025 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, 5, 6, 7 or 8 first preferred shares outstanding and no second preferred shares outstanding. As at December 31, 2025, the Company had the following common shares, Cenovus Warrants and first preferred shares outstanding:

	Units Outstanding (thousands)
Common Shares	1,883,400
Cenovus Warrants (1)	1,172
Series 1 First Preferred Shares	10,740
Series 2 First Preferred Shares	1,260

(1)The Cenovus Warrants expired on January 1, 2026.

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. – 2025 Annual Information Form	37

Normal Course Issuer Bid

On November 7, 2025, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 120.3 million common shares during the period from November 11, 2025, to November 10, 2026.

For the year ended December 31, 2025, the Company purchased and cancelled 89.4 million common shares (2024 – 55.9 million) through the NCIB. The common shares were purchased at a volume weighted average price of $21.87 per common share (December 31, 2024 – $25.38) for a total of $2.0 billion (December 31, 2024 – $1.4 billion).

From January 1, 2026, to February 13, 2026, the Company purchased an additional 5.0 million common shares for $126 million. As at February 13, 2026, the Company can further purchase up to 107.9 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, 2025	Dividend Reset Date	Dividend Rate<br><br>(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	3.95	1,260

(1)The floating-rate dividend was 5.21 percent from December 31, 2024, to March 30, 2025, 4.57 percent from March 31, 2025, to June 29, 2025, 4.37 percent from June 30, 2025, to September 29, 2025 and 4.39 percent from September 30, 2025, to December 30, 2025.

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 March 31, 2025 and June 30, 2025, the Company exercised its right to redeem all series 5 and series 7 first preferred shares, respectively.

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 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. For the series 2 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.

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 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, 2025.

Cenovus Warrants

The Cenovus Warrants were created and issued pursuant to the terms of the warrant indenture dated January 1, 2021 (the “Warrant Indenture”). Any Cenovus Warrants that remained outstanding as at January 1, 2026, expired as of such date in accordance with their terms. As of the date of this document there are no Cenovus Warrants outstanding.

Base Shelf Prospectus

On November 28, 2025, the Company filed a short form base shelf prospectus under Part 9B of National Instrument 44-102 “Shelf Distributions” (“NI 44-102”). The base shelf prospectus allows Cenovus 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 2028. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.

Cenovus Energy Inc. – 2025 Annual Information Form	38

The Company has determined that it satisfies the conditions of subsection 9B.2(1) of NI 44-102 and is a “well-known seasoned issuer” (“WKSI”). Cenovus is therefore eligible to file a WKSI base shelf prospectus in accordance with NI 44-102.

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 Husky 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 Husky 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 Husky 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 2025 MD&A, which 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<br><br>Ratings<br><br>(“S&P”)	Moody’s<br><br>Investors Service<br><br>(“Moody’s”)	Morningstar<br><br>DBRS<br><br>(“DBRS”)	Fitch<br><br>Ratings Inc.<br><br>(“Fitch”)
Senior Unsecured Long-Term Notes	BBB	Baa1	BBB(high)	BBB
Outlook/Trend	Negative	Negative	Stable	Stable
Series 1 First Preferred Shares	P-3(High)	—	Pfd-3 (high)	—
Series 2 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. – 2025 Annual Information Form	39

S&P’s long-term credit ratings are on a rating scale that ranges from AAA to D/SD, 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 “Negative” outlook indicates that a rating may be lowered in the medium term.

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 global scale preferred share rating. A rating of BB+ by S&P is within the fifth highest of its 10 long-term rating 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 Baa1 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 “Negative” outlook indicates a higher likelihood of a rating downgrade over the medium term.

DBRS’s long-term credit ratings are on a rating scale that ranges from AAA to D/SD, 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. – 2025 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 2025:

	TSX				NYSE
	Price Range (1) ( per share)		Volume (1) (thousands)		Price Range (2) (US per share)				Volume (2) (thousands)
	High	Close		High			Close
January	22.97	21.02	216,298		15.95	14.36		14.47	219,394
February	22.41	20.01	198,706		15.70	13.49		13.84	208,008
March	20.80	20.00	273,685		14.57	12.08		13.91	241,035
April	20.14	16.23	248,588		14.05	10.24		11.77	228,384
May	19.73	18.08	230,229		14.10	11.61		13.18	278,679
June	20.54	18.53	325,079		15.06	12.88		13.60	288,660
July	21.63	21.09	305,293		15.64	13.48		15.23	258,822
August	23.54	22.84	357,545		17.06	14.49		16.61	290,207
September	25.34	23.63	443,947		18.17	15.80		16.99	476,730
October	25.97	23.70	407,128		18.61	16.58		16.92	377,765
November	26.36	24.93	344,591		18.74	16.56		17.86	193,012
December	25.92	23.22	395,930		18.70	16.41		16.92	214,261

All values are in US Dollars.

(1)Prices as reported by TSX. Volumes reported by all Canadian marketplaces. Source: Bloomberg.

(2)Prices as reported by NYSE. Volumes reported by all U.S. marketplaces. Source: Bloomberg.

As of December 31, 2025, the Cenovus Warrants were listed and traded on the TSX under the symbol CVE.WT and on the NYSE under the symbol CVE.WS. The Cenovus Warrants expired on January 1, 2026. The Series 1 First Preferred Shares and Series 2 First Preferred Shares are listed and trade on the TSX under the symbols CVE.PR.A and CVE.PR.B, respectively.

The share price trading range and volume of the Cenovus Warrants traded in 2025 are provided below:

	TSX				NYSE
	Price Range (1) ( per share)		Volume (1) (thousands)		Price Range (2) (US per share)				Volume (2) (thousands)
	High	Close		High			Close
January	16.41	14.51	90		11.20	10.02		10.36	43
February	15.83	13.39	170		10.90	9.20		9.27	86
March	14.10	13.50	211		9.89	7.69		9.53	35
April	13.59	9.70	143		9.42	5.97		7.09	39
May	13.00	11.48	142		9.33	7.00		8.53	30
June	13.93	12.06	199		10.18	8.01		8.80	105
July	15.06	14.54	160		10.50	8.56		10.35	75
August	17.01	16.22	395		13.31	9.57		12.25	121
September	18.80	17.07	198		13.44	11.30		12.35	33
October	19.37	17.11	183		13.74	11.80		12.13	82
November	19.80	18.34	259		13.80	11.95		13.20	37
December	19.30	16.61	788		13.88	11.22		12.33	180

All values are in US Dollars.

(1)Prices as reported by TSX. Volumes reported by all Canadian marketplaces. Source: Bloomberg.

(2)Prices as reported by NYSE. Volumes reported by all U.S. marketplaces. Source: Bloomberg.

Cenovus Energy Inc. – 2025 Annual Information Form	41

The share price trading range and volume of the Series 1 First Preferred Shares traded in 2025 are provided below:

	Price Range (1) ( per share)		Volume (1) (thousands)
	High	Close
January	22.95	22.72	645
February	22.90	22.90	170
March	23.63	23.63	174
April	23.17	22.72	202
May	24.01	24.01	127
June	24.38	23.87	462
July	24.11	23.99	416
August	24.51	23.98	285
September	24.68	24.37	441
October	24.67	24.60	111
November	24.88	24.45	87
December	24.75	24.66	142

All values are in US Dollars.

(1)Prices as reported by TSX. Volumes reported by all Canadian marketplaces. Source: Bloomberg.

The share price trading range and volume of the Series 2 First Preferred Shares traded in 2025 are provided below:

	Price Range (1) ( per share)		Volume (1) (thousands)
	High	Close
January	23.00	22.98	23
February	23.00	23.00	21
March	23.00	22.60	24
April	23.75	22.68	16
May	24.19	23.75	24
June	23.75	23.26	9
July	23.84	23.84	71
August	23.84	23.53	1
September	24.49	23.77	7
October	24.35	24.00	45
November	24.06	23.85	33
December	24.74	24.74	6

All values are in US Dollars.

(1)Prices as reported by TSX. Volumes reported by all Canadian marketplaces. Source: Bloomberg.

The share price trading range and volume of the Series 5 First Preferred Shares traded in 2025, prior to their redemption on March 31, 2025, are provided below:

	Price Range (1) ( per share)		Volume (1) (thousands)
	High	Close
January	24.99	24.99	254
February	25.22	25.21	315
March	25.25	24.99	1,603

All values are in US Dollars.

(1)Prices as reported by TSX. Volumes reported by all Canadian marketplaces. Source: Bloomberg.

The share price trading range and volume of the Series 7 First Preferred Shares traded in 2025, prior to their redemption on June 30, 2025, are provided below:

	Price Range (1) ( per share)		Volume (1) (thousands)
	High	Close
January	24.90	24.86	449
February	25.05	25.02	196
March	25.11	24.92	135
April	24.91	24.90	139
May	25.16	25.10	234
June	25.22	25.00	638

All values are in US Dollars.

(1)Prices as reported by TSX. Volumes reported by all Canadian marketplaces. Source: Bloomberg.

Cenovus Energy Inc. – 2025 Annual Information Form	42
DIRECTORS AND EXECUTIVE OFFICERS
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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.
Keith M. Casey<br><br>San Antonio, Texas<br><br>United States	April 29, 2020<br><br>Independent SSR<br><br>HRC (1)	Mr. Casey was the Chief Executive Officer of Pin Oak Group, LLC, a private midstream company, from February 2022 to February 2025; and 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<br><br>Calgary, Alberta<br><br>Canada	November 1, 2023<br><br>Independent<br><br>Governance<br><br>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 publicly traded 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; a director of Denova Inc., a private biotechnology company, since August 2025 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<br><br>Luxembourg<br><br>Grand-Duchy of Luxembourg	November 1, 2023<br><br>Independent HRC (1)<br><br>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 publicly traded 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 from April 2012 to March 2021.
Jane E. Kinney<br><br>Toronto, Ontario<br><br>Canada	April 24, 2019<br><br>Independent<br><br>Audit<br><br>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<br><br>Vancouver, British Columbia Canada	January 1, 2021<br><br>Independent<br><br>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.		Cenovus Energy Inc. – 2025 Annual Information Form	43
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Name and Residence	Date Elected or Appointed as Director, Independence Status and Committee Membership	Principal Occupation During the Past Five Years
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Melanie A. Little<br><br>Alpharetta, Georgia<br><br>United States	January 1, 2023<br><br>Independent<br><br>SSR<br><br>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 publicly traded partnership that transports, stores and distributes petroleum products which was acquired by ONEOK Inc. 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 publicly traded oil and gas producer, from December 2019 to December 2022.
Richard J. Marcogliese Alamo, California<br><br>United States	April 27, 2016<br><br>Independent<br><br>Audit<br><br>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.
Chana L. Martineau Edmonton, Alberta Canada	May 8, 2025 Independent Audit Governance	Ms. Martineau is the Chief Executive Officer of the Alberta Indigenous Opportunities Corporation (“AIOC”), a provincial Crown corporation with a mandate to serve as a catalyst for Indigenous prosperity and independence through investment and involvement in Alberta’s natural resources, agriculture, transportation, tourism, and telecommunications sectors, since July 2022, and was a director of AIOC from November 2021 to July 2022. Ms. Martineau is also a director of Alamos Gold Inc., a Canadian based intermediate gold producer, since May 2025. Ms. Martineau served as Vice President – Banking, Canadian Western Bank, a Canadian based bank that is now a part of National Bank Financial Group, from January 2021 to July 2022; was on the COVID-19 Emergency Response Leadership Team from March 2020 to January 2021; and was Vice President – Sales Strategy & Effectiveness from January 2018 to January 2021.
Jonathan M. McKenzie Calgary, Alberta Canada	April 26, 2023<br><br>Non-Independent (2)	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<br><br>Montreal, Quebec<br>Canada	December 1, 2016<br><br>Independent<br><br>Audit<br><br>Governance	Mr. Mongeau was appointed Lead Independent director of Cenovus effective April 26, 2023. Mr. Mongeau was a director of The Toronto-Dominion Bank, an international financial institution, from March 2015 to April 2025; and was Board Chair, from May 2024 to June 2025, and a director from September 2019 to June 2025, 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<br><br>Calgary, Alberta<br><br>Canada	November 6, 2017<br><br>Non-Independent (2)	Mr. Pourbaix was appointed Board Chair of Cenovus effective May 8, 2025; and was Executive Chair of the Board of Cenovus from April 2023 to May 2025. 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.		Cenovus Energy Inc. – 2025 Annual Information Form	44
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Name and Residence	Date Elected or Appointed as Director, Independence Status and Committee Membership	Principal Occupation During the Past Five Years
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Frank J. Sixt<br><br>Hong Kong Special<br><br>Administrative Region	January 1, 2021<br><br>Independent<br><br>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, a publicly traded telecommunications service provider company, since May 2001; 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 Chairman from December 2023 to August 2025 and a director from January 1998 to August 2025 of Hutchison Telecommunications (Australia) Limited, and a Commissioner of PT Indosat Tbk, from January 2022 to September 2023, both publicly traded telecommunications service provider companies. Mr. Sixt was a director of Husky, from August 2000 until March 2021.
Rhonda I. Zygocki<br><br>Friday Harbor, Washington<br>United States	April 27, 2016<br><br>Independent<br><br>Governance<br><br>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. 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)As non-independent directors, Mr. McKenzie as an officer and Mr. Pourbaix as Board Chair 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
Jonathan M. McKenzie<br><br>Calgary, Alberta<br><br>Canada	President & Chief Executive Officer<br><br>Mr. McKenzie’s biographical information is included under “Directors”.
Karamjit S. Sandhar<br><br>Calgary, Alberta<br><br>Canada	Executive Vice-President & Chief Financial Officer<br><br>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; and from January 2020 to January 2021, Mr. Sandhar was Senior Vice-President, Conventional.
P. Andrew Dahlin<br><br>Calgary, Alberta<br><br>Canada	Executive Vice-President & Chief Operating Officer<br><br>Mr. Dahlin was appointed Executive Vice-President & Chief Operating Officer effective March 1, 2025. From September 2023 to February 2025, Mr. Dahlin was Executive Vice-President, Natural Gas & Technical Services; 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.
Jeffery G. Lawson<br><br>Calgary, Alberta<br><br>Canada	Executive Vice-President, Corporate Development & Chief Sustainability Officer<br><br>Mr. Lawson was appointed Executive Vice-President, Corporate Development & Chief Sustainability Officer effective March 1, 2025. From May 2024 to February 2025, Mr. Lawson was Senior Vice-President, Corporate Development & Acting Chief Sustainability Officer; and from December 2022 to May 2024, Mr. Lawson was Senior Vice-President, Corporate Development. From October 2018 to December 2022, Mr. Lawson was Managing director, Corporate Finance at Peters & Co. Limited.
Cenovus Energy Inc. – 2025 Annual Information Form	45
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Name and Residence	Office Held and Principal Occupation During the Past Five Years
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Geoffrey T. Murray<br><br>Calgary, Alberta<br><br>Canada	Executive Vice-President, Commercial<br><br>Mr. Murray was appointed Executive Vice-President, Commercial effective May 1, 2024. From August 2023 to May 2024, Mr. Murray was Senior Vice-President, Commercial; 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.
John F. Soini<br><br>Calgary, Alberta<br><br>Canada	Executive Vice-President, Upstream – Thermal & Atlantic Offshore<br><br>Mr. Soini was appointed Executive Vice-President, Upstream – Thermal & Atlantic Offshore effective March 1, 2025. From April 2024 to February 2025, Mr. Soini was Senior Vice-President, Major & Capital Projects. From January 2023 to March 2024, Mr. Soini was Global Operating Partner at Brookfield Infrastructure Partners L.P. (“Brookfield”), a publicly traded limited partnership engaged in global acquisition and infrastructure asset management. From October 2021 to January 2023, Mr. Soini was Senior Vice-President at Heartland PetroChemical Complex Project at Inter Pipeline Ltd., a public global energy infrastructure business acquired by Brookfield in October 2021, at which time it became a private subsidiary of Brookfield; and from May 2019 to January 2023, Mr. Soini was Chief Operating Officer at NorthRiver Midstream Inc., a Canadian gas gathering and processing business which Brookfield acquired from Enbridge Inc. in October 2018.
Susan M. Anderson<br><br>Calgary, Alberta<br><br>Canada	Senior Vice-President, Legal, General Counsel & Corporate Secretary<br><br>Ms. Anderson was appointed Senior Vice-President, Legal, General Counsel & Corporate Secretary effective March 1, 2025. From March 2022 to February 2025, Ms. Anderson was Senior Vice-President, People Services; and 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 at Husky.
Candace J. Newman<br><br>Calgary, Alberta<br><br>Canada	Senior Vice-President, People Services<br><br>Ms. Newman was appointed Senior Vice-President, People Services effective March 1, 2025. From March 2023 to February 2025, Ms. Newman was Vice-President, Human Resources. From October 2018 to March 2023, Ms. Newman was CHRO Vice President HR and Real Estate at LNG Canada Corporation, a private joint venture and liquified natural gas exporter.
Eric R. Zimpfer<br><br>Columbus, Ohio<br><br>United States	Senior Vice-President, Head of Downstream<br><br>Mr. Zimpfer was appointed Senior Vice-President, Head of Downstream effective March 1, 2025. From April 2024 to February 2025, Mr. Zimpfer was Senior Vice-President, U.S. Refining. From January 2021 to April 2024 Mr. Zimpfer was Vice-President of Refining at Cherry Point Refinery at BP West Coast Products LLC, a subsidiary of BP p.l.c., a publicly traded multinational oil and gas company, and from March 2017 to December 2020 was Operations Manager at BP-Husky Toledo Refinery, a joint operation between BP Products North America Inc., an oil and natural gas exploration, development, refining and marketing subsidiary of BP p.l.c., and Husky Oil Toledo Company, a refining subsidiary of Husky.

As of December 31, 2025, all of Cenovus’s directors and executive officers, as a group, beneficially owned or exercised control or direction over, directly or indirectly, 3,786,341 common shares or approximately 0.20 percent of the number of common shares that were outstanding as of such date.

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

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

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

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

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

Cenovus Energy Inc. – 2025 Annual Information Form	46

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 five 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, Chana L. Martineau 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. – 2025 Annual Information Form	47

Chana L. Martineau

Ms. Martineau has a Bachelor of Arts degree in Economics from the University of Alberta, is a member of the Young Presidents' Organization, and holds an Institute of Corporate directors designation. Ms. Martineau has been Chief Executive Officer of the AIOC, a provincial Crown corporation with a mandate to serve as a catalyst for Indigenous prosperity and independence through investment and involvement in Alberta’s natural resources, agriculture, transportation, tourism, and telecommunications sectors, since July 2022; and was a director of AIOC from November 2021 to July 2022. Ms. Martineau is also a director of Alamos Gold Inc., a publicly traded Canadian based intermediate gold producer, since May 2025. Ms. Martineau served as Vice President – Banking, Canadian Western Bank, a Canadian based bank that is now a part of National Bank Financial Group, from January 2021 to July 2022; was on the COVID-19 Emergency Response Leadership Team from March 2020 to January 2021; and was Vice President – Sales Strategy & Effectiveness from January 2018 to January 2021.

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 was a director of The Toronto-Dominion Bank, an international financial institution, from March 2015 to April 2025, and Norfolk Southern Corporation, a publicly traded rail transportation provider, from September 2019 to June 2025. 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.

Cenovus Energy Inc. – 2025 Annual Information Form	48

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, 2025 and 2024:

($ thousands)	2025	2024
Audit Fees (1)	3,989	4,809
Audit-Related Fees (2)	1,178	646
Tax Fees (3)	108	103
All Other Fees (4)	65	165
Total	5,340	5,723

(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 Consolidated Financial statements and are not reported as audit fees. The services provided in this category included audit-related services in relation to Cenovus’s Sustainability disclosures, prospectuses and participation fees levied by the Canadian Public Accountability Board. Fees related to the acquisition or divestiture of assets are also included in audit-related fees.

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

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

During the year ended December 31, 2025, 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, 2025, 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.<br><br>320 Bay Street, 14th Floor<br><br>Toronto, ON M5H 4A6<br><br>Canada | Computershare Trust Company NA<br><br>150 Royall St., Suite 101<br><br>Canton, MA 02021<br><br>U.S. | | Tel: 1-866-332-8898<br><br>Website: www.computershare.com/cenovus | || Cenovus Energy Inc. – 2025 Annual Information Form | 49 | | --- | --- | | MATERIAL CONTRACTS | | --- |

During the year ended December 31, 2025, 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.

On January 1, 2026 the standstill agreements (each, a “Husky Standstill Agreement”), registration rights agreements (each, a “Husky Arrangement Registration Rights Agreement”) and pre-emptive rights agreements (each, a “Husky Arrangement Pre-Emptive Rights Agreement”) entered into with each of Hutchison Whampoa Europe Investments S.à r.l. (“Hutchison”) and L.F. Investments S.à r.l. (“L.F. Investments”), in connection with the Husky Arrangement, expired in accordance with their terms. Copies of the Husky Standstill Agreements, Husky Arrangement Registration Rights Agreements and Husky Arrangement Pre-Emptive Rights Agreements were filed on SEDAR+ on January 4, 2021, and are available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.

ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER

On October 24, 2020, each of Hutchison and L.F. Investments entered into Husky Standstill Agreements, with effect as of January 1, 2021, which provided for certain restrictions and obligations in connection with such shareholder’s shareholdings in Cenovus following completion of the transactions contemplated by the Husky Arrangement (the “Transfer Restrictions”).

The Husky Standstill Agreements expired on January 1, 2026, in accordance with their terms and the common shares held by each of Hutchison and L.F. Investments are no longer subject to the Transfer Restrictions.

The following table summarizes the number of Cenovus securities that were subject to the Transfer Restrictions as at December 31, 2025:

Name of Holder	Designation of Securities	Number of Securities subject to Transfer Restrictions	Percentage of Class
Hutchison Whampoa Europe Investments S.à r.l.	Common Shares	316,927,051	16.8
L.F. Investments S.à r.l.	Common Shares	231,194,699	12.3
Total		548,121,750	29.1
INTERESTS OF EXPERTS
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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 18, 2026, in respect of the Company’s Consolidated Financial Statements as at December 31, 2025 and December 31, 2024, and for each of the years then ended and on the effectiveness of internal control over financial reporting as at December 31, 2025. 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.

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, 2025, can be found in Cenovus’s Consolidated Financial Statements and annual MD&A for the year ended December 31, 2025.

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.

Cenovus Energy Inc. – 2025 Annual Information Form	50
ACCOUNTING MATTERS
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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, 2025, 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 2025 MD&A. As a result, the disclosure in the annual 2025 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 | | | FPSO | floating production, storage and offloading unit | | CLB | Cold Lake Blend | | | NCIB | normal course issuer bid | | LLB | Lloyd Blend | | | AECO | Alberta Energy Company | | WDB | Western Canada Dilbit Blend | | | USGC | U.S. Gulf Coast |

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. – 2025 Annual Information Form	51
FORWARD-LOOKING INFORMATION
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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”, “forecast”, “future”, “may”, “plan”, “target” and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: the Company’s target to return 50 percent, or 75 percent of Excess Free Funds Flow to shareholders, depending on the Company’s Net Debt, in accordance with the updated shareholder returns framework; Net Debt targets and Excess Free Funds Flow; share repurchases under the NCIB and the timing thereof; timing for completion of commissioning activities and commencement of drilling at the West White Rose project and SeaRose FPSO; exploration and future development programs at Block DW-1; planned relinquishment of the Liman contract area; 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 the Minnedosa ethanol plant; the redemption of the Company’s preferred shares; the use of financial derivatives and other arrangements to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates, future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions; the Company’s expectation 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; the intended effects of the Company’s plans and policies into its operations; commitment to a safe and inclusive workplace; investing in and partnering with local and Indigenous communities; continuously improving operating practices; investing in technology; innovating to reduce our GHG emissions and minimize our environmental impact, and delivering transparent performance reporting; the expectation that the Company’s bitumen reserves will be recovered using SAGD, except for heavy crude oil; Cenovus’s forecasted production of Cenovus’s proved and proved plus probable SAGD bitumen reserves; timing estimates for the Company’s production of the current proved developed portion; anticipated timing for the proved and probable undeveloped reserves attributable to the West White Rose project to be on stream; timing for potential expiry of the rights to explore, develop and exploit unproved net acres related to Crown and freehold properties in Canada; the Company’s commitment related to exploration to be completed in China; relationships with Indigenous communities and other stakeholders; commitment to human rights; 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 and timing thereof; 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 and 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 absence of certain changes, including divestitures, as it relates to production estimates; 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 and other arrangements to manage its exposure

Cenovus Energy Inc. – 2025 Annual Information Form	52

to fluctuations in commodity prices, foreign exchange and interest rates; future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions; the Company’s ability to engage in trading activities for purposes other than hedging; the future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions; 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; the ability of the Company to achieve its Net Debt and Excess Free Cash Flow targets; 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, 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 sustainability goals and the commercial viability and scalability of related strategies, technology and products; risk that the benefit of investment in sustainability focus areas and goals may be less than expected; collaboration with the government and industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2026 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. 2026 guidance dated December 10, 2025, and available on cenovus.com, assumes: Brent prices of US$64.00 per barrel, WTI prices of US$60.00 per barrel; WCS of US$47.50 per barrel; Differential WTI-WCS of US$12.50 per barrel; AECO natural gas prices of $2.50 per Mcf; Chicago 3-2-1 crack spread of US$20.00 per barrel; RINs of US$6.00 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 sustainability goals and the commercial viability and scalability of 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 Company’s risk management and trading activities; disclosure controls and procedures and internal control over financial reporting; 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 Earnings before interest, taxes, depreciation, and amortization 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; risks associated with project development and execution; 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

Cenovus Energy Inc. – 2025 Annual Information Form	53

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof, and the Company undertakes no obligation to update or revise any forward-looking information except as required by law. 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 annual 2025 MD&A, 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. – 2025 Annual Information Form	54
APPENDIX A
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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, 2025. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2025, 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, 2025, 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<br><br>(Before Income Taxes, 10% Discount Rate)<br><br>($ millions)
McDaniel & Associates Consultants Ltd.	December 31, 2025	Canada	79,439
McDaniel & Associates Consultants Ltd.	December 31, 2025	China	2,246
McDaniel & Associates Consultants Ltd.	December 31, 2025	Indonesia	433
GLJ Ltd.	December 31, 2025	Canada	1,489
			83,607

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.<br><br>President & CEO<br><br>McDaniel & Associates Consultants Ltd.<br><br>Calgary, Alberta, Canada	Jodi L. Anhorn, M.Sc., P. Eng.<br><br>President and Chief Executive Officer<br><br>GLJ Ltd.<br><br>Calgary, Alberta, Canada

February 17, 2026

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APPENDIX B
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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<br><br>President & Chief Executive Officer<br><br>Cenovus Energy Inc.	Karamjit S. Sandhar<br><br>Executive Vice-President & Chief Financial Officer<br><br>Cenovus Energy Inc.
/s/ Alexander J. Pourbaix	/s/ Richard J. Marcogliese
Alexander J. Pourbaix<br><br>Board Chair<br><br>Cenovus Energy Inc.	Richard J. Marcogliese<br><br>Director and Chair of the Safety, Sustainability and Reserves Committee<br><br>Cenovus Energy Inc.

February 18, 2026

Cenovus Energy Inc. – 2025 Annual Information Form	56
APPENDIX C
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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.

•Review amendments to and compliance with the Code of Business Conduct & Ethics.

•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 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 recommend for approval to the Board the Corporation’s:

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

Cenovus Energy Inc. – 2025 Annual Information Form	59

(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

(a)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.

(b)Review and recommend to the Board any amendments to the Code of Business Conduct & Ethics.

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.

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

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

(i)Review and report to the Board on compliance with the Code of Business Conduct & Ethics through regular reporting from management on the status of complaints received, employee training and sign-off.

(j)Review and report to the Board on compliance with the Trade Compliance Standard through regular reporting from management on the status of known, suspected or observed violations, investigations and enforcement.

(k)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.

(l)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.

(m)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

Cenovus Energy Inc. – 2025 Annual Information Form	61

(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.

(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.

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(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.

(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, including trends, insights, initiatives and investigations, 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.

Cenovus Energy Inc. – 2025 Annual Information Form	63

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

The Committee:

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

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

(c)shall 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)may 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)shall 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 of its duties;

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

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

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

(i)shall 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 10, 2025

Cenovus Energy Inc. – 2025 Annual Information Form	64

Document

Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Year Ended December 31, 2025

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the year ended December 31, 2025
TABLE OF CONTENTS
---
OVERVIEW OF CENOVUS	3
---	---
YEAR IN REVIEW	3
OPERATING AND FINANCIAL RESULTS	6
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	11
OUTLOOK	14
REPORTABLE SEGMENTS	16
UPSTREAM	17
OIL SANDS	17
CONVENTIONAL	21
OFFSHORE	24
DOWNSTREAM	27
CANADIAN REFINING	27
U.S. REFINING	28
CORPORATE AND ELIMINATIONS	31
QUARTERLY RESULTS	32
OIL AND GAS RESERVES	35
LIQUIDITY AND CAPITAL RESOURCES	36
RISK MANAGEMENT AND RISK FACTORS	41
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	58
CONTROL ENVIRONMENT	60
ADVISORY	61
ABBREVIATIONS AND DEFINITIONS	64
SPECIFIED FINANCIAL MEASURES	65

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 18, 2026, should be read in conjunction with our December 31, 2025 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”) and our December 31, 2025 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 18, 2026, 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 18, 2026. 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 (as defined below), 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. – 2025 Management's Discussion and Analysis	2
OVERVIEW OF CENOVUS
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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.”).

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 North America 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.

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 reaching and 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 11, 2025, we released our 2026 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 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 2026 corporate guidance dated December 10, 2025, available on our website at cenovus.com.

YEAR IN REVIEW

Our 2025 results reflect strong operational performance in the upstream and downstream business. Despite a weakened commodity price environment, we delivered strong financial results, reached significant milestones in key growth projects and completed strategic acquisitions and divestitures, which enhance our asset portfolio.

•Delivered safe and reliable operations. We delivered safe operations across our business and safely completed turnarounds at Foster Creek, Sunrise and the Toledo Refinery. In late May, we responded to wildfire activity in northern Alberta by temporarily shutting-in production at Christina Lake to ensure the safety of our staff and assets. We resumed production in early June. Safety continues to be our top priority.

•Acquisition of MEG Energy Corp. On November 13, 2025, we completed the acquisition of MEG Energy Corp. (“MEG”) through a plan of arrangement (the “MEG Acquisition”). Purchase consideration for the MEG Acquisition included $3.4 billion in cash partially funded through the receipt of a $2.7 billion term loan facility, and the issuance of 143.9 million Cenovus common shares with a fair value of $3.7 billion. The acquired MEG assets immediately contributed to our Christina Lake production and results.

•Sale of interest in WRB Refining LP. On September 30, 2025, we divested our entire 50 percent interest in the jointly-owned Wood River and Borger refineries held through WRB Refining LP (“WRB”) (the “WRB Divestiture”) for proceeds of US$1.3 billion (C$1.9 billion) after closing adjustments. The divestiture aligns with our strategy of owning and operating assets that are core to our business.

•Record annual upstream production. We achieved record annual upstream production averaging 834.2 thousand BOE per day (2024 – 797.2 thousand BOE per day), primarily due to record annual Oil Sands production averaging 644.1 thousand BOE per day (2024 – 610.7 thousand). Oil Sands production increased due to successful results from new well pads, additional production volumes following the MEG Acquisition and the completion of key growth projects.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	3

•Completed and advanced key Oil Sands growth projects. We ramped-up production following the completion of the Narrows Lake tie-back to Christina Lake, and we completed the Foster Creek optimization project ahead of schedule. At Sunrise, we brought new well pads online to support continued production growth. At our Lloydminster conventional heavy oil assets, we made progress on our heavy oil development program.

•Achieved Offshore milestones at the West White Rose Project. The topsides were placed atop the concrete gravity structure, and we completed the subsea tie-ins to our existing production system at the SeaRose floating production, storage and offloading unit (“FPSO”). Hookup and commissioning of the platform continued to progress and was substantially completed in the fourth quarter of 2025, despite challenging offshore weather conditions.

•Strong utilization in our downstream assets. Average crude oil throughput (“throughput”) in our downstream assets was 626.6 thousand barrels per day, representing a crude unit utilization of 95 percent, compared with 646.9 thousand barrels per day in 2024, representing crude unit utilization of 90 percent. Our Canadian assets achieved record annual throughput and continue to run at or above capacity, while the completion of turnarounds and operational improvement initiatives in our operated U.S. assets resulted in higher reliability.

•Reported solid financial results. Adjusted Funds Flow was $8.9 billion, an increase of $707 million from 2024, reflecting strong operating performance in our upstream and downstream operations, despite a weakened commodity price environment. Brent and WTI benchmark prices both decreased by 14 percent, partially offset by higher market crack spreads and the narrowing of the WTI-WCS differential. Cash from operating activities was $8.2 billion, a decrease from $9.2 billion in 2024, mainly due to changes in non-cash working capital.

•Closed senior notes offerings. In connection with the closing of the MEG Acquisition and upcoming debt maturities, the Company closed public offerings in Canada and the U.S. of $2.6 billion of senior unsecured notes. The proceeds of the offerings were used to fund the redemption of select senior unsecured notes and for general corporate purposes.

•Completed the redemption of select senior notes. The Company redeemed US$973 million in principal of senior unsecured notes due in 2027 and 2029, in full, including the US$600 million senior unsecured notes assumed with the MEG Acquisition. The Company also redeemed $750 million in principal of senior unsecured notes due in 2027, in full.

•Delivered significant returns to shareholders. We returned $3.8 billion to common and preferred shareholders, including the purchase of 89.4 million common shares for $2.0 billion through our normal course issuer bid (“NCIB”), $1.4 billion through common and preferred share base dividends, and the redemption of the Company’s series 5 and series 7 preferred shares at a price of $25.00 per share for a total of $350 million. Following the MEG Acquisition, we have adjusted our shareholder returns framework to balance deleveraging with shareholder returns.

•Raised our common share base dividend. In the second quarter, the Board approved an 11 percent increase in the base dividend to $0.800 per common share annually. On February 18, 2026, the Board declared a first quarter dividend of $0.200 per common share.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	4

Summary of Annual Results

($ millions, except where indicated)	2025	2024	2023
Upstream Production Volumes (1) (2) (MBOE/d)	834.2	797.2	778.7
Downstream Total Processed Inputs (3) (4) (Mbbls/d)	667.5	678.0	586.8
Crude Oil Unit Throughput (3) (Mbbls/d)	626.6	646.9	560.4
Downstream Production Volumes (3) (Mbbls/d)	687.2	693.1	599.2
Revenues	49,696	54,277	52,204
Operating Margin (5)	10,608	10,809	11,022
Operating Margin – Upstream (6)	10,403	11,121	9,870
Operating Margin – Downstream (6)	205	(312)	1,152
Cash From (Used In) Operating Activities	8,228	9,235	7,388
Adjusted Funds Flow (5)	8,871	8,164	8,803
Per Share – Basic (5) ($)	4.90	4.41	4.64
Per Share – Diluted (5) ($)	4.87	4.38	4.54
Capital Investment	4,907	5,015	4,298
Free Funds Flow (5)	3,964	3,149	4,505
Net Earnings (Loss)	3,930	3,142	4,109
Per Share – Basic ($)	2.16	1.68	2.15
Per Share – Diluted ($)	2.15	1.67	2.09
Total Assets	63,424	56,539	53,915
Total Long-Term Liabilities (5)	25,472	19,408	18,993
Long-Term Debt, Including Current Portion	11,032	7,534	7,108
Net Debt	8,292	4,614	5,060
Cash Returns to Common and Preferred Shareholders	3,782	3,246	2,798
Common Shares – Base Dividends	1,423	1,255	990
Base Dividends Per Common Share ($)	0.780	0.680	0.525
Common Shares – Variable Dividends	—	251	—
Variable Dividends Per Common Share ($)	—	0.135	—
Purchase of Common Shares Under NCIB	1,995	1,445	1,061
Payment for Purchase of Warrants	—	—	711
Dividends Paid on Preferred Shares	14	45	36
Preferred Share Redemption	350	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)Includes results of the MEG Acquisition from November 13, 2025.

(3)Represent Cenovus’s net interest in refining operations. Following the WRB Divestiture, all refining operations are wholly-owned.

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

(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. – 2025 Management's Discussion and Analysis	5
OPERATING AND FINANCIAL RESULTS
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Selected Operating and Financial Results — Upstream

		Percent Change
			2024
Production Volumes by Segment (1) (MBOE/d)
Oil Sands (2)	644.1	5		610.7
Conventional (3)	122.8	2		119.9
Offshore (4)	67.3	1		66.6
Total Production Volumes	834.2	5		797.2
Production Volumes by Product (1)
Bitumen (Mbbls/d)	616.8	4		591.3
Heavy Crude Oil (Mbbls/d)	25.1	43		17.6
Light Crude Oil (5) (Mbbls/d)	18.1	40		12.9
NGLs (Mbbls/d)	28.8	(10)		32.0
Conventional Natural Gas (MMcf/d)	872.4	1		860.2
Total Production Volumes (MBOE/d)	834.2	5		797.2
Per-Unit Operating Expenses by Segment (6) (/BOE)
Oil Sands (2)	11.81	4		11.40
Conventional (3) (7)	9.84	(18)		11.99
Offshore (4) (7)	16.88	(12)		19.27
Oil and Gas Reserves (8) (MMBOE)
Total Proved	6,135	8		5,664
Probable	3,472	24		2,793
Total Proved Plus Probable	9,607	14		8,457

All values are in US Dollars.

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

(2)For the year ended December 31, 2025, reported Oil Sands segment production and per-unit operating expenses includes results of the MEG Acquisition from November 13, 2025.

(3)For the year ended December 31, 2025, reported Conventional segment production and per-unit operating expenses include Cenovus’s 30 percent equity interest in the Duvernay Energy Corporation (“Duvernay”) joint venture, which is accounted for using the equity method in the Consolidated Financial Statements. Operating expenses for the Conventional segment, excluding our equity interests in the Duvernay joint venture, was $464 million.

(4)Reported Offshore segment production and per-unit operating expenses include Cenovus’s 40 percent equity interest in the Husky-CNOOC Madura Limited (“HCML”) joint venture, which is accounted for using the equity method in the Consolidated Financial Statements. Operating expenses for the Offshore segment, excluding our equity interests in the HCML joint venture, was $349 million (2024 – $423 million).

(5)Light crude oil corresponds to light crude oil and medium crude oil combined as defined by National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). Cenovus does not produce medium crude oil.

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

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

(8)Includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay joint venture and Cenovus’s 40 percent equity interest in the HCML joint venture. See the Advisory – Interests in Joint Ventures section of this MD&A.

Production

Total upstream production increased in 2025, compared with 2024, due to:

•Incremental production at Christina Lake following the MEG Acquisition in November 2025 and the ramp-up of production from Narrows Lake.

•Successful results from new well pads at Foster Creek and the completion of the Foster Creek optimization project, which supported additional production.

•Production resuming at the White Rose field following the completion of the SeaRose asset life extension (“ALE”) project.

The increase was partially offset by the temporary shut-in of production at our Rush Lake facilities in our Lloydminster thermal assets, due to a casing failure at a steam injection well that occurred in the second quarter of 2025. In the fourth quarter, we successfully restarted production and the phased ramp-up is progressing as expected.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	6

Per-Unit Operating Expenses

For the year ended December 31, 2025, per-unit operating expenses increased in the Oil Sands segment compared with 2024, primarily due to higher fuel costs and higher costs at our Lloydminster thermal assets related to the incident at Rush Lake. Per-unit operating expenses decreased in the Conventional segment primarily due to lower turnaround costs, and processing and gathering costs compared with 2024. Per-unit operating expenses decreased in the Offshore segment compared with 2024, primarily due to higher sales volumes and lower repairs and maintenance expenses as the White Rose field resumed production following the completion of the SeaRose ALE project in the first quarter of 2025.

We continue to focus on controlling costs through securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.

Selected Operating and Financial Results — Downstream

		Percent Change
			2024
Crude Oil Unit Throughput by Segment (Mbbls/d)
Canadian Refining	110.7	22		90.5
U.S. Refining	515.9	(7)		556.4
Total Crude Oil Unit Throughput	626.6	(3)		646.9
Production Volumes by Product (1) (Mbbls/d)
Gasoline	266.7	(5)		280.5
Distillates (2)	210.5	(4)		219.9
Synthetic Crude Oil	52.0	27		41.0
Asphalt	41.8	(5)		44.0
Ethanol	5.0	4		4.8
Other	111.2	8		102.9
Total Production Volumes	687.2	(1)		693.1
Per-Unit Operating Expenses by Segment (3) (/bbl)
Canadian Refining	11.59	(49)		22.56
U.S. Refining	12.73	(2)		12.99
Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3) (/bbl)
Canadian Refining	11.54	(25)		15.38
U.S. Refining	10.88	(6)		11.55

All values are in US Dollars.

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

(2)Includes diesel and jet fuel.

(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A. In the Canadian Refining segment, operating expenses represent expenses associated with the Lloydminster Upgrader (“Upgrader”), the Lloydminster Refinery and the commercial fuels business.

Total downstream throughput and refined product production decreased in 2025. The decrease was primarily due to the WRB Divestiture and the impact of turnarounds completed at our Toledo Refinery and non-operated Wood River and Borger refineries during the year. The decrease in throughput and refined product production was partially offset by our Canadian Refining assets running at, or above, full capacity and ongoing operational improvement initiatives at our operated U.S. Refining assets.

In 2025, per-unit operating expenses excluding turnaround costs decreased in the Canadian Refining segment compared with 2024, due to lower project costs and higher total processed inputs. Total processed inputs were lower and operating expenses were higher in 2024, due to a major turnaround completed at the Upgrader in the second quarter of 2024.

In 2025, per-unit operating expenses excluding turnaround costs decreased in the U.S. Refining segment compared with 2024, primarily due to lower controllable operating expenses, partially offset by higher electricity costs.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	7

Selected Consolidated Financial Results

Revenues

Revenues decreased eight percent compared with 2024, primarily due to a weakened commodity price environment combined with lower U.S. Refining sales volumes following the WRB Divestiture. The decrease was partially offset by higher sales volumes from our upstream assets and Canadian Refining segment.

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.

($ millions)	2025	2024
Gross Sales
External Sales	52,751	57,726
Intersegment Sales	8,941	8,970
	61,692	66,696
Royalties	(3,055)	(3,449)
Revenues	58,637	63,247
Expenses
Purchased Product	30,078	33,926
Transportation and Blending	11,243	11,331
Operating Expenses	6,710	7,159
Realized (Gain) Loss on Risk Management	(2)	22
Operating Margin	10,608	10,809

Operating Margin by Segment

Years Ended December 31, 2025 and 2024

Operating Margin decreased compared with 2024, primarily due to:

•Lower Realized Sales Prices impacting revenues in our Oil Sands segment due to lower benchmark WTI prices, partially offset by a narrower WTI-WCS differential.

•Increased operating expenses in our Oil Sands segment due to higher fuel costs and costs related to the incident at Rush Lake.

The decreases were partially offset by:

•The increase in Oil Sands production discussed above, which includes the accretive impact from the MEG Acquisition.

•Lower operating expenses and higher sales volumes in our Canadian Refining segment, as discussed above.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	8

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

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

($ millions)	2025	2024
Cash From (Used in) Operating Activities	8,228	9,235
(Add) Deduct:
Settlement of Decommissioning Liabilities	(280)	(234)
Net Change in Non-Cash Working Capital	(363)	1,305
Adjusted Funds Flow	8,871	8,164

Adjusted Funds Flow was higher in 2025, compared with 2024, primarily due to lower current tax expense and lower cash-settled long-term incentive costs, partially offset by higher integration, transaction and other costs, and lower Operating Margin.

Cash from operating activities decreased in 2025, compared with 2024, primarily due to changes in non-cash working capital, partially offset by higher Adjusted Funds Flow, as discussed above. The net change in non-cash working capital was primarily due to an increase in accounts receivable, and decreases in accounts payable and income tax payable, partially offset by a decrease in inventories, excluding the impact of the MEG Acquisition and the WRB Divestiture.

Net Earnings (Loss)

Net earnings in 2025 was $3.9 billion (2024 – $3.1 billion). The increase was primarily due to unrealized foreign exchange gains in 2025 compared with losses in 2024, and lower income tax expense, partially offset by higher depreciation, depletion and amortization expense and lower Operating Margin.

Net Debt

As at December 31, ($ millions)	2025	2024
Short-Term Borrowings	—	173
Current Portion of Long-Term Debt	—	192
Long-Term Portion of Long-Term Debt	11,032	7,342
Total Debt	11,032	7,707
Cash and Cash Equivalents	(2,740)	(3,093)
Net Debt	8,292	4,614

Total Debt and Net Debt increased as at December 31, 2025, primarily due to the receipt of a $2.7 billion term loan facility and the issuance of $2.6 billion of senior unsecured notes. The increase was partially offset by the redemption and repayment of senior unsecured notes totaling $2.3 billion, which includes the US$600 million notes assumed in the MEG Acquisition, and unrealized foreign exchange gains due to the strengthening of the Canadian dollar. The increase in Net Debt was further offset by the receipt of proceeds from the WRB Divestiture.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	9

Capital Investment (1)

($ millions)	2025		2024
Upstream
Oil Sands		2,944		2,714
Conventional		453		421
Offshore		934		1,145
Total Upstream		4,331		4,280
Downstream
Canadian Refining		117		208
U.S. Refining		442		488
Total Downstream		559		696
Corporate and Eliminations		17		39
Total Capital Investment		4,907		5,015

(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes capital expenditures related to joint ventures accounted for using the equity method in the Consolidated Financial Statements.

Capital investment in 2025 was mainly related to:

•Sustaining, optimization and redevelopment 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.

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

•Reliability and sustaining activities in our refining segments.

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

Drilling Activity

	Net Stratigraphic Test Wells<br><br>and Observation Wells		Net Production Wells (1)
	2025	2024	2025	2024
Foster Creek	76	85	46	22
Christina Lake (2)	68	61	27	23
Sunrise	21	40	11	14
Lloydminster Thermal	68	53	12	22
Lloydminster Conventional Heavy Oil	2	19	83	49
Other (3)	—	—	5	—
	235	258	184	130

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

(2)Includes results of the MEG Acquisition from November 13, 2025.

(3)Includes new resource plays.

Stratigraphic test wells were drilled to help identify future well pad locations and to further evaluate our assets. Observation wells were drilled to gather information and monitor reservoir conditions.

	2025			2024
(net wells)	Drilled	Completed	Tied-in	Drilled	Completed	Tied-in
Conventional (1)	53	54	54	36	31	31

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

In the Offshore segment, no wells were drilled or completed in 2025 (2024 – drilled and evaluated one exploration well in China).

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	10
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
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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)

				Year Ended December 31,
(Average US$/bbl, unless otherwise indicated)	Q4 2025	Percent Change	Q4 2024	2025	Percent Change	2024
Dated Brent	63.69	(15)	74.69	69.06	(14)	80.76
WTI	59.14	(16)	70.27	64.81	(14)	75.72
Differential Dated Brent – WTI	4.55	3	4.42	4.25	(16)	5.04
WCS at Hardisty	47.94	(17)	57.71	53.68	(12)	60.97
Differential WTI – WCS at Hardisty	11.20	(11)	12.56	11.13	(25)	14.75
WCS at Hardisty (C$/bbl)	66.89	(17)	80.74	75.07	(10)	83.52
WCS at Nederland	55.63	(15)	65.69	61.74	(11)	69.69
Differential WTI – WCS at Nederland	3.51	(23)	4.58	3.07	(49)	6.03
Condensate (C5 at Edmonton)	57.01	(19)	70.66	63.36	(13)	72.94
Differential Condensate – WTI Premium/(Discount)	(2.13)	(646)	0.39	(1.45)	(48)	(2.78)
Differential Condensate – WCS at Hardisty Premium/(Discount)	9.07	(30)	12.95	9.68	(19)	11.97
Condensate (C$/bbl)	79.54	(20)	98.84	83.63	(16)	99.92
Synthetic at Edmonton	57.84	(19)	71.11	64.47	(14)	75.07
Differential Synthetic – WTI Premium/(Discount)	(1.30)	(255)	0.84	(0.34)	(48)	(0.65)
Synthetic at Edmonton (C$/bbl)	80.69	(19)	99.45	90.15	(12)	102.83
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	70.66	(11)	78.95	80.81	(10)	89.95
Chicago Ultra-low Sulphur Diesel (“ULSD”)	90.70	2	89.28	91.13	(7)	97.47
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)	18.20	50	12.12	19.44	16	16.74
Group 3 3-2-1 Crack Spread (2)	19.25	52	12.66	20.63	23	16.81
Renewable Identification Numbers (“RINs”)	6.04	50	4.02	5.81	55	3.74
Upgrading Differential (3) (C$/bbl)	13.53	(27)	18.64	14.92	(22)	19.21
Natural Gas Prices
AECO (4) (C$/Mcf)	2.23	51	1.48	1.68	15	1.46
NYMEX (5) (US$/Mcf)	3.55	27	2.79	3.43	51	2.27
Foreign Exchange Rates
US$ per C$1 – Average	0.717	—	0.715	0.716	(2)	0.730
US$ per C$1 – End of Period	0.730	5	0.695	0.730	5	0.695
RMB per C$1 – Average	5.084	(1)	5.142	5.144	(2)	5.255

(1)These benchmark prices are not our Realized Sales Prices and represent approximate values. For our Realized Sales Prices 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 adjusted 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 Canadian Refining assets; 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 2025, global crude oil benchmark prices, Brent and WTI, decreased compared with 2024, as global supply exceeded demand leading to inventory builds throughout the year. Global crude oil production increased considerably in 2025 as OPEC+ continued to unwind production cuts, while non-OPEC countries, including the United States, Canada and Brazil, also increased supply. Year-over-year demand growth in 2025 weakened compared with 2024 due to a combination of weaker macroeconomic conditions, trade tensions, and other softer industrial activity in major consuming regions.

Cenovus Energy Inc. – 2025 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.

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 2025, compared with 2024, due to:

•The Trans Mountain Pipeline expansion project (“TMX”) increasing market access for WCS crude.

•Low inventory levels in the Western Canadian Sedimentary Basin as well as strong global demand for heavy crudes.

•Strong pricing for fuel oil in which heavy grades yield more versus light grades.

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 2025, the WTI-WCS at Nederland differential narrowed compared with 2024, due to strong global demand for heavy crudes, as well as other factors as mentioned above.

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 2025, synthetic crude oil at Edmonton strengthened relative to WTI compared with 2024. The strength in pricing relative to 2024 was a function of deep discounts in the first quarter of 2024 due to high synthetic crude oil production in Alberta and the supply of light crude oil being above pipeline capacity on light crude oil pipelines with limited local storage capacity.

Crude Oil Benchmark Prices (1)

(1)Forward pricing as at February 2, 2026.

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 2025, the average Edmonton condensate benchmark traded at a smaller discount to WTI compared with 2024, due to the same factors impacting the synthetic crude oil to WTI differential, as discussed above, as well as tight Canadian supply and low Canadian inventories.

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 adjusted 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.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	12

In 2025, refined product crack spreads in Chicago and Group 3 increased compared with 2024. The increase can be largely attributed to strong product cracks as unplanned global and North American refinery outages supported refined product pricing and new refining capacity has been slow to ramp up. The average cost of RINs was higher in 2025, compared with 2024, due to weaker U.S. production and imports of renewable diesel and biodiesel causing a decline in RINs generation.

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 adjusted refining margin is affected by various other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output. The benchmark 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 February 2, 2026.

Natural Gas Benchmarks

In 2025, AECO prices increased compared with 2024, though not as much as the increase in NYMEX pricing. NYMEX prices increased more than AECO as NYMEX prices were supported by strong liquified natural gas (“LNG”) demand, while AECO prices were impacted by limited Western Canadian takeaway capacity, causing the AECO discount to NYMEX to widen. In 2025, both Western Canadian and U.S. natural gas production increased compared with 2024. 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 strengthens or weakens, our U.S. dollar debt gives rise to unrealized foreign exchange gains or losses, respectively, when translated to Canadian dollars. Changes in foreign exchange rates also impact the translation of our U.S. and Asia Pacific operations.

In 2025, on average, the Canadian dollar weakened relative to the U.S. dollar compared with 2024, positively impacting our reported revenues and negatively impacting our U.S. Refining operating expenses. 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 2025, on average, the Canadian dollar weakened relative to RMB, compared with 2024, positively impacting our reported revenues.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	13

Interest Rate Benchmarks

Our interest income, short-term and floating rate 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, 2025, the Bank of Canada’s policy interest rate was 2.25 percent. On January 28, 2026, the Bank of Canada held the policy interest rate at 2.25 percent.

OUTLOOK

Commodity Price Outlook

Global crude oil prices softened in 2025 as supply growth outpaced demand following the unwinding of OPEC+ voluntary cuts. Entering 2026, markets remain oversupplied, but price direction is uncertain and subject to volatility driven by policy decisions and geopolitical developments. OPEC+ policy continues to remain crucial to global oil supply and demand balances, and prices. Sanctions on Russian and Iranian crude and refined products have introduced persistent logistical challenges and altered trade flows globally. Policies regarding these regions will continue to be key factors that will drive energy supply. Policy and sanction uncertainty related to Venezuelan crude exports continues to influence global heavy crude oil supply and trade flows.

The global trade war and ongoing geopolitical tensions have the potential to reduce global GDP growth and oil demand, while increasing recessionary risks; however, the actual effects have been less pronounced than expected, and repeated pauses to tariffs have limited the direct economic impacts. There is potential for heightened price volatility across all commodities to continue until there is a firm resolution on the duration and magnitude of tariffs.

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

•OPEC+ policy and the pace at which OPEC+ unwinds production cuts.

•In the near-term, there is a higher risk of a tariff-induced global economic slowdown that could slow oil demand.

•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 does not exceed Canadian crude oil export capacity.

•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.

•AECO and NYMEX natural gas prices are expected to remain volatile. The prospect of new LNG facilities in the U.S. and Canada coming into service or ramping up in the next year could increase demand and support North American natural gas prices. Weather will also 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, the U.S. Administration’s 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 segment.

Our refining capacity is primarily focused in the U.S. Midwest, along with smaller exposures in the USGC and Alberta, exposing us 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 oil 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.

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Key Priorities for 2026

Our 2026 priorities are focused on top-tier safety performance, integration of MEG, maintaining and growing our competitive advantages in our heavy oil value chain, advancing our major projects and progressing our sustainability initiatives, while continuing to focus on cost leadership and balancing shareholder returns with deleveraging.

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.

Integration of MEG

The MEG Acquisition is expected to further strengthen our oil sands assets by integrating top-tier adjacent assets at Christina Lake. In 2026, we plan to complete a fully integrated development plan for Christina Lake intended to increase production, reduce costs and capture synergies across the combined asset.

Heavy Oil Value Chain

Our heavy oil value chain includes all of our bitumen and heavy oil producing, midstream and pipeline-connected downstream assets. Across the value chain, we will focus on increasing our optionality, optimizing our working capital, improving our margins and reducing our break-even pricing.

Project Execution

Investing in future growth and profitability is a priority for us with several key projects underway, including the West White Rose project, the Amine Claus project at Foster Creek, the Christina Lake North expansion project, the Sunrise growth program and development of our Lloydminster assets.

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 to heavy oil differentials.

We will continue to implement operational improvements to our downstream assets to maximize the long-term profitability of our assets.

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. Upon closing of the MEG Acquisition, we adjusted our shareholder returns framework to balance deleveraging with shareholder returns. Our long-term Net Debt target of $4.0 billion remains unchanged and the adjusted framework allows us to make progress towards this target. For further details, see the Liquidity and Capital Resources section of this MD&A.

Cost Leadership

We aim to maximize shareholder value through a 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.

Sustainability

Sustainability is central to Cenovus’s culture. We have established goals in our sustainability focus areas and we continue to advance work to support progress against these commitments.

The Government of Canada and the Government of Alberta have announced a framework aimed at strengthening federal-provincial collaboration in the energy sector to support a number of overlapping goals, including Canada’s greenhouse gas (“GHG”) emissions reduction ambitions. We continue to support our commitment to the Pathways Alliance, including efforts to reach agreements with the federal and provincial governments that provide sufficient fiscal and regulatory support to progress large-scale carbon capture projects, while maintaining global competitiveness.

Cenovus’s updated social commitments and 2024 Corporate Social Responsibility report, highlighting our performance in safety, Indigenous reconciliation, and acceptance and belonging, are available on our website at cenovus.com.

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2026 Corporate Guidance

Our 2026 corporate guidance dated December 10, 2025, is available on our website at cenovus.com.

Our 2026 corporate guidance for total capital investment is between $5.0 billion and $5.3 billion. This includes $3.5 billion to $3.6 billion directed towards sustaining capital to maintain base production and support continued safe and reliable operations, and between $1.2 billion and $1.4 billion of investment directed towards growth projects, such as:

•The Christina Lake North expansion project.

•The drilling program and ramping-up of production at the West White Rose field.

•The Sunrise growth program and the development of our Lloydminster assets.

The following table is a sub-set of our full updated guidance for 2026:

	Capital Investment<br><br>($ millions)	Production<br><br>(MBOE/d)	Crude Oil Unit Throughput<br><br>(Mbbls/d)
Upstream
Oil Sands	3,500 - 3,600	755 - 780
Conventional	450 - 500	120 - 125
Offshore	450 - 500	70 - 80
Upstream Total	4,400 - 4,600	945 - 985
Downstream
Canadian Refining			105 - 110
U.S. Refining			325 - 340
Downstream Total	600 - 700		430 - 450
Corporate and Eliminations	Up to 25
REPORTABLE SEGMENTS
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Our Operations

The Company operates through the following reportable segments:

Upstream Segments

•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets, as well as Christina Lake, which includes the results of the MEG Acquisition completed in November 2025. 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 HCML, which is engaged in the exploration for, and production of, NGLs and natural gas in offshore Indonesia.

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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. On September 30, 2025, Cenovus divested its entire 50 percent interest in the jointly-owned Wood River and Borger refineries held through WRB with operator Phillips 66. The U.S. Refining segment included the WRB results up to the date of divestiture. Cenovus markets its own and third-party refined products.

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 2025, we:

•Delivered safe and reliable operations, including the safe execution of turnarounds at Foster Creek and Sunrise.

•Completed the MEG Acquisition, which immediately contributed to our Christina Lake results.

•Produced 644.1 thousand BOE per day (2024 – 610.7 thousand BOE per day).

•Generated Operating Margin of $8.9 billion (2024 – $9.8 billion).

•Averaged a Netback of $38.37 per barrel (2024 – $44.88 per barrel).

•Invested capital of $2.9 billion for sustaining activities and growth projects.

In 2025, we completed the Narrows Lake tie-back to Christina Lake and ramped-up production. All major process units at the Foster Creek optimization project were brought online and the project was completed ahead of schedule, supporting incremental production. At Sunrise, we brought new well pads online to support continued production growth. At our Lloydminster conventional heavy oil assets, we made progress on our heavy oil development program.

Financial Results

($ millions)	2025	2024
Gross Sales
External Sales	21,541	21,857
Intersegment Sales	6,786	6,590
	28,327	28,447
Royalties	(2,920)	(3,274)
Revenues	25,407	25,173
Expenses
Purchased Product	2,886	1,851
Transportation and Blending	10,875	11,000
Operating	2,754	2,511
Realized (Gain) Loss on Risk Management	8	20
Operating Margin	8,884	9,791
Unrealized (Gain) Loss on Risk Management	3	(16)
Depreciation, Depletion and Amortization	3,433	3,117
Exploration Expense	11	2
(Income) Loss from Equity-Accounted Affiliates	(38)	(14)
Segment Income (Loss)	5,475	6,702
Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	17
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Operating Margin Variance

Year Ended December 31, 2025

(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.

Operating Results

	2024
Total Sales Volumes (1) (MBOE/d)	599.5
Crude Oil Production by Asset (Mbbls/d)
Foster Creek	196.0
Christina Lake (2)	234.2
Sunrise	49.6
Lloydminster Thermal	111.5
Lloydminster Conventional Heavy Oil	17.6
Total Crude Oil Production (3) (Mbbls/d)	608.9
Natural Gas (1) (MMcf/d)	11.1
Total Production (MBOE/d)	610.7
Netback (4) (/bbl)
Realized Sales Price	80.20
Royalties	14.92
Transportation and Blending	9.00
Operating	11.40
Total Netback (/bbl)	44.88

All values are in US Dollars.

(1)Bitumen, heavy crude oil and natural gas. Natural gas is a conventional natural gas product type.

(2)Includes results of the MEG Acquisition from November 13, 2025.

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

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

Revenues

Gross sales were relatively consistent in 2025 compared with 2024, due to lower Realized Sales Prices, offset by higher sales volumes.

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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 decreased in 2025 compared with 2024, mainly due to a lower WTI benchmark price, partially offset by a narrower WTI-WCS differential.

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.

In 2025, approximately 37 percent (2024 – 33 percent) of our sales volumes were sold at destinations outside of Alberta and approximately 25 percent (2024 – 20 percent) of our sales volumes were sold to our downstream operations.

Production Volumes

Oil Sands crude oil production increased in 2025, compared with 2024, primarily due to:

•Incremental production at Christina Lake following the MEG Acquisition in November 2025 and the ramp-up of production from Narrows Lake.

•Successful results from new well pads at Foster Creek and the completion of the Foster Creek optimization project, which supported additional production.

•Strong base production and additional volumes from new development wells at our Lloydminster conventional heavy oil assets.

The increase was partially offset by the temporary shut-in of production at our Rush Lake facilities following an incident in the second quarter of 2025.

Royalties

Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Saskatchewan.

In Alberta, oil sands royalties 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. Sunrise is a pre-payout 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.

In Saskatchewan, 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.

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Effective Royalty Rate (1)

Percent	2025	2024
Foster Creek	22.5	24.0
Christina Lake	25.3	27.3
Sunrise	6.2	6.1
Lloydminster (2)	12.2	11.7
Total Effective Royalty Rate	20.0	21.0

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

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

In 2025, Oil Sands royalties decreased compared with 2024, mainly due to lower realized pricing, partially offset by higher sales volumes. The Oil Sands effective royalty rate decreased, primarily due to lower realized prices and lower Alberta sliding scale oil sands royalty rates, combined with annual adjustments in 2025.

Expenses

Transportation and Blending

In 2025, blending expenses decreased compared with 2024, primarily due to lower condensate prices, partially offset by higher sales volumes.

In 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, primarily due to higher sales volumes on TMX and increased pipeline transportation rates on shipments to U.S. destinations, partially offset by lower sales volumes at U.S. destinations.

Per-Unit Transportation Expenses (1)

($/bbl)	2025	2024
Foster Creek	14.36	13.57
Christina Lake	6.86	6.53
Sunrise	15.42	16.07
Lloydminster (2)	3.23	3.95
Total Oil Sands	9.28	9.00

(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 sales volumes sold at West Coast destinations through the use of TMX, increasing to 32 percent (2024 – 20 percent), partially offset by lower rail costs. In 2025, our sales volumes to U.S. destinations were relatively consistent at 36 percent, compared with 37 percent in 2024.

At Christina Lake, per-unit transportation expenses increased primarily due to higher pipeline rates and higher sales volumes at West Coast destinations through the use of TMX, which increased to one percent, compared with no sales volumes in 2024. In 2025, our sales volumes to U.S. destinations were relatively consistent at 17 percent, compared with 18 percent in 2024.

At Sunrise, per-unit transportation expenses decreased primarily due to lower sales volumes at U.S. destinations, partially offset by higher use of TMX. In 2025, 36 percent of our sales volumes were sold at U.S. destinations (2024 – 67 percent) and 51 percent of our sales volumes were sold at West Coast destinations (2024 – 18 percent).

At Lloydminster, per-unit transportation expenses decreased primarily due to sales volumes at U.S. destinations decreasing to one percent compared with three percent in 2024.

Operating

Primary drivers of our operating expenses in 2025 were fuel, repairs and maintenance, and workforce. Total operating expenses in 2025 increased compared with 2024, primarily due to higher fuel costs and higher costs at our Lloydminster thermal assets related to the incident at Rush Lake.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	20

Per-Unit Operating Expenses (1)

($/bbl)	2025	Percent <br>Change	2024
Foster Creek
Fuel	2.12	1	2.10
Non-Fuel	7.64	(2)	7.77
Total	9.76	(1)	9.87
Christina Lake
Fuel	2.23	7	2.09
Non-Fuel	5.98	(9)	6.54
Total	8.21	(5)	8.63
Sunrise
Fuel	3.68	27	2.89
Non-Fuel	13.85	21	11.47
Total	17.53	22	14.36
Lloydminster (2)
Fuel	2.98	9	2.74
Non-Fuel	17.03	15	14.78
Total	20.01	14	17.52
Total Oil Sands
Fuel	2.46	7	2.30
Non-Fuel	9.35	3	9.10
Total	11.81	4	11.40

(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 increased in 2025, compared with 2024, due to higher AECO benchmark pricing and increased consumption volumes from well pads coming online at our Sunrise assets.

Foster Creek per-unit non-fuel costs decreased slightly in 2025, compared with 2024, primarily due to higher sales volumes, partially offset by higher turnaround costs in the second quarter of 2025.

Christina Lake per-unit non-fuel costs decreased in 2025, primarily due to higher sales volumes and lower turnaround expenses, compared with 2024.

Sunrise per-unit non-fuel costs increased in 2025, compared with 2024, primarily due to turnaround activities in the second and third quarters of 2025, partially offset by higher sales volumes.

Lloydminster per-unit non-fuel costs increased in 2025, compared with 2024, due to higher costs related to the Rush Lake incident in the second quarter of 2025.

Conventional

In 2025, we:

•Delivered safe and reliable operations.

•Produced 122.8 thousand BOE per day (2024 – 119.9 thousand BOE per day).

•Generated Operating Margin of $457 million, an increase of $166 million from 2024.

•Earned a Netback of $10.37 per BOE (2024 – $6.48 per BOE).

•Invested capital of $453 million, primarily related to drilling, completion, tie-in and infrastructure projects.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	21

Financial Results

($ millions)	2025	2024
Gross Sales
External Sales	1,305	1,211
Intersegment Sales	1,355	1,848
	2,660	3,059
Royalties	(55)	(76)
Revenues	2,605	2,983
Expenses
Purchased Product	1,337	1,823
Transportation and Blending	351	320
Operating	464	555
Realized (Gain) Loss on Risk Management	(4)	(6)
Operating Margin	457	291
Unrealized (Gain) Loss on Risk Management	(4)	4
Depreciation, Depletion and Amortization	479	442
Exploration Expense	22	1
(Income) Loss From Equity-Accounted Affiliates	—	2
Segment Income (Loss)	(40)	(158)

Operating Margin Variance

Year Ended December 31, 2025

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

(2)Includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	22

Operating Results

	2024
Total Sales Volumes (1) (MBOE/d)	119.9
Realized Sales Price (1) (2) (/BOE)
Light Crude Oil (/bbl)	92.68
NGLs (/bbl)	54.62
Conventional Natural Gas (/Mcf)	2.51
Production by Product (1)
Light Crude Oil (Mbbls/d)	4.9
NGLs (Mbbls/d)	21.0
Conventional Natural Gas (MMcf/d)	563.8
Total Production (MBOE/d)	119.9
Conventional Natural Gas Production (percentage of total)	78
Crude Oil and NGLs Production (percentage of total)	22
Effective Royalty Rate (1) (3) (percent)	10.3
Netback (1) (2) (/BOE)
Realized Sales Price	25.18
Royalties	1.73
Transportation and Blending	4.98
Operating	11.99
Total Netback (/BOE)	6.48

All values are in US Dollars.

(1)For the year ended December 31, 2025, reported production volumes, sales volumes, associated per-unit values and effective royalty rates include Cenovus’s 30 percent equity interest in the Duvernay joint venture.

(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.

Revenues

Gross sales decreased in 2025, compared with 2024, due to lower commodity trading volumes sourced from third parties, partially offset by higher Realized Sales Prices and sales volumes.

Price

Our total Realized Sales Price increased in 2025, compared with 2024, primarily due to higher sales volumes to U.S. destinations. In 2025, 31 percent of our natural gas sales volumes were sold at U.S. destinations (2024 – 28 percent) where NYMEX natural gas benchmark prices increased to US$3.43 per Mcf (2024 – US$2.27 per Mcf). The year-over-year increase was also due to AECO natural gas benchmark prices increasing to $1.68 per Mcf (2024 – $1.46 per Mcf).

Production Volumes

Production volumes increased in 2025, compared with 2024, primarily due to strong base performance. In 2024, production volumes were lower due to turnaround activities.

Royalties

The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties and the effective royalty rate decreased in 2025, compared with 2024, primarily due to overall lower benchmark prices used to calculate our royalties.

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 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, due to increased pipeline transportation rates.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	23

Operating

Primary drivers of operating expenses in 2025 were repairs and maintenance, workforce and property tax costs. Total operating expenses and per-unit operating expenses decreased compared with 2024, primarily due to lower turnaround costs, and processing and gathering costs.

Offshore

In 2025, we:

•Delivered safe and reliable operations.

•Produced 67.3 thousand BOE per day of light crude oil, NGLs and natural gas (2024 – 66.6 thousand BOE per day).

•Generated Operating Margin of $1.1 billion, an increase of $23 million from 2024.

•Averaged a Netback of $52.27 per BOE (2024 – $52.38 per BOE).

•Invested capital of $934 million, mainly related to the progression of the West White Rose project.

In 2025, we have made significant progress on the West White Rose project. The topsides were placed atop the concrete gravity structure, and we completed the subsea tie-ins to our existing production system at the SeaRose FPSO. Hookup and commissioning of the platform continued to progress and was substantially completed in the fourth quarter of 2025, despite challenging offshore weather conditions. First oil is anticipated in the second quarter of 2026.

Financial Results

	2025			2024
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	420	1,088	1,508	322	1,250	1,572
Intersegment Sales	—	—	—	—	—	—
	420	1,088	1,508	322	1,250	1,572
Royalties	(4)	(76)	(80)	(2)	(97)	(99)
Revenues	416	1,012	1,428	320	1,153	1,473
Expenses
Purchased Product	—	—	—	—	—	—
Transportation and Blending	17	—	17	11	—	11
Operating	226	123	349	290	133	423
Operating Margin (1)	173	889	1,062	19	1,020	1,039
Depreciation, Depletion and Amortization			440			563
Exploration Expense			8			66
(Income) Loss from Equity-Accounted Affiliates			(31)			(53)
Segment Income (Loss)			645			463

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

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	24

Operating Margin Variance

Year Ended December 31, 2025

(1)Includes other activities not attributable to the production of crude oil and natural gas.

Operating Results

	2025	2024
Sales Volumes
Atlantic (Mbbls/d)	11.3	8.0
Asia Pacific (MBOE/d)
China	38.3	42.6
Indonesia (1)	15.9	16.0
Total Asia Pacific	54.2	58.6
Total Sales Volumes (MBOE/d)	65.5	66.6
Production by Product
Atlantic – Light Crude Oil (Mbbls/d)	13.1	8.0
Asia Pacific (1)
NGLs (Mbbls/d)	7.6	11.0
Conventional Natural Gas (MMcf/d)	279.3	285.3
Total Asia Pacific (MBOE/d)	54.2	58.6
Total Production (MBOE/d)	67.3	66.6
Effective Royalty Rate (2) (percent)
Atlantic	1.0	0.7
Asia Pacific (1)	11.1	9.5

(1)Reported sales volumes, production volumes and royalty rates reflect Cenovus’s 40 percent equity interest in the HCML joint venture.

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

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	25

Netbacks (1)

	2025
($/BOE, except where indicated)	Atlantic (/bbl)	China	Indonesia		Total Offshore (2)
Realized Sales Price		77.81		59.31		76.66
Royalties		5.43		14.34		6.81
Transportation and Blending		—		—		0.70
Operating Expenses		8.16		11.39		16.88
Netback		64.22		33.58		52.27

All values are in US Dollars.

	2024
($/BOE, except where indicated)	Atlantic (/bbl)	China	Indonesia		Total Offshore (2)
Realized Sales Price		80.26		57.82		78.40
Royalties		6.19		9.32		6.29
Transportation and Blending		—		—		0.46
Operating Expenses		7.61		10.93		19.27
Netback		66.46		37.57		52.38

All values are in US Dollars.

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

(2)Reported per-unit values reflect Cenovus’s 40 percent equity interest in the HCML joint venture.

Revenues

Gross sales decreased in 2025, compared with 2024, due to lower sales volumes in China and lower Realized Sales Prices, partially offset by higher sales volumes in our Atlantic operations.

Price

Our Atlantic Realized Sales Price decreased in 2025, compared with 2024, 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

Light crude oil production from the White Rose and Terra Nova fields are offloaded from the SeaRose and Terra Nova FPSO vessels, respectively, to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales.

Atlantic production increased in 2025, compared with 2024, primarily due to production resuming at the White Rose field in the first quarter of 2025 following completion of the SeaRose ALE project. Atlantic production was lower in 2024, as production at the White Rose field was suspended in late December 2023 in preparation for the project.

Asia Pacific production decreased in 2025, compared with 2024, primarily due to lower contracted sales volumes in China.

Royalties

Royalty rates at the White Rose and Terra Nova fields are governed by an agreement with the Government of Newfoundland and Labrador which limits royalties to one percent of gross revenues until certain costs incurred have been recovered. For the year ended December 31, 2025, the Atlantic effective royalty rate was relatively consistent compared with 2024.

Royalty rates in Asia Pacific are governed by production-sharing contracts, in which production is shared with the Chinese and Indonesian governments.

Expenses

Transportation

Transportation expenses include the costs of transporting crude oil from the SeaRose and Terra Nova FPSOs to onshore terminals and storage costs. Transportation expenses for the year ended December 31, 2025, increased to $17 million (2024 – $11 million), primarily due to higher Atlantic sales volumes.

Operating

Primary drivers of our Atlantic operating expenses in 2025 were repairs and maintenance, costs related to vessels and air services, and workforce. Operating expenses decreased compared with 2024, primarily due to lower repairs and maintenance, and vessels and air service costs as the SeaRose ALE project was completed in the first quarter of 2025. Per-unit operating expenses decreased compared with 2024, due to higher sales volumes and lower costs related to the SeaRose ALE project, as discussed.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	26

Primary drivers of our China operating expenses in 2025 were repairs and maintenance, workforce and insurance costs. Per-unit operating expenses increased in 2025, compared with 2024, primarily due to lower sales volumes.

Primary drivers of our Indonesia operating expenses in 2025 were repairs and maintenance, and workforce costs. Per-unit operating expenses increased, compared with 2024, due to higher repairs and maintenance costs, partially offset by lower vessel costs.

DOWNSTREAM

Canadian Refining

In 2025, we:

•Delivered safe and reliable operations.

•Achieved record annual throughput of 110.7 thousand barrels per day and crude unit utilization of 103 percent (2024 – 90.5 thousand barrels per day and 84 percent, respectively).

•Incurred per-unit operating expenses excluding turnaround costs of $11.54 per barrel (2024 – $15.38 per barrel).

•Generated Operating Margin of $354 million, an increase of $434 million from 2024.

•Invested capital of $117 million, primarily focused on sustaining activities.

Financial and Operating Results

($ millions)	2025	2024
Revenues	5,079	5,310
Purchased Product	4,128	4,483
Gross Margin (1)	951	827
Expenses
Operating	597	907
Operating Margin	354	(80)
Depreciation, Depletion and Amortization	178	185
Segment Income (Loss)	176	(265)

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

($ millions, except where indicated)	2025	2024
Gross Margin	951	827
Add (Deduct):
Inventory Holding (Gain) Loss (1)	3	(2)
Adjusted Gross Margin (2)	954	825
Adjusted Refining Margin (3) ($/bbl)	19.57	20.72

(1)Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the first-in, first-out (“FIFO”) or weighted average cost basis, as required by IFRS Accounting Standards.

(2)Non-GAAP 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. Revenues from the Upgrader, the Lloydminster Refinery and the commercial fuels business for the year ended December 31, 2025, were $4.8 billion (2024 – $5.0 billion).

Revenues, Adjusted Gross Margin and Adjusted Refining Margin

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

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.

Revenues decreased compared with 2024, due to lower refined product pricing partially offset by higher sales volumes.

Adjusted Gross Margin increased in 2025, compared with 2024, primarily due to lower feedstock costs as a result of lower benchmark crude pricing and higher sales volumes, partially offset by lower refined product pricing and the narrowing of the WTI-WCS differential.

Adjusted Refining Margin decreased in 2025, as the increase in Adjusted Gross Margin, as discussed above, was more than offset by the increase in total processed inputs.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	27
(Mbbls/d, except where indicated)	2025	2024
---	---	---
Operable Capacity	108.0	108.0
Total Processed Inputs	119.4	96.6
Crude Oil Unit Throughput	110.7	90.5
Crude Unit Utilization (percent)	103	84
Total Production	127.3	103.1
Synthetic Crude Oil	52.0	41.0
Asphalt	17.9	15.7
Diesel	15.2	10.8
Other	37.2	30.8
Ethanol	5.0	4.8

The Upgrader and Lloydminster Refinery source their crude oil feedstock from our Oil Sands segment. In 2025, 14 percent of our Oil Sands segment’s sales volumes were purchased by our Canadian Refining segment (2024 – 12 percent).

Throughput and total production increased in 2025, compared with 2024. In 2025, our assets ran at, or above, full capacity due to ongoing improvement initiatives and high asset reliability. In 2024, we safely completed the largest turnaround in the history of the Upgrader, which decreased throughput and increased operating expenses.

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)	2025	2024
Operating Expenses – Upgrading and Refining	505	798
Operating Expenses – Excluding Turnaround Costs	503	544
Operating Expenses – Turnaround Costs	2	254
Per-Unit Operating Expenses (1) ($/bbl)	11.59	22.56
Per-Unit Operating Expenses – Excluding Turnaround Costs	11.54	15.38
Per-Unit Operating Expenses – Turnaround Costs	0.05	7.18

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

Primary drivers of operating expenses were workforce, and repairs and maintenance.

In 2025, operating expenses decreased compared with 2024, mainly due to lower turnaround costs and other project costs. Turnaround costs and other project costs were higher in 2024 due to the turnaround completed at the Upgrader, as discussed above.

Operating expenses excluding turnaround costs decreased in 2025, compared with 2024, due to lower project costs.

In 2025, the decrease in operating expenses, combined with increased total processed inputs, resulted in decreased per-unit operating expense metrics compared with 2024.

U.S. Refining

In 2025, we:

•Delivered safe and reliable operations.

•Recorded throughput of 515.9 thousand barrels per day compared with 556.4 thousand barrels per day in 2024 and crude unit utilization of 94 percent (2024 – 91 percent).

•Decreased per-unit operating expenses excluding turnaround costs to $10.88 per barrel (2024 – $11.55 per barrel).

•Recorded an Operating Margin shortfall of $149 million (2024 – $232 million).

•Invested capital of $442 million, primarily focused on reliability and sustaining activities.

•Completed the WRB Divestiture on September 30, 2025.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	28

Financial and Operating Results

($ millions)	2025	2024
Revenues	24,118	28,308
Purchased Product	21,727	25,769
Gross Margin (1)	2,391	2,539
Expenses
Operating	2,546	2,763
Realized (Gain) Loss on Risk Management	(6)	8
Operating Margin	(149)	(232)
Unrealized (Gain) Loss on Risk Management	(5)	8
Depreciation, Depletion and Amortization	566	462
Segment Income (Loss)	(710)	(702)

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

($ millions, except where indicated)	2025	2024
Gross Margin	2,391	2,539
Add (Deduct):
Inventory Holding (Gain) Loss (1)	298	(23)
Adjusted Gross Margin (2)	2,689	2,516
Adjusted Refining Margin (2) ($/bbl)	13.44	11.83
Weighted Average Crack Spread, Net of RINs (US$/bbl)	13.85	13.01
Weighted Average Crack Spread, Net of RINs (C$/bbl)	19.34	17.82
Adjusted Market Capture (2) (percent)	69	67

(1)Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the FIFO or weighted average cost basis, as required by IFRS Accounting Standards.

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

Revenues

Revenues decreased in 2025, compared with 2024, primarily due to lower sales volumes as a result of the WRB Divestiture and lower refined product pricing.

Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture

Benchmark 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.

In 2025, the Chicago 3-2-1 crack spread increased 16 percent and the Group 3 3-2-1 crack spread increased 23 percent compared with 2024. The increase in crack spreads was partially offset by a 55 percent increase in the average cost of RINs, compared with 2024.

Year-over-year, Adjusted Gross Margin increased primarily due to improved reliability, the receipt of Small Refinery Exemption waivers, and a pipeline settlement. The increase in weighted average crack spreads, net of RINs, was offset by the narrowing of the WTI-WCS differential.

Adjusted Refining Margin, which is the Adjusted 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; and the cost of feedstock.

Adjusted Refining Margin and Adjusted Market Capture increased in 2025, compared with 2024, due to the increase in Adjusted Gross Margin discussed above and lower total processed inputs.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	29
(Mbbls/d, except where indicated)	2025	2024
---	---	---
Operable Capacity (1)	549.9	612.3
Total Processed Inputs	548.1	581.4
Crude Oil Unit Throughput	515.9	556.4
Heavy Crude Oil	197.9	219.6
Light/Medium Crude Oil	318.0	336.8
Crude Unit Utilization (1) (percent)	94	91
Total Refined Product Production	559.9	590.0
Gasoline	266.7	280.5
Distillates (2)	195.3	209.1
Asphalt	23.9	28.3
Other	74.0	72.1

(1)For the year ended December 31, 2025, reported operable capacity and crude unit utilization reflects the weighted average impact of the WRB Divestiture, which closed on September 30, 2025.

(2)Includes diesel and jet fuel.

Throughput and refined product production decreased in 2025, compared with 2024. The decrease was primarily due to the WRB Divestiture on September 30, 2025, and turnarounds at our Toledo Refinery and non-operated Wood River and Borger refineries during the year. For the nine months ended September 30, 2025, WRB recorded crude oil throughput of 238.7 thousand barrels per day and refined product production of 248.8 thousand barrels per day net to Cenovus. The decreased throughput and refined product production was partially offset by improved reliability across our operated refineries, driven by ongoing operational improvements made to the U.S. Refining business. In 2024, throughput and refined product production were affected by the turnarounds at the Lima Refinery and non-operated Borger Refinery.

Operating Expenses

($ millions, except where indicated)	2025	2024
Operating Expenses	2,546	2,763
Operating Expenses – Excluding Turnaround Costs	2,176	2,457
Operating Expenses – Turnaround Costs	370	306
Per-Unit Operating Expenses (1) ($/bbl)	12.73	12.99
Per-Unit Operating Expenses – Excluding Turnaround Costs	10.88	11.55
Per-Unit Operating Expenses – Turnaround Costs	1.85	1.44

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

Primary drivers of operating expenses were repairs and maintenance, workforce and turnaround costs.

Operating expenses decreased in 2025, compared with 2024, primarily due to lower repairs and maintenance, and project costs, partially offset by an increase in turnaround costs. Overall operating expenses were lower in 2025, compared with 2024, due in part to the WRB Divestiture in September 2025.

Turnaround costs increased compared with 2024, due to the turnaround completed at the Toledo Refinery and at the non-operated Wood River and Borger refineries. In 2024, turnarounds were completed at the Lima Refinery and the non-operated Borger refinery.

Operating expenses excluding turnaround costs and related per-unit metrics for 2025 decreased compared with 2024. This was mainly due to lower controllable operating expenses, including lower repairs and maintenance and project costs, as well as the positive benefits of ongoing business improvement initiatives and improved reliability in our operated downstream assets. The decreases in operating expenses excluding turnaround costs were partially offset by higher electricity costs.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	30

CORPORATE AND ELIMINATIONS

Financial Results

($ millions)	2025	2024
Realized (Gain) Loss on Risk Management	(20)	24
Unrealized (Gain) Loss on Risk Management	(9)	16
General and Administrative	812	794
Finance Costs, Net	569	514
Integration, Transaction and Other Costs	234	166
Foreign Exchange (Gain) Loss, Net	(361)	462
(Gain) Loss on Divestiture of Assets	(87)	(119)
Other (Income) Loss, Net	(115)	(55)

General and Administrative

Primary drivers of our general and administrative expenses in 2025 were workforce and information technology related costs. The increase in general and administrative costs was primarily due to higher long-term incentive costs, partially offset by general cost saving initiatives.

Finance Costs, Net

Net finance costs were higher in 2025, compared with 2024, primarily due to lower interest income, and higher interest expenses on higher average debt. 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 2025 was 4.5 percent (2024 – 4.5 percent).

Integration, Transaction and Other Costs

In 2025, we incurred $234 million in integration, transaction and other costs largely due to integration and transaction costs from the MEG Acquisition and costs related to the standardization of data governance to enhance efficiency and effectiveness of the Company’s information technology systems.

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.

Foreign Exchange (Gain) Loss, Net

($ millions)	2025	2024
Unrealized Foreign Exchange (Gain) Loss	(424)	550
Realized Foreign Exchange (Gain) Loss	63	(88)
	(361)	462

Unrealized foreign exchange losses and gains were primarily due to the translation of U.S. denominated debt. As at December 31, 2025, the Canadian dollar strengthened five percent relative to the U.S. dollar at December 31, 2024. As at December 31, 2024, the Canadian dollar was eight percent weaker relative to the U.S. dollar at December 31, 2023. In 2025, realized foreign exchange losses were primarily related to working capital and the repayment of U.S. denominated debt.

(Gain) Loss on Divestiture of Assets

In 2025, the Company recorded a before-tax gain of $119 million related to the WRB Divestiture. The Company also divested certain Lloydminster thermal assets in the Oil Sands segment and recorded a before-tax loss of $58 million.

Prior to the closing of the MEG Acquisition, the Company held an aggregate of 25.0 million common shares of MEG. The acquisition-date fair value of the previously held MEG common shares was estimated to be $775 million and the net carrying value was $752 million. Cenovus recognized a revaluation gain of $23 million, which is recorded in gain (loss) on divestiture of assets in net earnings (loss).

In 2024, we recorded a before-tax gain of $65 million on the divestiture of assets related to Duvernay, and a before-tax gain of $51 million for the sale of non-core assets in our Conventional segment.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	31

Income Taxes

($ millions)	2025	2024
Current Tax
Canada	540	1,141
United States	(1)	9
Asia Pacific	198	214
Other International	41	39
Total Current Tax Expense (Recovery)	778	1,403
Deferred Tax Expense (Recovery)	(231)	(474)
	547	929

For the year ended December 31, 2025, the decline in current income tax expense was primarily due to the impact of the MEG Acquisition. The effective tax rate for 2025 was 12.2 percent (2024 – 22.8 percent). The lower effective tax rate in 2025 is primarily attributable to the reclassification of the cumulative foreign currency translation adjustment associated with the WRB Divestiture, which is not tax effected.

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 rates and other legislation.

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.

QUARTERLY RESULTS

Our results for the fourth quarter of 2025 reflect strong operational performance in the upstream business, lower throughput in our downstream operations, mainly due to the impact of the WRB Divestiture, and financial results impacted by a declining commodity price environment compared with the third quarter of 2025.

•Upstream production averaged 917.9 thousand BOE per day, an increase of 85.0 thousand BOE per day from the third quarter of 2025, mainly due to completion of the MEG Acquisition in November 2025. In addition, production increased due to successful development and optimization programs at our Lloydminster thermal assets.

•In the quarter, we achieved milestones for key projects. We fully ramped-up production at the Narrows Lake tie-back to Christina Lake project. All major process units at the Foster Creek optimization project were brought online and the project was completed ahead of schedule, supporting incremental production. At Sunrise, the first of the new well pads in the east development area commenced steam injection.

•Commissioning of the platform at the West White Rose project continued despite challenging weather conditions. Construction and welding is complete and integration testing is underway.

•Downstream throughput decreased 35 percent from the third quarter of 2025 to 465.5 thousand barrels per day, due to the WRB Divestiture.

•Benchmark WTI prices decreased from US$64.93 per barrel to US$59.14 per barrel, and WCS at Hardisty decreased from US$54.54 per barrel to US$47.94 per barrel in the fourth quarter of 2025. Additionally, the Chicago 3-2-1 crack spread and the Group 3 3-2-1 crack spread fell 25 percent and 19 percent, respectively, from the third quarter of 2025 to US$18.20 and US$19.25 per barrel, respectively.

•U.S. Refining Adjusted Market Capture increased 41 percent from the third quarter to 106 percent, driven by the receipt of a pipeline settlement in the quarter and continued reliability, which allowed us to take advantage of market conditions.

•Cash from operating activities increased to $2.4 billion from $2.1 billion in the third quarter of 2025, and Adjusted Funds Flow increased to $2.7 billion, an eight percent increase from the third quarter, as the lower Operating Margin was more than offset by lower current tax expense.

•We returned $1.1 billion to shareholders through common and preferred share base dividends of $380 million, and $714 million through our NCIB.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	32

Summary of Quarterly Results

	2024
( millions, except where indicated)		Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Average Commodity Prices (1) (US/bbl)
Dated Brent		63.69	69.07	67.82	75.66	74.69	80.18	84.94	83.24
WTI		59.14	64.93	63.74	71.42	70.27	75.09	80.57	76.96
WCS at Hardisty		47.94	54.54	53.47	58.75	57.71	61.54	66.96	57.65
Differential WTI-WCS at Hardisty		11.20	10.39	10.27	12.67	12.56	13.55	13.61	19.31
Chicago 3-2-1 Crack Spread (2)		18.20	24.24	21.64	13.68	12.12	18.62	18.76	17.45
Group 3 3-2-1 Crack Spread (2)		19.25	23.72	23.07	16.48	12.66	18.95	18.13	17.50
RINs		6.04	6.33	6.12	4.76	4.02	3.89	3.39	3.68
Upstream Production Volumes (3)
Bitumen (Mbbls/d)		696.2	615.2	552.1	602.5	608.6	569.6	591.7	595.4
Heavy Crude Oil (Mbbls/d)		28.1	25.4	25.0	21.8	18.0	16.3	18.1	17.9
Light Crude Oil (Mbbls/d)		22.3	16.3	17.0	16.8	12.3	13.6	13.5	12.5
NGLs (Mbbls/d)		27.9	27.8	29.9	29.8	31.7	31.0	33.0	32.4
Conventional Natural Gas (MMcf/d)		860.4	889.5	851.4	887.9	873.3	844.6	867.2	855.8
Total Production Volumes (MBOE/d)		917.9	832.9	765.9	818.9	816.0	771.3	800.8	800.9
Downstream Total Processed Inputs (4) (Mbbls/d)		498.4	757.6	714.9	700.5	700.5	674.4	652.9	683.8
Crude Oil Unit Throughput (4) (Mbbls/d)		465.5	710.7	665.8	665.4	666.7	642.9	622.7	655.2
Downstream Production Volumes (4) (Mbbls/d)		527.5	770.3	729.4	722.4	722.6	685.2	659.5	702.1
Revenues		10,883	13,195	12,319	13,299	12,813	13,819	14,582	13,063
Operating Margin (5)		2,777	2,954	2,066	2,811	2,274	2,408	2,936	3,191
Operating Margin – Upstream (6)		2,628	2,590	2,137	3,048	2,670	2,731	3,089	2,631
Operating Margin – Downstream (6)		149	364	(71)	(237)	(396)	(323)	(153)	560
Cash From (Used in) Operating Activities		2,408	2,131	2,374	1,315	2,029	2,474	2,807	1,925
Adjusted Funds Flow (5)		2,674	2,466	1,519	2,212	1,601	1,960	2,361	2,242
Per Share – Basic (5) ()		1.47	1.38	0.84	1.21	0.88	1.06	1.27	1.20
Per Share – Diluted (5) ()		1.46	1.38	0.84	1.21	0.87	1.05	1.26	1.19
Capital Investment		1,360	1,154	1,164	1,229	1,478	1,346	1,155	1,036
Free Funds Flow (5)		1,314	1,312	355	983	123	614	1,206	1,206
Excess Free Funds Flow (5)		(1,597)	745	(306)	373	(416)	146	735	832
Net Earnings (Loss)		934	1,286	851	859	146	820	1,000	1,176
Per Share – Basic ()		0.51	0.72	0.47	0.47	0.08	0.44	0.53	0.62
Per Share – Diluted ()		0.50	0.72	0.45	0.47	0.07	0.42	0.53	0.62
Total Assets		63,424	53,573	55,820	56,380	56,539	54,680	56,000	54,994
Long-Term Debt, Including Current Portion		11,032	7,156	7,241	7,524	7,534	7,199	7,275	7,227
Net Debt		8,292	5,255	4,934	5,079	4,614	4,196	4,258	4,827
Cash Returns to Common and Preferred Shareholders		1,094	1,274	819	595	706	1,070	1,034	436
Common Shares – Base Dividends		376	356	364	327	330	329	334	262
Base Dividends Per Common Share ()		0.200	0.200	0.200	0.180	0.180	0.180	0.180	0.140
Common Shares – Variable Dividends		—	—	—	—	—	—	251	—
Variable Dividends Per Common Share ()		—	—	—	—	—	—	0.135	—
Purchase of Common Shares Under NCIB		714	918	301	62	108	732	440	165
Dividends Paid on Preferred Shares		4	—	4	6	18	9	9	9
Preferred Share Redemption		—	—	150	200	250	—	—	—

All values are in US Dollars.

(1)These benchmark prices are not our Realized Sales Prices and represent approximate values.

(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)Includes results of the MEG Acquisition from November 13, 2025.

(4)Represent Cenovus’s net interest in refining operations. Following the WRB Divestiture, all refining operations are wholly-owned.

(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. – 2025 Management's Discussion and Analysis	33

Fourth Quarter 2025 Results Compared with the Fourth Quarter 2024

The summary below compares financial and operating results for the three months ended December 31, 2025, compared with the same period in 2024.

Upstream Production Volumes

Total upstream production increased 101.9 thousand BOE per day in the fourth quarter of 2025, compared with 2024, primarily due to:

•Incremental production at Christina Lake following the MEG Acquisition in November 2025 and the ramp-up of production from Narrows Lake.

•Successful results from new well pads at Foster Creek and the completion of the Foster Creek optimization project, which supported additional production.

•Production resuming at the White Rose field following the completion of the SeaRose ALE project.

The increases were partially offset by the temporary shut-in of production at our Rush Lake facilities following an incident in the second quarter of 2025. In the fourth quarter, we successfully restarted production and the phased ramp-up is progressing as expected.

Downstream Refining Throughput and Production

Canadian Refining operations were strong in the fourth quarter with crude unit utilization of 105 percent (2024 – 97 percent). Throughput increased 8.5 thousand barrels per day to 112.9 thousand barrels per day and production increased 12.9 thousand barrels per day to 131.3 thousand barrels per day compared with 2024. In 2025, our assets ran at, or above full capacity due to ongoing improvement initiatives and continued high asset reliability.

U.S. Refining crude unit utilization increased to 97 percent (2024 – 92 percent) due to higher reliability and ongoing operational improvements. Throughput decreased 209.7 thousand barrels per day to 352.6 thousand barrels per day and total refined product production decreased 208.0 thousand barrels per day to 396.2 thousand barrels per day compared with 2024, primarily due to the WRB Divestiture.

Operating Margin

Three Months Ended December 31, 2025 and 2024

Operating Margin increased compared with the fourth quarter of 2024, primarily due to:

•Higher sales volumes in our Oil Sands and Canadian Refining segments.

•Higher market crack spreads in our U.S. Refining segment and the receipt of a pipeline settlement during the quarter.

The increase was partially offset by:

•Lower Realized Sales Prices impacting revenues in our Oil Sands segment due to lower benchmark WTI prices, partially offset by a narrower WTI-WCS differential.

•Increased operating expenses in our Oil Sands segment due to higher fuel costs.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	34

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

Cash from operating activities increased $379 million to $2.4 billion in the fourth quarter of 2025, compared with the fourth quarter of 2024, primarily due to lower current tax expense and higher Operating Margin, partially offset by the changes in non-cash working capital. The 2025 net change in non-cash working capital was primarily due to decreases in accounts receivable. In 2024, the net change in non-cash working capital was primarily due to increases in accounts payable and taxes payable, combined with a decrease in accounts receivable, partially offset by increased inventories.

Adjusted Funds Flow increased to $2.7 billion in the fourth quarter of 2025, compared with $1.6 billion in 2024, primarily due to lower current tax expense and higher Operating Margin, partially offset by integration, transaction and other costs related to the MEG Acquisition.

Net Earnings (Loss)

Net earnings were $934 million in the fourth quarter of 2025 compared with $146 million in the fourth quarter of 2024. The increase was primarily due to an increase in Operating Margin and foreign exchange gains, compared with losses in 2024, partially offset by an increase in depreciation, depletion and amortization.

Capital Investment

Capital investment was $1.4 billion in the fourth quarter of 2025, compared with $1.5 billion in the fourth quarter of 2024, as we continued our sustaining activities and upstream growth projects.

| OIL AND GAS RESERVES | | --- || As at December 31, 2025<br><br>(before royalties) (1) (2) | Bitumen (3)<br><br>(MMbbls) | Light and<br><br>Medium Oil<br><br>(MMbbls) | NGLs<br><br>(MMbbls) | Conventional Natural Gas (4)<br><br>(Bcf) | Total<br><br>(MMBOE) | | --- | --- | --- | --- | --- | --- | | Total Proved | 5,697 | 87 | 59 | 1,745 | 6,135 | | Probable | 3,227 | 71 | 28 | 878 | 3,472 | | Total Proved Plus Probable | 8,924 | 158 | 87 | 2,622 | 9,607 || As at December 31, 2024<br><br>(before royalties) (1) (2) | Bitumen (3)<br><br>(MMbbls) | Light and<br><br>Medium Oil<br><br>(MMbbls) | NGLs<br><br>(MMbbls) | Conventional Natural Gas (4)<br><br>(Bcf) | Total<br><br>(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 |

(1)Totals may not sum due to rounding.

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

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

(4)Includes shale gas that is not material.

The following developments occurred in 2025 compared with 2024:

•Bitumen gross total proved and gross total proved plus probable reserves increased by 518 million barrels and 1,245 million barrels, respectively. The changes were due to the MEG Acquisition, 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. These increases were partially offset by current year production and negative technical revisions resulting from recovery factor changes at Christina Lake and Foster Creek, and a minor disposition at Lloydminster thermal.

•Light and medium oil gross total proved and gross total proved plus probable reserves decreased by four million barrels and 10 million barrels, respectively. The changes were due to current year production and negative technical revisions due to updates to the Conventional segment development plans. These decreases were partially offset by extensions due to updates to the Conventional segment development plans.

•NGLs gross total proved and gross total proved plus probable reserves decreased by 10 million barrels and 20 million barrels, respectively. The changes were due to current year production, negative technical revisions due to updates to the Conventional segment development plans and negative technical revisions due to reductions to recovery performance in Indonesia. These reductions were partially offset by extensions due to updates to the Conventional segment development plans and technical revisions due to improvements to recovery performance in China.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	35

•Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 205 billion cubic feet and 399 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 negative technical revisions due to reductions to recovery performance in Indonesia. 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 in China and minor acquisitions in the Conventional segment.

The reserves data is presented as at December 31, 2025, using an average of the forecast prices, inflation and exchange rates (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule ERCE. The Average Forecast is dated January 1, 2026. Comparative information as at December 31, 2024, uses the January 1, 2025, Average Forecast.

Additional information with respect to the evaluation and reporting of our reserves in accordance with NI 51-101 is contained in our AIF for the year ended December 31, 2025. 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.

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. Our other sources of liquidity include 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. The cost and availability of borrowing, and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.

($ millions)	2025	2024
Cash From (Used In)
Operating Activities	8,228	9,235
Investing Activities	(7,677)	(5,126)
Net Cash Provided (Used) Before Financing Activities	551	4,109
Financing Activities	(749)	(3,505)
Effect of Foreign Exchange on Cash and Cash Equivalents	(155)	262
Increase (Decrease) in Cash and Cash Equivalents	(353)	866
As at December 31, ($ millions)	2025	2024
Cash and Cash Equivalents	2,740	3,093
Total Debt	11,032	7,707

Cash From (Used in) Operating Activities

In 2025, cash from operating activities decreased compared with 2024, primarily due to changes in non-cash working capital, partially offset by lower current tax expense and lower cash-settled long-term incentive costs. Non-cash working capital decreased cash from operating activities by $363 million, primarily due to an increase in accounts receivable, and decreases in accounts payable and income tax payable, partially offset by a decrease in inventories, excluding the impact of the MEG Acquisition and the WRB Divestiture.

In 2024, the change in non-cash working capital was a source of cash of $1.3 billion due to lower accounts receivable, higher accounts payable and higher taxes payable, partially offset by higher inventories.

Cash From (Used in) Investing Activities

Cash used in investing activities increased in 2025 compared with 2024. Cash used in investing activities primarily relates to capital investment and the MEG Acquisition, partially offset by proceeds from the WRB Divestiture.

Cash From (Used in) Financing Activities

In 2025, cash used in financing activities was $749 million, compared with $3.5 billion in 2024, primarily due to the redemption of certain senior unsecured notes and higher share purchases under the Company’s NCIB, partially offset by an increase in long-term debt from the receipt of a $2.7 billion term loan facility and the issuance of $2.6 billion of senior unsecured notes.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	36

Working Capital

Working capital as at December 31, 2025, was $3.6 billion (December 31, 2024 – $3.1 billion). The increase was primarily driven by higher accounts receivable and lower accounts payable, partially offset by lower 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 a WTI price of approximately US$45.00 per barrel.

Upon closing of the MEG Acquisition, we adjusted our shareholder returns framework as follows:

•While Net Debt is above $6.0 billion, the Company will target to return approximately 50 percent of Excess Free Funds Flow to shareholders, with the remainder allocated to deleveraging.

•When Net Debt is between $6.0 billion and $4.0 billion, the Company will target to return approximately 75 percent of Excess Free Fund Flow to shareholders, with the remainder allocated to deleveraging.

Our long-term Net Debt target of $4.0 billion remains unchanged, and upon reaching the targeted levels, we plan to return approximately 100 percent of Excess Free Funds Flow to shareholders over time while stewarding 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.

As at December 31, 2025, our Net Debt position was $8.3 billion and, as a result, our returns to shareholders target for the three months ended March 31, 2026, will be 50 percent of the first quarter’s Excess Free Funds Flow.

Short-Term Borrowings

There were no direct borrowings on our uncommitted demand facilities as at December 31, 2025, or December 31, 2024. On September 30, 2025, Cenovus completed the WRB Divestiture, which included the Company’s proportionate share of the WRB uncommitted demand facilities outstanding of US$225 million (C$313 million). Cenovus’s proportionate share of the WRB uncommitted demand facilities outstanding as at December 31, 2024, was US$120 million (C$173 million).

Long-Term Debt, Including Current Portion

As at December 31, ($ millions)	2025	2024
Term Loan Facility	2,700	—
U.S. Dollar Denominated Senior Unsecured Notes	5,887	5,470
Canadian Dollar Senior Unsecured Notes	2,450	2,000
Total Debt Principal	11,037	7,470

Upon maturity on July 15, 2025, the Company repaid its 5.38 percent senior unsecured notes with a principal of US$133 million, in full.

We obtained a $2.7 billion term loan facility maturing on February 28, 2029, to fund a portion of the cash consideration for the MEG Acquisition. Upon closing of the MEG Acquisition, we assumed MEG’s U.S. dollar senior unsecured notes with a principal of US$600 million. The notes were subsequently redeemed on December 1, 2025, in full.

On November 20, 2025, the Company closed public offerings in Canada and the U.S. of senior unsecured notes of $2.6 billion, composed of $650 million 4.25 percent notes due in 2033, $550 million 4.60 percent notes due in 2035, US$500 million 4.65 percent notes due in 2031 and US$500 million 5.40 percent notes due in 2036.

On December 1, 2025, the Company redeemed its 4.25 percent senior unsecured notes with a principal of US$373 million, in full. On December 22, 2025, the Company redeemed its 3.60 percent senior unsecured notes with a principal of $750 million, in full.

As at December 31, 2025, we were in compliance with all of the terms of our debt agreements, which includes the terms of our committed credit facility and term loan 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. – 2025 Management's Discussion and Analysis	37

Available Sources of Liquidity

The following sources of liquidity are available as at December 31, 2025:

($ millions)	Maturity	Amount Available
Cash and Cash Equivalents	n/a	2,740
Committed Credit Facility (1)
Revolving Credit Facility – Tranche A	September 19, 2029	3,300
Revolving Credit Facility – Tranche B	September 19, 2028	2,200
Uncommitted Demand Facilities (2)	n/a	1,116

(1)No amounts were drawn on the committed credit facility as at December 31, 2025 (December 31, 2024 – $nil).

(2)Represents amounts available for cash draws. Our uncommitted demand facilities include $1.5 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, 2025, there were outstanding letters of credit aggregating to $341 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).

On September 19, 2025, Cenovus renewed its existing committed credit facility to extend the maturity dates by more than one year. As at December 31, 2025, the committed credit facility consists of a $3.3 billion tranche maturing on September 19, 2029, and a $2.2 billion tranche maturing on September 19, 2028. As at December 31, 2025, no amount was drawn on the credit facility (December 31, 2024 – $nil).

Base Shelf Prospectus

On November 28, 2025, 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 2028. 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 other (income) loss, net 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,	2025	2024
Net Debt to Adjusted EBITDA Ratio (times)	0.9	0.5
Net Debt to Adjusted Funds Flow Ratio (times)	0.9	0.6
Net Debt to Capitalization Ratio (percent)	21	13

Our Net Debt to Adjusted EBITDA ratio and our Net Debt to Adjusted Funds Flow 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, Net Debt to Adjusted Funds Flow ratio and Net Debt to Capitalization ratio as at December 31, 2025, increased compared with December 31, 2024, primarily as a result of higher Net Debt. See the Operating and Financial Results section of this MD&A for more information on changes in Net Debt.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	38

Share Capital and Stock-Based Compensation Plans

Our common shares are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”). Our cumulative redeemable preferred shares series 1 and 2 are listed on the TSX. On March 31, 2025, and June 30, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company’s series 5 preferred shares and all 6.0 million of the Company’s series 7 preferred shares, respectively. The preferred shares were redeemed at a price of $25.00 per share for a total of $350 million.

As at December 31, 2025, there were approximately 1,883.4 million common shares outstanding (December 31, 2024 – 1,825.0 million common shares) and 12.0 million preferred shares outstanding (December 31, 2024 – 26.0 million preferred shares). Total purchase consideration for the MEG Acquisition included the issuance of 143.9 million Cenovus common shares. Refer to Note 4 of the Consolidated Financial Statements for further details.

Cenovus has 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. For the year ended December 31, 2025, the Trust purchased 7.1 million common shares (2024 – 2.0 million common shares) for a total of $155 million (2024 – $43 million) and distributed 3.8 million common shares (2024 – nil) for a total of $82 million (2024 – $nil) under the employee benefit plan. As at December 31, 2025, there were 5.3 million common shares held by the Trust (December 31, 2024 – 2.0 million common shares). Refer to Note 26 of the Consolidated Financial Statements for further details.

As at December 31, 2025, there were approximately 1.2 million common share purchase warrants (“Cenovus Warrants”) outstanding (December 31, 2024 – 3.6 million). Each Cenovus Warrant entitled 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 expired on January 1, 2026. Refer to Note 26 of the Consolidated Financial Statements for further details.

Refer to Note 28 of the Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows:

As at February 13, 2026	Units Outstanding<br><br>(thousands)	Units Exercisable<br><br>(thousands)
Common Shares	1,879,261	n/a
Series 1 First Preferred Shares	10,740	n/a
Series 2 First Preferred Shares	1,260	n/a
Stock Options	10,626	4,647
Other Stock-Based Compensation Plans	21,089	1,832

Common Share Dividends

In 2025, we declared and paid base dividends of $1.4 billion or $0.780 per common share (2024 – $1.3 billion or $0.680 per common share) and variable dividends of $nil (2024 – $251 million or $0.135 per common share).

On February 18, 2026, the Board declared a first quarter base dividend of $0.200 per common share. The dividend is payable on March 31, 2026, to common shareholders of record as at March 13, 2026.

The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.

Cumulative Redeemable Preferred Share Dividends

($ millions)	2025	2024
Series 1 First Preferred Shares	7	7
Series 2 First Preferred Shares	1	2
Series 3 First Preferred Shares	—	12
Series 5 First Preferred Shares	2	9
Series 7 First Preferred Shares	4	6
Total Preferred Share Dividends Declared	14	36

For the year ended December 31, 2025, dividends of $14 million were paid on the preferred shares (2024 – $45 million).

On February 18, 2026, the Company’s Board of Directors declared first quarter preferred share dividends of $2 million payable on March 31, 2026, to preferred shareholders of record as at March 13, 2026.

The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly.

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Share Repurchases

On November 7, 2025, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 120.3 million common shares during the period from November 11, 2025, to November 10, 2026.

	2025	2024
Common Shares Purchased and Cancelled Under NCIB (millions of common shares)	89.4	55.9
Weighted Average Price per Common Share ($)	21.87	25.38
Purchase of Common Shares Under NCIB ($ millions)	1,995	1,445

From January 1, 2026, to February 13, 2026, the Company purchased an additional 5.0 million common shares for $126 million. As at February 13, 2026, the Company can further purchase up to 107.9 million common shares under the NCIB.

Contractual Commitments and Obligations

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 34 to the Consolidated Financial Statements.

As at December 31, 2025
($ millions)	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Commitments
Transportation and Storage (1) (2)	2,603	2,623	2,775	2,802	2,531	23,591	36,925
Real Estate	64	65	65	69	70	474	807
Obligation to Fund HCML	99	94	54	42	41	59	389
Other Long-Term Commitments	547	184	151	117	111	484	1,594
Total Commitments	3,313	2,966	3,045	3,030	2,753	24,608	39,715
Long-Term Debt (Principal and Interest)	473	489	1,717	3,303	330	9,718	16,030
Lease Liabilities (Principal and Interest) (3)	519	485	437	371	317	2,719	4,848
Decommissioning Liabilities	222	228	210	232	257	7,568	8,717
Total Commitments and Obligations	4,527	4,168	5,409	6,936	3,657	44,613	69,310

(1)Includes transportation commitments that are subject to regulatory approval or were approved but are not yet in service of $7.7 billion (December 31, 2024 – $854 million), of which $1.6 billion were assumed from the MEG Acquisition. Terms are up to 15 years on commencement.

(2)As at December 31, 2025, includes $1.7 billion related to transportation and storage commitments with HMLP (December 31, 2024 – $1.8 billion).

(3)Lease contracts related to office space, a pipeline, storage tanks, terminals, railcars, vessels, refining equipment, a natural gas processing plant, caverns, fleet vehicles, our commercial fuels network and other field equipment.

Through the MEG Acquisition, the Company assumed $8.3 billion of various transportation and storage commitments.

As at December 31, 2025, outstanding letters of credit issued as security for performance under certain contracts totaled $341 million (December 31, 2024 – $355 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

The Company holds a 35 percent interest in and is the operator of HMLP. 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.

($ millions)	2025	2024
Revenues from Construction and Management Services	164	155
Transportation Expenses	258	278

For the year ended December 31, 2025, the Company received $40 million of distributions from HMLP (2024 – $65 million) and paid $2 million in contributions (2024 – $51 million).

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	40

Husky-CNOOC Madura Limited

Cenovus holds a 40 percent equity interest in the jointly-controlled entity HCML. For the year ended December 31, 2025, the Company received $94 million of distributions from HCML (2024 – $107 million) and paid $nil in contributions (2024 – $nil).

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”). We continuously monitor our risk profile and industry best practices. The ERM Policy, approved by our Board, outlines our risk management principles, expectations, and the roles and responsibilities of all staff. Our risk management framework aligns with 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 and through regular updates.

Risk Factors

We are exposed to various 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 supply; processing and export capacity; export or import restrictions; domestic and global economic conditions; inflation; changes to interest rates; the impact of tariffs and responses thereto (including by governments, our trade partners and customers), which may include, without limitation, counter-tariffs, surtaxes, countermeasures, countervailing duties, antidumping duties, special duties, export taxes on Cenovus’s products, and restrictions on imports and exports, such as export controls, sanctions 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 regarding whether and to what extent 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 governments and regulatory bodies; enforcement of laws and regulations; shifts or changes in governmental policy; 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, 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 potential 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, prices of refinery feedstock; capacity and utilization rates at existing refineries; global and regional demand for refined products; market conditions 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.

We integrate the potential impact of a variety of factors and scenarios into our business planning processes, including commodity price fluctuations, climate change and GHG regulations, including the cost of carbon. To mitigate uncertainty, we evaluate our business plans under a range of scenarios. Although Management believes that our assumptions and estimates are reasonable, reflect current, pending and potential future states and are informed by external scenarios, they are based on numerous assumptions and estimates that, if false, may have a material adverse effect on our business, financial condition and results of operations. As such, variations between actual outcomes and our assumptions and estimates may have a material adverse effect on our business, financial condition, results of operations, reputation and cash flows.

Fluctuations in 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 ability to maintain our business and fund projects. A substantial decline in these commodity prices or an extended period of low commodity prices may result in: an inability to meet all 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, along with the comparison of the carrying value of our assets to our market capitalization, be considered indicators of impairment.

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 or produce 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 Tariffs and International Trade

Discussions continue regarding current and future economic arrangements between Canada and the U.S., and the U.S.’s relationships with other global trading partners, and there remains significant uncertainty over whether tariffs, surtaxes, or other restrictive trade measures or countermeasures will be implemented or maintained and, if so, the scope, impact, and duration of any such measures. Potential measures could include, among others, increased tariffs on Canadian energy imports into the U.S. or other jurisdictions, controls or restrictions on cross-border supply chains, changes to existing preferential trade agreements such as the United States-Mexico-Canada Agreement or cross-border energy agreements, 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 North America 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 such effects may have a material adverse impact on our business, results of operations and financial condition.

Additionally, restrictive trade measures or countermeasures or export controls imposed on our products or operations 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 restrictions, controls, or increases 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, NGLs 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 and physical positions 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 and trading 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 or physical position; 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 rate changes.

Additionally, Cenovus may engage in trading activities other than for hedging purposes. These activities, including the trading of energy products, are exposed to market variables and commodity price risk. As part of these activities, the Company may enter into physical contracts and other financial instruments. Such trading activities may expose Cenovus to additional risks including: market price risk; liquidity risk; counterparty risk; and increased earnings volatility.

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 31 and 32 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, 2025	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	1	(1)
WCS (Hardisty) Differential Price	± US$2.50/bbl Applied to WCS Differential Hedges Tied to Production	13	(13)
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(4)	4
Natural Gas Commodity Price	± US$0.50/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$10.00/MWh (2) Applied to Power Hedges	39	(39)

(1)Excluding WCS at Hardisty.

(2)One thousand kilowatts of electricity per hour (“MWh”).

For further information on our risk management positions, see Notes 31 and 32 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, is limited by the capacity of the applicable markets, which may be adversely affected if investors, insurers, or other relevant stakeholders adopt more restrictive decarbonization policies.

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.

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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; reducing or suspending 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.

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, 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, 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 oil and gas and refining industries 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 opportunities or having contracts terminated.

Exposure to Counterparties

In the normal course of business, we enter into contracts 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

Fluctuations in interest rates could negatively affect Cenovus’s financial performance. This risk arises during the refinancing of maturing long-term debt, when issuing new debt, or through changes in borrowing costs on floating-rate instruments. We are also exposed to interest rate variability on existing credit facilities used to support liquidity. Additionally, shifts in interest rates could change our net finance costs and could impact how certain liabilities are recorded. Collectively, these factors could have an impact on 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. 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 within our capital allocation framework, 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 as a result of, among other things, our business plans, results of operations, acquisitions and dispositions, 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 any share repurchases and payment of dividends is at the discretion of our Board.

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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.

Management has limited the scope of the design of DC&P and ICFR for the business acquired from MEG for the current reporting period, as permitted under National Instrument 52‑109, “Certification and Disclosure in Issuers’ Annual and Interim Filings” (“NI 52-109”). Management continues to integrate the acquired operations and expects to complete its assessment and alignment of DC&P and ICFR with Cenovus’s control environment during 2026. For further details, see the Control Environment section of this MD&A.

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 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, including at facilities operated by our partners or third parties; and (v) the development and operation of projects relating to our sustainability 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 including, but not limited to, adverse sea conditions, extreme weather events, wildfires and natural disasters; 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; equipment underperformance; 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; price, quality and unavailability of feedstock, including condensate; epidemics or pandemics; protests, blockades or other acts of activism; geopolitical factors including but not limited to war, vandalism or terrorism, or other regional or international conflict or action; and catastrophic events, including, but not limited to, 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 sustainability 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 responses thereto (including by governments, our trade partners and customers), which may include, without limitation, tariffs, surtaxes, countermeasures, countervailing duties, antidumping duties, special duties, export taxes on Cenovus’s products, and restrictions on imports and exports, such as export controls, sanctions 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, terminal 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 gaps caused by operational constraints on the pipeline system. In addition, our rail, marine and truck shipments may be impacted by service delays, changes to laws and regulations, labour issues, 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. Should laws and regulations change, the costs of complying with those changes will likely be passed on to Cenovus and may adversely affect our ability to transport by rail, marine or truck or the economics associated with such transportation. Finally, planned or unplanned shutdowns, outages or closures of our refineries or third-party systems can limit our ability to receive or deliver product with negative implications on our business, financial condition, results of operations and cash flows.

Reserves Replacement

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 business, reputation, 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.

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.

Reserve Estimates

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, truck and marine transportation and processing facilities, all of which may cause actual results to vary materially from estimates.

All such estimates are uncertain, and classifications of reserves are only attempts to define the degree of uncertainty involved. The accuracy of any reserves estimate is a matter of interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, and classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, as 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.

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Estimates with respect to reserves are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based on production history will result in variations in the estimated reserves, which may be material. The evaluation of reserves is a continuous process which can be significantly impacted by a variety of internal and external influences, and periodic revisions are required as a result of newly acquired technical data, technology improvements or changes in performance, pricing, economic conditions, market availability or regulatory requirements.

Non-Producing or Undeveloped Reserves

A significant portion of our bitumen reserves, as well as a portion of our light and medium oil, NGLs and conventional natural gas reserves, are classified as undeveloped and will require significant expenditures to render them capable of production. These reserves may not ultimately be developed or produced, either because it may not be commercially viable to do so or for other reasons. As these reserves are non-producing and/or undeveloped, their estimation relies on geological and recovery performance analogs that assume success case outcomes that may not materialize. These reserves are expected to be developed over multiple decades, with decisions regarding the priority and timing of development depending on a range of factors, including economic conditions, government regulations such as production limits, observed reservoir performance, development plan optimization, facility capacity, pipeline constraints, the overall size of the development program and strategic considerations. As a result, developments may be delayed, advanced, or cancelled, and the associated reserves may be revised and/or reclassified or removed from the reserves base.

SAGD Bitumen Recovery Process

The SAGD bitumen recovery process is energy intensive and consumes significant amounts of natural gas in the production of steam that is used in the recovery process. The amount of steam required in the recovery process varies and therefore impacts natural gas and related emissions costs. Geological characteristics, in concert with the actual development and operating practices employed, directly influence the efficiency of steam chamber conformance and propagation. Variability in these factors can materially affect bitumen mobility, steam‑oil ratios and recovery factors, which may differ materially from estimates informed by geological and recovery performance analogs, which are inherently less reliable than actual production history. Variability of any of these development or operational considerations may reduce production, increase costs or lead to revisions to reserves estimates or development plans. A large increase in costs could cause certain projects that rely on the SAGD bitumen recovery process to become economically challenged, which could have a negative effect on our business and financial condition.

Operational issues may adversely affect the stability and performance of the SAGD bitumen recovery process. The requirement to maintain reservoir integrity, under sustained steam‑injection can impact production timing, costs and recovery performance. Operational issues and reservoir integrity related events, may result in production curtailments, increased costs, regulatory involvement or revisions to future development plans and reserve estimates.

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; economic sanctions; restrictive trade measures or countermeasures; changing government policies (including but not limited to 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 operations technology and information technology, to effectively run our business. This includes all core technology assets and services, both on-premises and third-party systems, such as networks, computer hardware and software, telecommunications, mobile applications, cloud services and other technologies, including artificial intelligence (“AI”). The organization is introducing AI through a deliberate, strategically governed approach, beginning with pilot‑phase use cases that focus on improving productivity and enhancing decision‑support capabilities. If we cannot access, use, secure, upgrade or maintain these systems and services or if our information is lost, corrupted or disclosed, operations could be disrupted.

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In the ordinary course of business, we collect, use and store sensitive business data, including intellectual property, proprietary information and personal information. Despite security measures, our systems and services may be exposed to risks such as cyber-attacks, espionage, activism, terrorism, war or geopolitical instability, natural disasters, or human errors or malfeasance. Additional risks also include cyber fraud through attacks that bypass controls, impersonate staff or business partners to divert payments or financial assets, or use ransomware to demand payment or block systems access.

Any incident, breach, or disruption of our internal or third-party technology systems or services, including where a threat actor bypasses our cybersecurity measures or business process controls, could result in theft, loss or misuse of internal, confidential, business, financial, proprietary, personal or other sensitive data.

Cyber incidents, privacy or security breaches, or misuse of technology or data (including those involving AI), could also result in business interruption, financial loss, remediation and recovery costs, legal claims or proceedings, liability under law or regulations (including those related to AI, cybersecurity, data processing, or privacy), regulatory penalties or fines (where applicable), operational disruption, reputational damage and other material adverse effects on our business.

The regulatory landscape governing technology use is constantly evolving across all jurisdictions where we operate, covering data processing and transfers, cybersecurity and data protection, third-party risk, AI and privacy. The rapid growth of generative AI tools and embedded features increases technology and data privacy risks through potential misuse, biased or incorrect automated decision-making, or unauthorized exposure of Cenovus’s sensitive data.

Failure to comply with laws or regulatory standards, including the use or misuse of AI or inadequate protection of personal data, could result in legal action against the Company by governmental entities or others, fines and penalties (where authorized under relevant law), reputational harm, or may have a negative impact on our financial performance. Compliance with continuously evolving legislation may also increase our operating costs.

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. Resource inventory quality, operating and, or, capital costs, and market access are the primary controllable drivers of financial performance in the energy industry. Cenovus invests in technology innovation and continuous improvement in an effort to reduce costs and improve financial returns to maintain a competitive position relative to peers. The broader hydrocarbon industry also competes with alternative energy sources including renewable fuels and electricity, which compete for market share. Failure to maintain a competitive position relative to hydrocarbon industry peers and alternative energy sources could result in adverse effects to our business, financial condition, cash flows and reputation.

Project Execution

We manage a variety of growth and optimization projects across our global portfolio of assets. In addition, we have 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.

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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 may 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 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

We depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business goals, including our sustainability goals. Limitations related to the development, adoption and success of these technologies or limited development of disruptive technologies could have a negative impact on our long-term business resilience.

Governmental Policy

Shifts in governmental policy by new or existing administrations can impact our operations and ability to grow our business. Restrictions on fossil fuel-based energy use and cross-border economic activity can impact supply of, demand for, and pricing of our products and services, and our opportunities for continued growth.

Cenovus works 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 predict the timelines for, and precise effects of, changes in governmental policy which may adversely affect our business, results of operations, financial condition or reputation.

Regulatory Risk

The crude oil, natural gas, NGLs and refining industries 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 explore, develop and produce crude oil, refined products, natural gas, NGLs and other related products. 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 and import 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.

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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 decommissioning, abandonment, remediation and reclamation (“Decommissioning”) liabilities for our operations and development and exploration activities, 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 and legislation changes, technological changes, ecological risks, changes to 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.

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

In Canada, Aboriginal and/or treaty rights held by Indigenous peoples are protected under the Constitution. Impacts to these Aboriginal and/or treaty rights must be considered in areas where Cenovus operates. The successful assertion of Indigenous title or other Indigenous rights claims on lands where we operate could have a material adverse impact on our operations or pace of growth.

Opposition by Indigenous communities to our Company, operations, activities, development or exploration on Crown land leases, may adversely impact our reputation and our ability to execute operational or exploration plans. 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 addition, changes in law related to Indigenous rights and title may have a material adverse impact on our business and operations.

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Furthermore, Indigenous title or other Indigenous rights claims, as well as opposition by Indigenous communities, can affect the oil and gas and refining industries as a whole. Legal challenges or opposition to major infrastructure projects such as pipelines, railways, or export terminals may result in delays, cancellations, or increased costs. These outcomes may adversely impact our operations, pace of growth, share price and development plans, even if our Company is not directly involved in the development or operation of such projects.

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 products. 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.

In addition, climate change-related regulatory, climatic and transition risks can also have industry-wide effects, particularly through their influence on major infrastructure projects. Regulatory changes, market trends, or policy shifts may lead to delays, cancellations, or increased costs for projects critical to the industry. Such impacts may indirectly affect our operations, growth prospects, share price and development plans, even if our Company is not directly involved in the development or operation of such projects.

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

Cenovus operates 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 discussion, review, or implementation, creating policy uncertainty. Further ambiguity exists as a result of the timing and possible impact of any contemplated or emerging regulations, including, but not limited to, how new and existing regulations may be harmonized and synchronized with already existing or contemplated requirements across jurisdictions. Furthermore, policy uncertainty exists as a result of changing government administrations, making the policy and cost impact to the business uncertain and unpredictable. Additional climate change regulations, including the implementation of regulations not currently contemplated, and changes to existing and future regulations, may adversely affect Cenovus’s business, financial condition, results of operations, regulatory approvals and cash flows, which impacts cannot be reliably or accurately estimated. Examples of such regulatory change include, but are not limited to, carbon pricing, regulation or limiting of GHG emissions, standards for carbon intensity of liquid fossil fuels, renewable fuel standards, vehicle emissions standards, sales targets for electric vehicles and regulation of electricity generation.

Changes in environmental and emissions legislation and regulations by government authorities could require changes to facility design and operations, potentially increasing the cost of construction, operation and abandonment. Other possible effects from emerging regulations may include, but are not limited to, increased compliance costs, penalties, permitting delays, a general shift away from fossil fuel-based energy, reduced future demand (and corresponding price levels) for our products, substantial costs to generate or purchase emission credits or allowances and higher prices for essential inputs (such as condensate), any of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be an economically viable option; required emissions reductions may not be technically or economically feasible to implement, in whole or in part; and failure to access resources or technology to meet emissions reduction requirements or other compliance mechanisms may have a material adverse effect to the business, resulting in, among other things, fines, permitting delays, penalties, shutting in production, and/or the suspension of operations.

The extent and magnitude of any adverse impacts of current or future regulations cannot be reliably or accurately estimated, in part because certain legislative and regulatory requirements have not been finalized, others are subject to change, and uncertainty exists with respect to additional measures being considered, the timeframes for compliance and that actual costs and impacts may be different than anticipated and such differences may be material.

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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, 2025, approximately 11 percent of our employees were represented by unions under collective bargaining agreements, which includes approximately 47 percent of our U.S. and one percent of our Canadian workforce.

At unionized worksites there is risk that strikes, or work stoppages could occur, which may have a material adverse effect on our business. The Company may also incur significant costs associated with mitigation and emergency operations plans to ensure continuity of operations in the event of a strike or lockout. Future unionization efforts of Cenovus’s non-represented workforce may result in higher wage, benefits and other adverse employment consequences related to flexibility and management rights.

Lastly, we did see increased unionization activity in 2025, which resulted in the unionization of an asset in our Atlantic Region which was previously unrepresented. Changes to the workplace resulting from transactions may increase unionization drive.

2026 will be a busy negotiating period across the organization, as all current collective agreements will expire and are open for renegotiation. Renegotiations of our existing collective bargaining agreements may result in terms that are more or less favourable to us.

Any of these actions may have a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows.

Leadership and Talent

Our success depends on strong leadership and a highly skilled, capable workforce. If we are unable to attract, develop and retain key personnel and diverse critical talent with the behaviours, leadership experience, technical and professional competencies needed to support our desired organizational and safety culture, we may face material adverse impacts to our business, safety, reputation, financial condition, results of operations and cash flows. Inadequate management of human-resources–related risks could also result in financial and/or reputational losses or risks, including those arising from actions that do not comply with applicable employment laws.

Additionally, insufficient succession planning or gaps in our talent pipeline for leadership positions could disrupt operations and slow organizational progress.

The integration of new personnel acquired in transactions may result in increased attrition rates in the workforce (including the loss of key employees), disruption of ongoing employment relationships and increased employment-related litigation.

Lastly, failure to sustain a culture that supports safety, inclusion and strong performance may undermine our strategic execution.

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, safety, reputation, financial condition, results of operations and cash flows.

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 Strait, held through and operated by the joint venture, HCML with delegation to CNOOC.

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Developments impacting international trade, particularly between Canada and the U.S., the U.S. and China, Canada and China, and the EU and China, including military exercises, changes in laws or enforcement of existing laws, exchange rate fluctuations, trade disputes, the renegotiation or nullification of agreements or treaties, new or increased tariffs and responses thereto (including by governments, our trade partners and customers), which may include, without limitation, retaliatory tariffs, surtaxes, countermeasures, countervailing duties, antidumping duties, export or import taxes on Cenovus’s products, and restrictions on imports and exports, such as export controls, sanctions and other measures, may negatively impact development projects, 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.

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. Similarly, political developments such as we are currently seeing in Venezuela may lead to short- or longer-term impacts in regional and global oil and gas markets. 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.

Litigation and Claims

From time-to-time, we may receive demands, or be involved in disputes, regulatory orders, investigations, proceedings, arbitrations and/or litigation (“Claims”) arising out of, or related to, our business, operations and/or contractual relationships. 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, 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, any of which may be material.

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 and investigations into how climate-related goals are established and promoted. 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 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, orders, 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, safety, reputation, financial condition, results of operations and cash flows.

Environmental Plans and Regulations Risks

All phases of our operations are subject to environmental plans and 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 laws and regulations will occur. 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.

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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. The extent and magnitude of any potential adverse impacts of legislation on project development and operations are difficult to predict, as uncertainty exists as to whether jurisdictional plans and actions undertaken will be sufficiently stringent to satisfy the SARA and associated provisions. Similarly, uncertainty exists with respect to the outcome of litigation that could be initiated with respect to federal duties and obligations pursuant to the SARA.

Canadian Federal Air Quality Management System

The Multi-Sector Air Pollutants Regulations (“MSAPR”), under the Canadian Environmental Protection Act, 1999, set mandatory national air pollutant emission standards to protect the environment and health of Canadians. It established nitrogen oxides emission limits for specific equipment, including stationary engines, boilers and heaters, across several industrial sectors. 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 current or future water licences will be continued or approved. 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 per- and polyfluoroalkyl substances (“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.

Sustainability Focus Areas and Goals

We have established meaningful goals in our sustainability focus areas and continue to allocate resources and progress tangible plans to meet these ambitions. To achieve these goals and to respond to changing market demand, we may incur additional costs and invest in 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 sustainability goals depend 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 may compare companies based on sustainability-related performance, including climate-related performance. Failure to achieve our sustainability goals, or a perception among key stakeholders that our sustainability goals are insufficient or unattainable, could adversely affect our reputation and our ability to attract capital and insurance coverage, and could result in claims that we misrepresented our goals or our ability to achieve them.

There is also a risk that some or all of the expected benefits and opportunities of achieving the various sustainability goals may fail to materialize, may cost more to achieve than we expect or may not occur within the anticipated time periods or at all. In addition, there is a risk that the actions we take in implementing ambitions relating to our sustainability 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. In those circumstances, this could result in claims that we misrepresented our goals or our ability to achieve them.

Furthermore, 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 relevance, 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 Goals

Our ability to meet our water stewardship goals 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 strategies and technologies as planned, without negatively impacting our expected operations or cost structure, or such strategies or technologies do not perform as expected, progress toward our goals could be interrupted, delayed or abandoned. In those circumstances, this could result in claims that we misrepresented our goals or our ability to achieve them.

Biodiversity Goals

Our ability to meet our biodiversity ambitions 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 meet, our biodiversity goals on the current timelines, or at all. In some cases, meeting our biodiversity ambitions has operational implications for reduced operational footprint and accelerated abandonment, reclamation and restoration. In the event that we do not meet our goals, this could result in claims that we misrepresented our goals or our ability to achieve them.

Indigenous Reconciliation Goals

A failure or delay in achieving our Indigenous reconciliation ambitions or continuing to advance Indigenous reconciliation initiatives may adversely affect our relationship with neighbouring Indigenous businesses and communities, and our reputation.

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Acceptance and Belonging Goals

The acceptance and belonging of our staff plays a critical role in strengthening our business performance and culture. A failure or delay in achieving our acceptance and belonging ambitions could have a material adverse effect on our recruitment activities, retention efforts and reputation with our stakeholders.

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 viewed as a credible, trusted company. All of our actions can influence public or key stakeholder opinions and decisions, which may adversely affect our share price, development plans or 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, and could lead to constrained access to insurance, liquidity and capital, and affect demand for our products.

Shareholder activism has been increasing in the oil and gas 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, successful or not, could adversely impact our business by distracting from core business operations, incurring increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans, affecting our ability to attract and retain staff, creating significant fluctuation in our share price, and provoking perceived uncertainty about the future direction of our business.

Internet search functions are increasingly using AI to summarize search results, often sourcing information from sites containing misinformation or inaccuracies. Investors and other stakeholders seeking information about Cenovus may be directed to falsehoods or incomplete information about the company, potentially impacting perceptions and decisions about our business or operations and incurring staff time to mitigate.

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 Divestitures

We have completed, and may complete in the future, acquisitions and divestitures 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. This may result in increased costs and could adversely affect our ability to achieve the anticipated benefits of such transactions, as well as other strategic opportunities or operational matters. 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 divestitures. 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 be material.

Should any of the risks associated with acquisitions or divestitures materialize, they could have an adverse effect on our business, financial condition or reputation.

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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”) and L.F. Investments S.à r.l. (“L.F. Investments”, together with Hutchison, 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. In addition, the Significant Shareholders may be able to impact certain matters requiring Cenovus shareholder approval. While the Significant Shareholders were subject to certain voting and selling restrictions pursuant to standstill agreements each shareholder entered into with Cenovus, such agreements expired on January 1, 2026.

Income and Property Tax Laws

Our operations are subject to complex and continually evolving tax laws and regulations in multiple jurisdictions. Evolving jurisprudence and changes in legislation, regulations or governmental policy could adversely affect our financial results and ability to achieve strategic objectives. Tax authorities may challenge our filings, and audits or disputes could result in additional liabilities.

Pandemic Risk

Pandemics, epidemics or outbreaks constitute ongoing risks to the Company, with their ultimate impacts remaining uncertain and subject to change. Such events, along with any measures implemented by Cenovus or governmental authorities to protect the health and safety of personnel and ensure business continuity, may give rise to legal disputes, diminished demand and pricing for key commodities, and could adversely affect the Company’s business performance, 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. Canadian customs regulations also prohibit importing goods produced with forced, child and prison labour, as well as the possession, purchase, sale, exchange, acquisition or disposition of these goods after they have been imported. Heightened regulatory scrutiny and evolving legislation, and our response to these changes, may disrupt our supply chains, affecting availability or cost of goods and materials, 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, exposing Cenovus to reputational harm. The Government of Canada may expand these requirements, but the timing and impact of any such expansion remains uncertain.

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
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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 right-of-use 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.

On September 30, 2025, Cenovus divested its entire 50 percent interest in WRB, which was a jointly-controlled entity. The joint arrangement met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company recognized its share of the assets, liabilities, revenues and expenses in its consolidated results up to the date of divestiture.

In determining the classification of its joint arrangement under IFRS 11, the Company considered the following:

•The original intention of the joint arrangement was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.

•The agreements required the partners to make contributions if funds were insufficient to meet the obligations or liabilities of the corporation and partnership. The past and future development of WRB was dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.

•WRB had third-party debt facilities to cover short-term working capital requirements.

•Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provided marketing services, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf as the agreements prohibited the partners from undertaking these roles themselves. In addition, the joint arrangement did not have employees and, as such, was not capable of performing these roles.

•In the arrangement, output was taken by the partners, indicating that the partners had the rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangement.

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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 renewable identification numbers. 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 estimates, assumptions and judgments 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 independent qualified reserves evaluators (“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, 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

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, if any, 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. 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.

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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.

New Accounting Standards and Interpretations not yet Adopted

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 fair value through other comprehensive income (loss) were added. The amendments are effective for annual periods beginning on or after January 1, 2026, and will be applied retrospectively. The amendments to IFRS 9 and IFRS 7 will not have a material impact on the Consolidated Financial Statements.

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 continuing to evaluate the impacts of adopting IFRS 18 on the Consolidated Financial Statements. Cenovus will adopt IFRS 18 effective January 1, 2027, using the retrospective approach.

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, 2025. 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, 2025.

On November 13, 2025, Cenovus completed the MEG Acquisition. As permitted by and in accordance with, NI 52-109, and guidance issued by the U.S. Securities and Exchange Commission, Management has limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures in respect of the business acquired from MEG. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P relating to the business acquired from MEG in a manner consistent with our other operations. Further integration will take place throughout the remainder of 2026 as processes and systems align.

Assets attributable to MEG as at December 31, 2025, represented approximately 18 percent of Cenovus’s total assets, and revenues attributable to MEG for the period of November 13, 2025, to December 31, 2025, represented approximately one percent of Cenovus’s total revenues for the three months ended December 31, 2025.

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
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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 “advance”, “aim”, “allocate”, “anticipate”, “believe”, “commit”, “continue”, “could”, “deliver”, “expect”, “F”, “focus”, “grow”, “maintain”, “may”, “maximize”, “mitigate”, “on track”, “objective”, “ongoing”, “opportunities”, “optimize”, “plan”, “position”, “potential”, “priority”, “progress”, “strategy”, “steward”, “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; top-tier safety performance; safety priorities; sustainability leadership and progressing sustainability initiatives; focus on cost leadership and balancing shareholder returns with deleveraging; our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with governments; maximizing value and profitability; disciplined capital allocation; cash flow and commodity price volatility and stability; price alignment and volatility management strategies; dividends; focus on cost and sustainability improvements; liquidity; our 2026 corporate guidance; factors influencing commodity outlook; the Company’s key priorities for 2026; the impact of the global trade war; realizing the full value of our integrated strategy; capitalizing on opportunities; Net Debt targets pursuant to the shareholder returns framework; allocating Excess Free Funds Flow to shareholder returns; absolute and per share Free Funds Flow growth; project execution; growing our competitive advantages in our heavy oil value chain and reliable operations; 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; progressing hookup and commissioning of the platform at the West White Rose project; progressing growth projects, including the Amine Claus project at Foster Creek, the Christina Lake North expansion project, the Sunrise growth program and the development of our Lloydminster assets; our sustainability focus areas, goals, plans and commitments; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; general outlook for crude oil and refined product prices; price volatility and geopolitical risks; impact of current and future economic arrangements between Canada and the U.S. including tariffs and other measures and countermeasures and responses thereto on market access and transportation; the use of derivatives, financial instruments and physical positions as financial risk management activities; trading activities, including trading of energy products, for purposes other than hedging Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; Net Debt to Adjusted EBITDA ratio; Net Debt to Capitalization ratio; introduction of artificial intelligence pilot-phase; 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, NGLs, condensate and refined products prices, and light-heavy and light-medium 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

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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, title or rights claims, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions, trade sanctions, restrictive trade measures or countermeasures, and the supply and demand for bitumen, crude oil and natural gas, NGLs, condensate and refined products and 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 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 risk management activities and physical positions to manage its exposure to fluctuations in commodity prices and, foreign exchange and interest rates, optimize supply costs or sales of production; the Company’s ability to use fixed-price commitments for the purchase or sale of commodities; 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; 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 oil processing capacity, as long as supply does not exceed Canadian crude oil export capacity; the Company’s ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, NGLs 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 sustainability targets and the Pathways Alliance project, and the commercial viability and scalability of related technology and products; expected benefits of investments in sustainability focus areas; collaboration with the government, Pathways Alliance and other industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2026 guidance available on cenovus.com and as set out below; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.

2026 guidance dated December 10, 2025, and available on cenovus.com, assumes: Brent prices of US$64.00 per barrel, WTI prices of US$60.00 per barrel; WCS of US$47.50 per barrel; Differential WTI-WCS of US$12.50 per barrel; AECO natural gas prices of $2.50 per Mcf; Chicago 3-2-1 crack spread of US$20.00 per barrel; RINs of US$6.00 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 business with its own in a timely and cost effective manner or at all; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and divestitures; 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 sustainability targets and the Pathways Alliance project and the commercial viability and scalability of related technology and products; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration and impact 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; WTI-WCS differential at Hardisty does not remain largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of the Company’s outlook for commodity prices and currency and interest rates; changes in laws or enforcement of existing laws, exchange rate fluctuations, trade disputes, trade agreements or treaties, new or increased tariffs, economic sanctions and other restrictive trade measures or countermeasures, and responses thereto; 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

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	62

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 factors influencing decisions on the priority and timing of development of undeveloped reserves; potential disruptions and risks associated with the adoption, development and integration of AI; 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 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 licence to operate and litigation related thereto; legal challenges or opposition to infrastructure projects associated with Indigenous title or other rights claims; 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 talent and integrate new personnel acquired in transactions; 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; climate change-related regulatory, climactic transition risks; failure to achieve our sustainability goals, or a perception among key stakeholders that our actions or goals are insufficient or unattainable; 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; OPEC+ policy; actions of OPEC and non-OPEC members, including compliance or non-compliance with agreed upon quotas and decisions to impose production quotas; 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 attempting to achieve goals for sustainability focus areas may have a negative impact on our existing business, growth plans and future results from operations, or that the benefits may be less than expected.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	63

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.

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/d	thousand barrels of oil <br>   equivalent per day
MMbbls	million barrels	MMcf/d	million cubic feet per day	MMBOE	million barrels of oil equivalent
WCS	Western Canadian Select	Bcf	billion cubic feet	DD&A	depreciation, depletion and<br>   amortization
WTI	West Texas Intermediate			GHG	greenhouse gas
				FPSO	floating production, storage and <br>   offloading unit
				NCIB	normal course issuer bid
				AECO	Alberta Energy Company
				NYMEX	New York Mercantile Exchange
				OPEC	Organization of Petroleum<br>   Exporting Countries
				OPEC+	OPEC and a group of 11 <br>   non-OPEC members
				USGC	U.S. Gulf Coast
Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	64
---	---

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, Realized Sales Price, Conventional, Offshore and Asia Pacific Per-Unit Operating Expenses, Netbacks (including the total Netback per BOE), Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture.

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 section 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 and Excess Free Funds Flow for prior period information from 2025, 2024 and 2023 that is not found below.

Non-GAAP Financial 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 Consolidated Financial Statements.

Operating Margin

	Three Months Ended December 31,
	2025	2024	2025	2024	2025	2024
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales	6,373	6,050	5,180	7,677	11,553	13,727
Intersegment Sales	1,914	2,190	134	160	2,048	2,350
	8,287	8,240	5,314	7,837	13,601	16,077
Royalties	(670)	(914)	—	—	(670)	(914)
Revenues	7,617	7,326	5,314	7,837	12,931	15,163
Expenses
Purchased Product	1,271	1,000	4,574	7,364	5,845	8,364
Transportation and Blending	2,832	2,816	—	—	2,832	2,816
Operating	893	842	591	866	1,484	1,708
Realized (Gain) Loss on Risk Management	(7)	(2)	—	3	(7)	1
Operating Margin	2,628	2,670	149	(396)	2,777	2,274

(1)Found in Note 1 of the interim Consolidated Financial Statements.

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	Year Ended December 31,
---	---	---	---	---	---	---
	2025	2024		2025	2024	2025	2024
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales	24,354	24,640		28,397	33,086	52,751	57,726
Intersegment Sales	8,141	8,438		800	532	8,941	8,970
	32,495	33,078		29,197	33,618	61,692	66,696
Royalties	(3,055)	(3,449)		—	—	(3,055)	(3,449)
Revenues	29,440	29,629		29,197	33,618	58,637	63,247
Expenses
Purchased Product	4,223	3,674		25,855	30,252	30,078	33,926
Transportation and Blending	11,243	11,331		—	—	11,243	11,331
Operating	3,567	3,489		3,143	3,670	6,710	7,159
Realized (Gain) Loss on Risk Management	4	14		(6)	8	(2)	22
Operating Margin	10,403	11,121		205	(312)	10,608	10,809

(1)Found in Note 1 of the Consolidated Financial Statements.

Operating Margin by Asset

( millions)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	420	1,088	1,508
Royalties	(4)	(76)	(80)
Revenues	416	1,012	1,428
Expenses
Purchased Product	—	—	—
Transportation and Blending	17	—	17
Operating	226	123	349
Operating Margin	173	889	1,062

All values are in US Dollars.

( millions)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	322	1,250	1,572
Royalties	(2)	(97)	(99)
Revenues	320	1,153	1,473
Expenses
Purchased Product	—	—	—
Transportation and Blending	11	—	11
Operating	290	133	423
Operating Margin	19	1,020	1,039

All values are in US Dollars.

(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. – 2025 Management's Discussion and Analysis	66

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)	2025	2024	2025	2024
Cash From (Used in) Operating Activities	2,408	2,029	8,228	9,235
(Add) Deduct:
Settlement of Decommissioning Liabilities	(82)	(64)	(280)	(234)
Net Change in Non-Cash Working Capital	(184)	492	(363)	1,305
Adjusted Funds Flow	2,674	1,601	8,871	8,164
Capital Investment	1,360	1,478	4,907	5,015
Free Funds Flow	1,314	123	3,964	3,149
Add (Deduct):
Base Dividends Paid on Common Shares	(376)	(330)	(1,423)	(1,255)
Dividends Paid on Preferred Shares	(4)	(18)	(14)	(45)
Purchase of Common Shares Under Employee <br>   Benefit Plan	(61)	(43)	(155)	(43)
Settlement of Decommissioning Liabilities	(82)	(64)	(280)	(234)
Principal Repayment of Leases	(84)	(80)	(350)	(299)
Acquisitions, Net of Cash Acquired	(3,430)	(3)	(3,666)	(22)
Acquisition of Ownership Interest in<br><br>MEG Energy Corp. (1)	(752)	—	(752)	—
Proceeds From Divestitures	1,878	(1)	1,891	46
Excess Free Funds Flow	(1,597)	(416)	(785)	1,297

(1)Represents the acquired MEG common shares purchased prior to the closing of the MEG Acquisition. For further information, refer to Note 3 of the interim Consolidated Financial Statements.

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)	2025	2024	2023
Total Liabilities	31,786	26,770	25,203
Less: Total Current Liabilities	6,314	7,362	6,210
Total Long-Term Liabilities	25,472	19,408	18,993

Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture

Gross Margin and Adjusted Gross Margin are non-GAAP financial measures that are used to evaluate the performance of our downstream operations. We define Gross Margin as revenues less purchased product and Adjusted Gross Margin as revenues less purchased product, excluding the impact of inventory holding gains or losses.

Inventory holding gains or losses reflects the difference between the cost of volumes produced at current-period costs, which is an indication of current market conditions, and the cost of volumes produced under the FIFO or weighted average cost basis as required by IFRS Accounting Standards, which generally reflects the market conditions at the time feedstock was purchased. The purchase and sale of inventories creates a timing difference that could be anywhere from several weeks to several months. This measure is an estimate of the impact of current-period costs to FIFO or weighted average cost, and assumes that all opening volumes are sold in the current period. Cenovus uses inventory holding gains or losses to analyze the performance of our assets and increase comparability with refining peers.

Adjusted Refining Margin and Adjusted Market Capture contain non-GAAP financial measures. Adjusted Refining Margin is used to evaluate our downstream operations after adjusting for inventory holding gains or losses. Adjusted Market Capture 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. These measures are useful to consistently measure the performance of our downstream operations.

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We define Adjusted Refining Margin as Adjusted Gross Margin divided by total processed inputs and Adjusted Market Capture as Adjusted 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.

We previously disclosed Refining Margin and Market Capture, which did not exclude the effect of inventory holding gains or losses. As of March 31, 2025, we have added Adjusted Gross Margin, and replaced our definitions of Refining Margin and Market Capture to exclude the impact of inventory holding gains or losses. We believe these changes provide more comparability and accuracy when measuring the performance of our downstream operations.

Comparative period information has been provided below for these new metrics.

Canadian Refining

	Three Months Ended December 31, 2025
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	1,078	78	1,156
Purchased Product	862	48	910
Gross Margin	216	30	246
Add (Deduct):
Inventory Holding (Gain) Loss	4	—	4
Adjusted Gross Margin	220	30	250
Total Processed Inputs (Mbbls/d)	122.6
Adjusted Refining Margin ($/bbl)	19.57

(1)Includes ethanol operations and crude-by-rail operations.

(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

	Three Months Ended December 31, 2024
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	1,207	56	1,263
Purchased Product	1,032	36	1,068
Gross Margin	175	20	195
Add (Deduct):
Inventory Holding (Gain) Loss	—	—	—
Adjusted Gross Margin	175	20	195
Total Processed Inputs (Mbbls/d)	112.1
Adjusted Refining Margin ($/bbl)	16.96

(1)Includes ethanol operations and crude-by-rail operations.

(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

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	Year Ended December 31, 2025
---	---	---	---
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	4,781	298	5,079
Purchased Product	3,932	196	4,128
Gross Margin	849	102	951
Add (Deduct):
Inventory Holding (Gain) Loss	3	—	3
Adjusted Gross Margin	852	102	954
Total Processed Inputs (Mbbls/d)	119.4
Adjusted Refining Margin ($/bbl)	19.57

(1)Includes ethanol operations and crude-by-rail operations.

(2)Revenues and purchased product are found in Note 1 of the Consolidated Financial Statements.

	Year Ended December 31, 2024
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	5,014	296	5,310
Purchased Product	4,278	205	4,483
Gross Margin	736	91	827
Add (Deduct):
Inventory Holding (Gain) Loss	(4)	2	(2)
Adjusted Gross Margin	732	93	825
Total Processed Inputs (Mbbls/d)	96.6
Adjusted Refining Margin ($/bbl)	20.72

(1)Includes ethanol operations and crude-by-rail operations.

(2)Revenues and purchased product are found in Note 1 of the Consolidated Financial Statements.

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U.S. Refining

	Three Months Ended December 31,		Year Ended December 31,
($ millions, except where indicated)	2025	2024	2025	2024
Revenues (1)	4,158	6,574	24,118	28,308
Purchased Product (1)	3,664	6,296	21,727	25,769
Gross Margin	494	278	2,391	2,539
Add (Deduct):
Inventory Holding (Gain) Loss	134	45	298	(23)
Adjusted Gross Margin	628	323	2,689	2,516
Total Processed Inputs (Mbbls/d)	375.8	588.4	548.1	581.4
Adjusted Refining Margin ($/bbl)	18.17	5.98	13.44	11.83
Operable Capacity (2) (Mbbls/d)	364.8	612.3	549.9	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	88	81	82	81
Group 3 3-2-1 Crack Spread Weighting	12	19	18	19
Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	18.20	12.12	19.44	16.74
Group 3 3-2-1 Crack Spread (US$/bbl)	19.25	12.66	20.63	16.81
RINs (US$/bbl)	6.04	4.02	5.81	3.74
US$ per C$1 – Average	0.717	0.715	0.716	0.730
Weighted Average Crack Spread, Net of RINs ($/bbl)	17.14	11.47	19.34	17.82
Adjusted Market Capture (percent)	106	52	69	67

(1)Found in Note 1 of the interim Consolidated Financial Statements.

(2)For the year ended December 31, 2025, reported operable capacity reflects the weighted average impact of the WRB Divestiture, which closed on September 30, 2025.

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. Netback per barrel of oil equivalent contains a non-GAAP measure. Netbacks per barrel of oil equivalent reflect our margin on a per-barrel of oil equivalent basis. Per-unit measures are divided by sales volumes.

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. Conventional, Offshore and Asia Pacific Per-Unit Operating Expenses contain non-GAAP measures. As of March 31, 2025, modifications were made to our Conventional Netback to include our 30 percent equity interest in the Duvernay joint venture. These modifications resulted in minor adjustments that are captured in the netback calculation on a prospective basis. Offshore and Asia Pacific operating expenses, as used in the basis of our Netback calculations, reflect our 40 percent equity interest in the HCML joint venture. The Duvernay and HCML joint ventures are accounted for using the equity method in the interim Consolidated Financial Statements.

The following tables provide a reconciliation of Netback to Operating Margin found in our interim Consolidated Financial Statements.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	70

Oil Sands

	Basis of Netback Calculation
Three Months Ended December 31, 2025 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,439	1,752	377	762	4,330
Royalties	(231)	(337)	(20)	(92)	(680)
Revenues	1,208	1,415	357	670	3,650
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	228	224	77	37	566
Operating	183	253	85	224	745
Netback	797	938	195	409	2,339
Realized (Gain) Loss on Risk Management					(2)
Operating Margin					2,341			Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---
Three Months Ended December 31, 2025 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	4,330		2,180	827	(125)	7,212
Royalties	(680)		—	—	41	(639)
Revenues	3,650		2,180	827	(84)	6,573
Expenses
Purchased Product	—		—	827	64	891
Transportation and Blending	566		2,180	—	(9)	2,737
Operating	745		—	—	(23)	722
Netback	2,339		—	—	(116)	2,223
Realized (Gain) Loss on Risk Management	(2)		—	—	—	(2)
Operating Margin	2,341		—	—	(116)	2,225

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

(2)Includes bitumen and heavy oil.

(3)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation, as well as adjustments to reflect the cost of volumes produced on acquired inventory.

(4)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

	Basis of Netback Calculation
Three Months Ended December 31, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,454	1,646	380	871	4,351
Royalties	(283)	(455)	(19)	(117)	(874)
Revenues	1,171	1,191	361	754	3,477
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	281	137	59	44	521
Operating	163	187	72	200	622
Netback	727	867	230	510	2,334
Realized (Gain) Loss on Risk Management					(3)
Operating Margin					2,337

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

(2)Includes bitumen and heavy oil.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	71
	Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---
Three Months Ended December 31, 2024 ($ millions)	Total Oil Sands (1)		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 bitumen and heavy oil.

(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
Year Ended December 31, 2025 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	5,938	6,252	1,479	3,247	16,916
Royalties	(1,093)	(1,414)	(73)	(379)	(2,959)
Revenues	4,845	4,838	1,406	2,868	13,957
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	1,090	638	301	149	2,178
Operating	741	763	342	926	2,772
Netback	3,014	3,437	763	1,793	9,007
Realized (Gain) Loss on Risk Management					8
Operating Margin					8,999			Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---
Year Ended December 31, 2025 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	16,916		8,636	2,578	197	28,327
Royalties	(2,959)		—	—	39	(2,920)
Revenues	13,957		8,636	2,578	236	25,407
Expenses
Purchased Product	—		—	2,578	308	2,886
Transportation and Blending	2,178		8,636	—	61	10,875
Operating	2,772		—	—	(18)	2,754
Netback	9,007		—	—	(115)	8,892
Realized (Gain) Loss on Risk Management	8		—	—	—	8
Operating Margin	8,999		—	—	(115)	8,884

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

(2)Includes bitumen and heavy oil.

(3)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation, as well as adjustments to reflect the cost of volumes produced on acquired inventory.

(4)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	72
	Basis of Netback Calculation
---	---	---	---	---
Year Ended December 31, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	5,837	6,428	1,574	3,724	17,563
Royalties	(1,176)	(1,601)	(78)	(413)	(3,268)
Revenues	4,661	4,827	1,496	3,311	14,295
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	937	554	294	185	1,970
Operating	682	733	263	819	2,497
Netback	3,042	3,540	939	2,307	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 (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
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)Includes bitumen and heavy oil.

(3)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation, as well as adjustments to reflect the cost of volumes produced on acquired inventory.

(4)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.

Conventional

	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2025 ($ millions)	Conventional (1)	Third-party Sourced	Other (1) (2)	Conventional (3)
Gross Sales	323	386	29	738
Royalties	(13)	—	2	(11)
Revenues	310	386	31	727
Expenses
Purchased Product	—	386	—	386
Transportation and Blending	61	—	31	92
Operating	90	—	5	95
Netback	159	—	(5)	154
Realized (Gain) Loss on Risk Management	(5)	—	—	(5)
Operating Margin	164	—	(5)	159

(1)For the three months ended December 31, 2025, reported netbacks are inclusive of revenues and expenses related to the Duvernay joint venture.

(2)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.

(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	73
	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

(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, 2025 ($ millions)	Conventional (1)	Third-party Sourced	Other (1) (2)	Conventional (3)
Gross Sales	1,208	1,337	115	2,660
Royalties	(58)	—	3	(55)
Revenues	1,150	1,337	118	2,605
Expenses
Purchased Product	—	1,337	—	1,337
Transportation and Blending	244	—	107	351
Operating	441	—	23	464
Netback	465	—	(12)	453
Realized (Gain) Loss on Risk Management	(4)	—	—	(4)
Operating Margin	469	—	(12)	457

(1)For the year ended December 31, 2025, reported netbacks are inclusive of revenues and expenses related to the Duvernay joint venture.

(2)Other includes the reclassification of costs primarily related to third-party cogeneration, processing and transportation.

(3)These amounts, excluding Netback, are found in Note 1 of the 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

(1)Other includes the 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. – 2025 Management's Discussion and Analysis	74

Offshore

	Basis of Netback Calculation					Adjustments
Three Months Ended December 31, 2025 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>Asia Pacific	Total Offshore	Equity<br><br>Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	64	275	83	358	422	(83)	(2)	337
Royalties	(1)	(20)	(14)	(34)	(35)	14	1	(20)
Revenues	63	255	69	324	387	(69)	(1)	317
Expenses
Purchased Product	—	—	—	—	—	—	(6)	(6)
Transportation and Blending	3	—	—	—	3	—	—	3
Operating	39	35	22	57	96	(21)	1	76
Netback	21	220	47	267	288	(48)	4	244
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					288	(48)	4	244			Basis of Netback Calculation					Adjustments
---	---	---	---	---	---	---	---	---
Three Months Ended December 31, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>Asia Pacific	Total Offshore	Equity<br><br>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

(1)Revenues and expenses related to the HCML joint venture.

(2)Includes other activities not attributable to the production of crude oil and natural gas.

(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, 2025 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>Asia Pacific	Total Offshore	Equity<br><br>Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	401	1,088	343	1,431	1,832	(343)	19	1,508
Royalties	(4)	(76)	(83)	(159)	(163)	83	—	(80)
Revenues	397	1,012	260	1,272	1,669	(260)	19	1,428
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	17	—	—	—	17	—	—	17
Operating	223	114	66	180	403	(58)	4	349
Netback	157	898	194	1,092	1,249	(202)	15	1,062
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					1,249	(202)	15	1,062

(1)Revenues and expenses related to the HCML joint venture.

(2)Includes other activities not attributable to the production of crude oil and natural gas.

(3)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	75
	Basis of Netback Calculation					Adjustments
---	---	---	---	---	---	---	---	---
Year Ended December 31, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>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

(1)Revenues and expenses related to the HCML joint venture.

(2)Includes other activities not attributable to the production of crude oil and natural gas.

(3)These amounts, excluding Netback, are found in Note 1 of the Consolidated Financial Statements.

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)	2025	2024	2025	2024
Oil Sands (2)
Foster Creek	227.5	184.0	208.0	188.8
Christina Lake	315.3	245.7	254.8	231.9
Sunrise	60.3	52.2	53.5	50.0
Lloydminster	134.4	125.9	126.8	127.7
Total Oil Sands	737.5	607.8	643.1	598.4
Conventional (3)	120.4	117.8	122.8	119.9
Offshore
Atlantic	8.0	6.2	11.3	8.0
Asia Pacific
China	38.4	42.6	38.3	42.6
Indonesia (4)	15.6	19.6	15.9	16.0
Total Asia Pacific	54.0	62.2	54.2	58.6
Total Offshore	62.0	68.4	65.5	66.6

(1)Sales volumes exclude the impact of purchased condensate.

(2)Includes bitumen and heavy crude oil sales.

(3)For the three months and year ended December 31, 2025, reported sales volumes reflect Cenovus’s 30 percent equity interest in the Duvernay joint venture.

(4)Reported sales volumes reflect Cenovus’s 40 percent equity interest in the HCML joint venture.

Other Specified Financial Measures

Per-Unit Operating Expenses

Per-unit operating expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. 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.

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 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.

Cenovus Energy Inc. – 2025 Management's Discussion and Analysis	76

cve-20251231

Exhibit 99.3

Cenovus Energy Inc.

Consolidated Financial Statements

For the Year Ended December 31, 2025

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS

| For the year ended December 31, 2025 | | --- || TABLE OF CONTENTS | | --- || REPORT OF MANAGEMENT | 3 | | --- | --- | | REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM | 4 | | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | 8 | | CONSOLIDATED BALANCE SHEETS | 9 | | CONSOLIDATED STATEMENTS OF EQUITY | 10 | | CONSOLIDATED STATEMENTS OF CASH FLOWS | 11 | | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | 12 | | 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES | 12 | | 2.BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE | 16 | | 3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY | 17 | | 4. MEG ENERGY CORP. ACQUISITION | 19 | | 5. GENERAL AND ADMINISTRATIVE | 21 | | 6. FINANCE COSTS, NET | 21 | | 7. FOREIGN EXCHANGE (GAIN) LOSS, NET | 21 | | 8. DIVESTITURES | 21 | | 9. IMPAIRMENT CHARGES AND REVERSALS | 22 | | 10. INCOME TAXES | 24 | | 11. PER SHARE AMOUNTS | 26 | | 12. CASH AND CASH EQUIVALENTS | 27 | | 13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES | 27 | | 14. INVENTORIES | 27 | | 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 | 32 | | 22. DEBT AND CAPITAL STRUCTURE | 32 | | 23. DECOMMISSIONING LIABILITIES | 36 | | 24. OTHER LIABILITIES | 36 | | 25. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS | 37 | | 26. SHARE CAPITAL AND WARRANTS | 39 | | 27. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | 42 | | 28. STOCK-BASED COMPENSATION PLANS | 42 | | 29. EMPLOYEE SALARIES AND BENEFIT EXPENSES | 45 | | 30. RELATED PARTY TRANSACTIONS | 45 | | 31. FINANCIAL INSTRUMENTS | 46 | | 32. RISK MANAGEMENT | 48 | | 33. SUPPLEMENTARY CASH FLOW INFORMATION | 50 | | 34. COMMITMENTS AND CONTINGENCIES | 52 | | 35. MATERIAL ACCOUNTING POLICIES | 53 | | Cenovus Energy Inc. – 2025 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 five independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee 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.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2025. 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, 2025.

Management excluded the internal control activities of the business acquired by the Company through a business combination in 2025 (see Note 4) from its assessment of internal control over financial reporting as at December 31, 2025. The total assets and total revenues of the acquired business excluded from Management's assessment of internal control over financial reporting represents 18 percent and one percent, respectively, of the related Consolidated Financial Statement amounts as at and for the year ended December 31, 2025.

The Consolidated Financial Statements of Cenovus Energy Inc. as at December 31, 2025, and 2024, and for each of the two years in the period ended December 31, 2025, and the effectiveness of internal control over financial reporting as of December 31, 2025, has been audited and unqualified opinions have been issued by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report dated February 18, 2026.

/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 18, 2026
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	3
---	---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders 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 (the Company) as of December 31, 2025 and 2024, 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, 2025, 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, 2025 and 2024, 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, 2025, 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.

As described in Management's Assessment of Internal Control Over Financial Reporting, management has excluded MEG Energy Corp. from its assessment of internal control over financial reporting as of December 31, 2025, because it was acquired by the Company through a business combination during 2025. We have also excluded MEG Energy Corp. from our audit of internal control over financial reporting. MEG Energy Corp. was a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent 18% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	4

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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, Net (PP&E) within the Oil Sands segment

As described in notes 1, 3, 16 and 35 to the Consolidated Financial Statements, the PP&E balance in the Oil Sands segment was $34.1 billion as of December 31, 2025. In aggregate, the Company recognized $3.4 billion of depreciation, depletion and amortization (DD&A) expense related to the Oil Sands segment for the year ended December 31, 2025. Management calculates depletion for the Oil Sands segment PP&E using the unit-of-production method based on estimated proved reserves. Costs subject to depletion include estimated future development costs to be incurred in developing those proved reserves. Estimating proved reserves requires the use of key assumptions and judgments by Management including expected future production volumes, future development and operating expenses, as well as forward commodity prices. Management's estimates of proved reserves used for the calculation of DD&A expense related to PP&E in the Oil Sands segment 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 proved reserves on PP&E, within the Oil Sands segment 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 proved reserves; (ii) 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; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	5

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 proved reserves and the calculation of DD&A expenses related to PP&E in the Oil Sands segment. These procedures also included, among others, testing Management's process for determining DD&A expense for the Oil Sands segment, which included for certain properties (i) evaluating the appropriateness of the methods used by Management in making these proved reserve estimates; (ii) testing the completeness and accuracy of the underlying data used in Management's estimates of proved reserves; (iii) assessing the reasonability of the key 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 proved reserves used in the calculation of DD&A expense related to PP&E in the Oil Sands segment. As a basis for using this work, the specialists' qualifications were understood, and the Company's relationship with the specialists was assessed. The procedures performed also included, for certain properties within the Oil Sands segment, evaluation of the methods and key assumptions used by the specialists, tests of data used by the specialists, and an evaluation of the specialists' findings. Professionals with specialized skill and knowledge assisted in this evaluation, as applicable. Evaluating the key 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 key assumptions used were reasonable considering the current and past performance of the Oil Sands segment and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable.

Valuation of acquired Property, Plant and Equipment (PP&E) related to the acquisition of MEG Energy Corp.

As described in notes 1, 3, 4 and 35 to the Consolidated Financial Statements, on November 13, 2025, the Company acquired MEG Energy Corp. (MEG) in an acquisition accounted for as a business combination using the acquisition method, which requires that assets acquired and liabilities assumed be measured at fair value on the acquisition date, with any excess of the purchase price over the estimated fair value of the net assets acquired recorded as goodwill. Total consideration for the total issued and outstanding common shares of MEG, including those previously owned by the Company, was $7.9 billion. The assets acquired included PP&E, which was valued at $9.7 billion. Management estimated the fair value of the acquired PP&E at the acquisition date using a discounted cash flow model. This fair value assessment required the use of significant judgments by Management including key assumptions related to forward commodity prices, expected future production volumes, quantity of reserves, future development and operating expenses and discount rate. The quantity of reserves has been developed by Management's specialists, including independent qualified reserve evaluators.

The principal considerations for our determination that performing procedures relating to the valuation of acquired PP&E related to the acquisition of MEG Energy Corp. is a critical audit matter are (i) the significant judgment by Management, including the use of Management’s specialists, as applicable, when developing the fair value of the acquired PP&E; (ii) the high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating key assumptions used in the discounted cash flow model used to value the acquired PP&E related to forward commodity prices, expected future production volumes, quantity of reserves, future development and operating expenses and discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	6

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimated fair value of the acquired PP&E. These procedures also included, among others, testing Management’s process for determining the fair value of the acquired PP&E, which included (i) evaluating the appropriateness of the discounted cash flow model used by Management in making this estimate; (ii) testing the completeness and accuracy of underlying data used in Management’s determination of the fair value and (iii) assessing the reasonability of the key assumptions related to forward commodity prices, expected future production volumes, quantity of reserves, future development and operating expenses and discount rate. The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the quantity of reserves. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and key assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings. Professionals with specialized skill and knowledge assisted in this evaluation, as applicable. Evaluating the key assumptions used by Management’s specialists also involved assessing whether the key assumptions used were reasonable considering the current and past performance of MEG and the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the fair value of the acquired PP&E determined by Management, including the discount rate.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants
Calgary, Canada
February 18, 2026
We have served as the Company’s auditor since 2008.
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	7
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
---

For the years ended December 31,

($ millions, except per share amounts)

	Notes	2025	2024
Revenues	1	49,696	54,277
Expenses	1
Purchased Product, Transportation and Blending		32,688	36,641
Operating		6,336	6,841
(Gain) Loss on Risk Management	31	(37)	58
Depreciation, Depletion, Amortization and Exploration Expense	15,16,17	5,233	4,940
(Income) Loss From Equity-Accounted Affiliates	18	(53)	(66)
General and Administrative	5	812	794
Finance Costs, Net	6	569	514
Integration, Transaction and Other Costs	4	234	166
Foreign Exchange (Gain) Loss, Net	7	(361)	462
(Gain) Loss on Divestiture of Assets	4,8	(87)	(119)
Re-measurement of Contingent Payments		—	30
Other (Income) Loss, Net		(115)	(55)
Earnings (Loss) Before Income Tax		4,477	4,071
Income Tax Expense (Recovery)	10	547	929
Net Earnings (Loss)		3,930	3,142
Other Comprehensive Income (Loss), Net of Tax	27
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits	25	17	14
Change in the Fair Value of Equity Instruments at FVOCI (1)	31	(25)	71
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		(1,904)	1,020
Total Other Comprehensive Income (Loss), Net of Tax		(1,912)	1,105
Comprehensive Income (Loss)		2,018	4,247
Net Earnings (Loss) Per Common Share ($)	11
Basic		2.16	1.68
Diluted		2.15	1.67

(1)Fair value through other comprehensive income (loss) (“FVOCI”).

See accompanying Notes to the Consolidated Financial Statements.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	8
CONSOLIDATED BALANCE SHEETS
---

As at December 31,

($ millions)

	Notes	2025	2024
Assets
Current Assets
Cash and Cash Equivalents	12	2,740	3,093
Accounts Receivable and Accrued Revenues	13	3,435	2,614
Income Tax Receivable		366	231
Inventories	14	3,349	4,496
Total Current Assets		9,890	10,434
Restricted Cash	23	256	241
Exploration and Evaluation Assets, Net	1,15	575	484
Property, Plant and Equipment, Net	1,16	45,260	38,568
Right-of-Use Assets, Net	1,17	2,153	1,950
Income Tax Receivable		25	25
Investments in Equity-Accounted Affiliates	18	295	399
Other Assets	19	464	451
Deferred Income Taxes	10	1,594	1,064
Goodwill	1,20	2,912	2,923
Total Assets		63,424	56,539
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities	21	5,847	6,242
Income Tax Payable		98	396
Short-Term Borrowings	22	—	173
Long-Term Debt	22	—	192
Lease Liabilities	17	369	359
Total Current Liabilities		6,314	7,362
Long-Term Debt	22	11,032	7,342
Lease Liabilities	17	2,806	2,568
Decommissioning Liabilities	23	4,872	4,534
Other Liabilities	24	889	919
Deferred Income Taxes	10	5,873	4,045
Total Liabilities		31,786	26,770
Shareholders’ Equity		31,622	29,754
Non-Controlling Interest		16	15
Total Liabilities and Equity		63,424	56,539
Commitments and Contingencies	34

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 18, 2026
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	9
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CONSOLIDATED STATEMENTS OF EQUITY
---

($ millions)

	Shareholders’ Equity
	Common Shares	Treasury<br>Shares	Preferred Shares	Warrants	Paid in<br><br>Surplus	Retained<br><br>Earnings	AOCI (1)	Total
	(Note 26)	(Note 26)	(Note 26)	(Note 26)	(Note 26)		(Note 27)
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<br>(Loss), Net of Tax	—	—	—	—	—	—	1,105	1,105
Total Comprehensive Income (Loss)	—	—	—	—	—	3,142	1,105	4,247
Common Shares Issued Under<br>Stock Option Plans	68	—	—	—	(16)	—	—	52
Purchase of Common Shares Under<br><br>NCIB (2)	(479)	—	—	—	(966)	—	—	(1,445)
Purchase of Common Shares Under<br>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<br>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
Net Earnings (Loss)	—	—	—	—	—	3,930	—	3,930
Other Comprehensive Income <br>(Loss), Net of Tax	—	—	—	—	—	—	(1,912)	(1,912)
Total Comprehensive Income (Loss)	—	—	—	—	—	3,930	(1,912)	2,018
Common Shares Issued (Note 4)	3,667	—	—	—	—	—	—	3,667
Common Shares Issued Under<br>Stock Option Plans	20	—	—	—	(4)	—	—	16
Purchase of Common Shares Under<br><br>NCIB (2)	(771)	—	—	—	(541)	(683)	—	(1,995)
Purchase of Common Shares Under<br>Employee Benefit Plan	—	(155)	—	—	—	—	—	(155)
Common Shares Issued Under<br>Employee Benefit Plan	—	82	—	—	(6)	—	—	76
Preferred Shares Redeemed	—	—	(243)	—	(107)	—	—	(350)
Warrants Exercised	24	—	—	(8)	—	—	—	16
Stock-Based Compensation Expense	—	—	—	—	12	—	—	12
Base Dividends on Common Shares	—	—	—	—	—	(1,423)	—	(1,423)
Dividends on Preferred Shares	—	—	—	—	—	(14)	—	(14)
As at December 31, 2025	18,599	(116)	113	4	298	12,323	401	31,622

(1)Accumulated other comprehensive income (loss) (“AOCI”).

(2)Normal course issuer bid (“NCIB”). Includes taxes payable on purchase of shares.

See accompanying Notes to the Consolidated Financial Statements.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	10
CONSOLIDATED STATEMENTS OF CASH FLOWS
---

For the years ended December 31,

($ millions)

	Notes	2025	2024
Operating Activities
Net Earnings (Loss)		3,930	3,142
Depreciation, Depletion and Amortization	16,17	5,192	4,871
Deferred Income Tax Expense (Recovery)	10	(231)	(474)
Unrealized (Gain) Loss on Risk Management	31	(15)	12
Unrealized Foreign Exchange (Gain) Loss	7	(424)	550
Realized Foreign Exchange (Gain) Loss on Non-Operating Items		23	—
(Gain) Loss on Divestiture of Assets	4,8	(87)	(119)
Re-measurement of Contingent Payments		—	30
Unwinding of Discount on Decommissioning Liabilities	23	243	225
(Income) Loss From Equity-Accounted Affiliates	18	(53)	(66)
Distributions Received From Equity-Accounted Affiliates	18	135	172
Stock-Based Compensation, Net of Payments		163	(145)
Other		(5)	(34)
Settlement of Decommissioning Liabilities	23	(280)	(234)
Net Change in Non-Cash Working Capital	33	(363)	1,305
Cash From (Used in) Operating Activities		8,228	9,235
Investing Activities
Acquisitions, Net of Cash Acquired	4	(3,666)	(22)
Capital Investment	1	(4,907)	(5,015)
Proceeds From Divestitures	8	1,891	46
Acquisition of Ownership Interest in MEG Energy Corp.	4	(752)	—
Net Change in Investments and Other		(7)	(80)
Net Change in Non-Cash Working Capital	33	(236)	(55)
Cash From (Used in) Investing Activities		(7,677)	(5,126)
Net Cash Provided (Used) Before Financing Activities		551	4,109
Financing Activities	33
Net Issuance (Repayment) of Short-Term Borrowings		152	5
Issuance of Long-Term Debt	22	5,265	—
Repayment of Long-Term Debt	22	(2,324)	—
Principal Repayment of Leases	17	(350)	(299)
Net Proceeds (Repayment) on Repurchase Agreements		413	—
Common Shares Issued Under Stock Option Plans		16	52
Purchase of Common Shares Under NCIB	26	(1,995)	(1,445)
Purchase of Common Shares Under Employee Benefit Plan	26	(155)	(43)
Redemption of Preferred Shares	26	(350)	(250)
Proceeds From Exercise of Warrants		16	26
Dividends Paid	11	(1,437)	(1,551)
Cash From (Used in) Financing Activities		(749)	(3,505)
Effect of Foreign Exchange on Cash and Cash Equivalents		(155)	262
Increase (Decrease) in Cash and Cash Equivalents		(353)	866
Cash and Cash Equivalents, Beginning of Year		3,093	2,227
Cash and Cash Equivalents, End of Year		2,740	3,093

See accompanying Notes to the Consolidated Financial Statements.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	11

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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 are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1 and 2 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

•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, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets, as well as Christina Lake, which includes the results from the acquisition of MEG Energy Corp. (“MEG”) through a plan of arrangement (the “MEG Acquisition”) (see Note 4). Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

•Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas 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 Limited (“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. On September 30, 2025, Cenovus divested its entire 50 percent interest in the jointly-owned Wood River and Borger refineries held through WRB Refining LP (“WRB”) with operator Phillips 66 (see Note 8). The U.S. Refining segment included the WRB results up to the date of divestiture. Cenovus markets its own and third-party refined products.

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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	12

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

A) Results of Operations – Segment and Operational Information

	Upstream
	Oil Sands		Conventional		Offshore		Total
For the years ended December 31,	2025	2024	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales	21,541	21,857	1,305	1,211	1,508	1,572	24,354	24,640
Intersegment Sales	6,786	6,590	1,355	1,848	—	—	8,141	8,438
	28,327	28,447	2,660	3,059	1,508	1,572	32,495	33,078
Royalties	(2,920)	(3,274)	(55)	(76)	(80)	(99)	(3,055)	(3,449)
Revenues	25,407	25,173	2,605	2,983	1,428	1,473	29,440	29,629
Expenses
Purchased Product	2,886	1,851	1,337	1,823	—	—	4,223	3,674
Transportation and Blending	10,875	11,000	351	320	17	11	11,243	11,331
Operating	2,754	2,511	464	555	349	423	3,567	3,489
Realized (Gain) Loss on Risk<br>   Management	8	20	(4)	(6)	—	—	4	14
Operating Margin	8,884	9,791	457	291	1,062	1,039	10,403	11,121
Unrealized (Gain) Loss on Risk<br><br>Management	3	(16)	(4)	4	—	—	(1)	(12)
Depreciation, Depletion and<br>   Amortization	3,433	3,117	479	442	440	563	4,352	4,122
Exploration Expense	11	2	22	1	8	66	41	69
(Income) Loss From Equity-<br>   Accounted Affiliates	(38)	(14)	—	2	(31)	(53)	(69)	(65)
Segment Income (Loss)	5,475	6,702	(40)	(158)	645	463	6,080	7,007			Downstream
---	---	---	---	---	---	---
	Canadian Refining		U.S. Refining		Total
For the years ended December 31,	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales	4,282	4,787	24,115	28,299	28,397	33,086
Intersegment Sales	797	523	3	9	800	532
	5,079	5,310	24,118	28,308	29,197	33,618
Royalties	—	—	—	—	—	—
Revenues	5,079	5,310	24,118	28,308	29,197	33,618
Expenses
Purchased Product	4,128	4,483	21,727	25,769	25,855	30,252
Transportation and Blending	—	—	—	—	—	—
Operating	597	907	2,546	2,763	3,143	3,670
Realized (Gain) Loss on Risk Management	—	—	(6)	8	(6)	8
Operating Margin	354	(80)	(149)	(232)	205	(312)
Unrealized (Gain) Loss on Risk Management	—	—	(5)	8	(5)	8
Depreciation, Depletion and Amortization	178	185	566	462	744	647
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	176	(265)	(710)	(702)	(534)	(967)
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	13
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

	Corporate and Eliminations		Consolidated
For the years ended December 31,	2025	2024	2025	2024
Gross Sales
External Sales	—	—	52,751	57,726
Intersegment Sales	(8,941)	(8,970)	—	—
	(8,941)	(8,970)	52,751	57,726
Royalties	—	—	(3,055)	(3,449)
Revenues	(8,941)	(8,970)	49,696	54,277
Expenses
Purchased Product	(7,910)	(7,823)	22,168	26,103
Transportation and Blending	(723)	(793)	10,520	10,538
Purchased Product, Transportation and Blending	(8,633)	(8,616)	32,688	36,641
Operating	(374)	(318)	6,336	6,841
Realized (Gain) Loss on Risk Management	(20)	24	(22)	46
Unrealized (Gain) Loss on Risk Management	(9)	16	(15)	12
Depreciation, Depletion and Amortization	96	102	5,192	4,871
Exploration Expense	—	—	41	69
(Income) Loss From Equity-Accounted Affiliates	16	(1)	(53)	(66)
Segment Income (Loss)	(17)	(177)	5,529	5,863
General and Administrative	812	794	812	794
Finance Costs, Net	569	514	569	514
Integration, Transaction and Other Costs	234	166	234	166
Foreign Exchange (Gain) Loss, Net	(361)	462	(361)	462
(Gain) Loss on Divestiture of Assets	(87)	(119)	(87)	(119)
Re-measurement of Contingent Payments	—	30	—	30
Other (Income) Loss, Net	(115)	(55)	(115)	(55)
	1,052	1,792	1,052	1,792
Earnings (Loss) Before Income Tax			4,477	4,071
Income Tax Expense (Recovery)			547	929
Net Earnings (Loss)			3,930	3,142

B) External Sales by Product

	Upstream
	Oil Sands		Conventional		Offshore		Total
For the years ended December 31,	2025	2024	2025	2024	2025	2024	2025	2024
Crude Oil	20,215	21,183	215	207	401	321	20,831	21,711
Natural Gas and Other	318	332	864	648	850	925	2,032	1,905
NGLs (1)	1,008	342	226	356	257	326	1,491	1,024
External Sales	21,541	21,857	1,305	1,211	1,508	1,572	24,354	24,640			Downstream
---	---	---	---	---	---	---
	Canadian Refining		U.S. Refining		Total
For the years ended December 31,	2025	2024	2025	2024	2025	2024
Gasoline	234	429	11,640	13,792	11,874	14,221
Distillates (2)	1,422	1,484	9,170	10,632	10,592	12,116
Synthetic Crude Oil	1,567	1,814	—	—	1,567	1,814
Asphalt	506	548	924	1,029	1,430	1,577
Other Products and Services	553	512	2,381	2,846	2,934	3,358
External Sales	4,282	4,787	24,115	28,299	28,397	33,086

(1)Third-party condensate sales are included within NGLs.

(2)Includes diesel and jet fuel.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	14

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

C) Geographical Information

	Revenues (1)
For the years ended December 31,	2025	2024
Canada	23,789	26,791
United States	24,895	26,333
China	1,012	1,153
Consolidated	49,696	54,277

(1)Revenues from external customers by country are classified based on the jurisdiction in which the selling entities are located.

	Non-Current Assets (1)
As at December 31,	2025	2024
Canada	47,641	37,006
United States	2,514	5,902
China	939	1,249
Indonesia	203	295
Consolidated	51,297	44,452

(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, 2025, Cenovus had two customers (2024 – 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 $11.7 billion and $5.8 billion, respectively (2024 – $17.7 billion and $8.1 billion, respectively), and are reported across all of the Company’s operating segments.

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
As at December 31,	2025	2024	2025	2024	2025	2024
Oil Sands	568	461	34,149	24,646	1,204	1,018
Conventional	—	15	2,202	2,230	44	57
Offshore	7	8	4,008	3,365	180	95
Canadian Refining	—	—	2,452	2,511	50	39
U.S. Refining	—	—	2,238	5,538	287	342
Corporate and Eliminations	—	—	211	278	388	399
Consolidated	575	484	45,260	38,568	2,153	1,950			Goodwill		Total Assets
---	---	---	---	---
As at December 31,	2025	2024	2025	2024
Oil Sands	2,912	2,923	42,505	31,668
Conventional	—	—	2,579	2,610
Offshore	—	—	4,756	4,089
Canadian Refining	—	—	2,831	2,901
U.S. Refining	—	—	4,698	9,517
Corporate and Eliminations	—	—	6,055	5,754
Consolidated	2,912	2,923	63,424	56,539
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	15
---	---

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

E) Capital Expenditures (1)

For the years ended December 31,	2025	2024
Capital Investment
Oil Sands	2,944	2,714
Conventional	453	421
Offshore
Atlantic	848	1,077
Asia Pacific	86	68
Total Upstream	4,331	4,280
Canadian Refining	117	208
U.S. Refining	442	488
Total Downstream	559	696
Corporate and Eliminations	17	39
	4,907	5,015
Acquisitions
Oil Sands (Note 4)	10,120	9
Conventional	44	13
	10,164	22
Total Capital Expenditures	15,071	5,037

(1)Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the Company's joint ventures.

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

These Consolidated Financial Statements are presented in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements 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 35.

These Consolidated Financial Statements were approved by the Board of Directors effective February 18, 2026.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	16

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 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 and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

A) Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.

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.

On September 30, 2025, Cenovus divested its entire 50 percent interest in WRB, which was a jointly-controlled entity (see Note 8). The joint arrangement met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company recognized its share of the assets, liabilities, revenues and expenses in its consolidated results up to the date of divestiture.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	17

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

In determining the classification of its joint arrangement under IFRS 11, the Company considered the following:

•The original intention of the joint arrangement was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.

•The agreements required the partners to make contributions if funds were insufficient to meet the obligations or liabilities of the corporation and partnership. The past and future development of WRB was dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.

•WRB had third-party debt facilities to cover short-term working capital requirements.

•Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provided marketing services, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf as the agreements prohibited the partners from undertaking these roles themselves. In addition, the joint arrangement did not have employees and, as such, was not capable of performing these roles.

•In the arrangement, output was taken by the partners, indicating that the partners had the rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangement.

B) Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis, and any revisions to accounting estimates are recorded in the period in which the estimates are revised.

The 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.

The following are the key estimates, assumptions and judgments 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 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”).

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

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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	18

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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, if any, 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. 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.

4. MEG ENERGY CORP. ACQUISITION

A) Summary of the Acquisition

On November 13, 2025, Cenovus completed the MEG Acquisition pursuant to which Cenovus acquired all the issued and outstanding common shares of MEG, other than common shares of MEG already owned by Cenovus, for total purchase consideration of $7.1 billion, consisting of $3.4 billion in cash, 143.9 million Cenovus common shares and $32 million of assumed stock-based compensation. Prior to closing the MEG Acquisition, the Company held an aggregate of 25.0 million common shares of MEG with an acquisition-date fair value of $775 million.

The MEG Acquisition provides Cenovus with additional oil sands assets that are directly adjacent to the Company’s Christina Lake asset and are reported under the Christina Lake results in the Oil Sands segment.

The MEG Acquisition was accounted for using the acquisition method pursuant to IFRS 3, “Business Combinations” (“IFRS 3”). Under the acquisition method, assets and liabilities are recorded at fair value on the date of acquisition, with the exception of ROU assets, lease liabilities, income taxes and stock-based compensation. 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. In accordance with the step acquisition treatment of IFRS 3, the previously held interest in MEG is required to be re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss).

B) Identifiable Assets Acquired and Liabilities Assumed

The preliminary purchase price allocation is based on Management’s best estimate of fair value. Upon finalizing the fair value of net assets acquired, adjustments to initial estimates, including goodwill, may be required.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	19

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

The following table summarizes the details of the consideration and the recognized amounts of assets acquired and liabilities assumed at the date of the acquisition.

As at	November 13, 2025
Consideration
Cash	3,441
Common Shares (1)	3,667
Stock-Based Compensation	32
Total Purchase Consideration	7,140
Fair Value of Pre-Existing Ownership Interest	775
Total Consideration	7,915
Identifiable Assets Acquired and Liabilities Assumed
Cash	36
Accounts Receivable and Accrued Revenues	571
Income Tax Receivable	13
Inventories	499
Exploration and Evaluation Assets	174
Property, Plant and Equipment	9,709
Right-of-Use Assets	301
Other Assets	13
Accounts Payable and Accrued Liabilities	(444)
Income Tax Payable	(3)
Long-Term Debt	(843)
Lease Liabilities	(366)
Decommissioning Liabilities	(184)
Other Liabilities	(27)
Deferred Income Tax Liabilities, Net	(1,534)
Total Identifiable Net Assets	7,915
Goodwill	—

(1)Based on the November 13, 2025, opening share price of $25.48, as reported on the TSX.

The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $571 million, all of which was collected.

C) Fair Value of Pre-Existing Ownership Interest

The acquisition-date fair value of the previously held MEG common shares was estimated to be $775 million and the net carrying value was $752 million. Cenovus recognized a revaluation gain of $23 million, which is recorded in gain (loss) on divestiture of assets in net earnings (loss).

D) Transaction Costs

For the year ended December 31, 2025, integration and transaction costs related to the acquisition of $72 million were recognized in net earnings (loss).

E) Revenue and Profit Contribution

The acquired business contributed revenues of $623 million and segment income of $29 million for the period from November 13, 2025, to December 31, 2025.

If the closing of the MEG Acquisition had occurred on January 1, 2025, Cenovus's consolidated pro forma revenues and segment income for the year ended December 31, 2025, would have been $53.4 billion and $6.0 billion, respectively. These amounts were calculated using results from the acquired business adjusting them for additional DD&A that would be charged assuming the fair value adjustments to PP&E had applied from January 1, 2025, and differences in accounting policies. This pro forma information is not necessarily indicative of the results that would have been obtained if the MEG Acquisition had actually occurred on January 1, 2025.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	20

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

| 5. GENERAL AND ADMINISTRATIVE | | --- || For the years ended December 31, | 2025 | 2024 | | --- | --- | --- | | Salaries and Benefits | 282 | 269 | | Administrative and Other | 339 | 399 | | Stock-Based Compensation Expense (Recovery) (Note 28) | 191 | 126 | | | 812 | 794 | | 6. FINANCE COSTS, NET | | --- || For the years ended December 31, | 2025 | 2024 | | --- | --- | --- | | Interest Expense – Short-Term Borrowings and Long-Term Debt | 333 | 307 | | Net Premium (Discount) on Redemption of Long-Term Debt (1) | 9 | — | | Interest Expense – Lease Liabilities (Note 17) | 171 | 162 | | Unwinding of Discount on Decommissioning Liabilities (Note 23) | 243 | 225 | | Other | 40 | 35 | | Capitalized Interest | (86) | (45) | | Finance Costs | 710 | 684 | | Interest Income | (141) | (170) | | | 569 | 514 |

(1)Includes the premium on redemption, transaction costs and the amortization of associated fair value adjustments.

| 7. FOREIGN EXCHANGE (GAIN) LOSS, NET | | --- || For the years ended December 31, | 2025 | 2024 | | --- | --- | --- | | Unrealized Foreign Exchange (Gain) Loss on Translation of: | | | | U.S. Dollar Debt | (312) | 442 | | Other | (112) | 108 | | Unrealized Foreign Exchange (Gain) Loss | (424) | 550 | | Realized Foreign Exchange (Gain) Loss | 63 | (88) | | | (361) | 462 | | 8. DIVESTITURES | | --- |

A) 2025 Divestitures

On September 30, 2025, the Company divested its entire 50 percent interest in WRB, which was reported in the U.S. Refining segment, for proceeds of US$1.3 billion (C$1.9 billion) after closing adjustments. The before-tax gain of $119 million on divestiture reflects the difference between proceeds and the Company’s share of net assets of $3.0 billion and a cumulative foreign currency translation adjustment directly attributable to WRB of $1.3 billion (see Note 27) that was recycled upon divestiture.

The Company also closed the sale of certain Lloydminster thermal assets in the Oil Sands segment for total proceeds of $75 million in cash and variable consideration of $29 million, which resulted in a before-tax loss of $58 million.

B) 2024 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, 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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	21

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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, 2025, and 2024, and there were no impairments. No impairment indicators were identified for the remaining CGUs as at December 31, 2025, and 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 the IQRE forward prices and cost estimates as at December 31, 2025. All reserves were evaluated as at December 31, 2025, and December 31, 2024, by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward commodity prices as at December 31, 2025, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2026	2027	2028	2029	2030	Average Annual Increase Thereafter<br><br>(percent)
WTI (1) (US$/bbl) (2)	59.92	65.10	70.28	71.93	73.37	2.00
WCS (3) (C$/bbl)	65.13	70.43	76.90	78.71	80.29	2.00
Condensate at Edmonton (C$/bbl)	80.01	86.19	92.83	95.04	96.94	2.00
Alberta Energy Company Natural Gas (C$/Mcf) (4)	3.00	3.30	3.49	3.58	3.65	2.00

(1)West Texas Intermediate (“WTI”).

(2)Barrel ("bbl").

(3)Western Canadian Select at Hardisty (“WCS”).

(4)One thousand cubic feet (“Mcf”).

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<br><br>(percent)
WTI (US$/bbl)	71.58	74.48	75.81	77.66	79.22	2.00
WCS (C$/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)	2.36	3.33	3.48	3.69	3.76	2.00

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 13 percent (2024 – 14 percent).

Sensitivities

A one percent (2024 – one percent) increase in the discount rate or a five percent (2024 – five percent) decrease in forward commodity price estimates would not impact the results of the impairment tests performed.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	22

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

B) Downstream Cash-Generating Units

i) 2025 Impairment Charges and Reversals

As at December 31, 2025, there were no indicators of impairment or impairment reversals for the Company's downstream CGUs.

ii) 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.

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 were 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 had on the impairment amount as at December 31, 2024, for the U.S. Refining CGUs:

	Increase (Decrease) to Impairment Amount
	One Percent Increase in<br><br>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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	23

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

10. INCOME TAXES

A) Income Tax Expense (Recovery)

For the years ended December 31,	2025	2024
Current Tax
Canada	540	1,141
United States	(1)	9
Asia Pacific	198	214
Other International	41	39
Total Current Tax Expense (Recovery)	778	1,403
Deferred Tax Expense (Recovery)	(231)	(474)
	547	929

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,	2025	2024
Earnings (Loss) Before Income Tax	4,477	4,071
Canadian Statutory Rate (percent)	23.7	23.7
Expected Income Tax Expense (Recovery)	1,061	965
Effect on Taxes Resulting From:
Statutory and Other Rate Differences	(37)	(34)
Non-Taxable Capital (Gains) Losses	(34)	45
Non-Recognition of Capital (Gains) Losses	(34)	45
Adjustments Arising From Prior Year Tax Filings	(37)	(31)
Recognition of U.S. Tax Basis	(54)	(77)
Cumulative Translation Adjustment	(298)	—
Other	(20)	16
Total Tax Expense (Recovery)	547	929
Effective Tax Rate (percent)	12.2	22.8

The effective tax rate for 2025 was 12.2 percent (2024 – 22.8 percent). The lower effective tax rate in 2025 is primarily attributable to the reclassification of the cumulative foreign currency translation adjustment associated with the WRB divestiture (see Note 8), which is not tax effected.

In 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.

For the year ended December 31, 2025, Pillar Two taxes did not have a material impact on net earnings. The Company is not expecting a material impact from jurisdictions where the Company operates that have not enacted Pillar Two legislation.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	24

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

B) Deferred Income Tax Assets and Liabilities

The significant components of the Company's deferred income tax expense (recovery) for the years ended December 31, 2025, and December 31, 2024, and deferred income tax (assets) liabilities as at December 31, 2025, and December 31, 2024, are composed of the following:

	Deferred Income Tax Expense (Recovery)		Deferred Income Tax (Assets) Liabilities
	2025	2024	December 31, 2025	December 31, 2024
Property, Plant and Equipment, Net	(494)	(632)	6,825	5,255
Right-of-Use Assets, Net	(23)	76	520	470
Decommissioning Liabilities	(32)	(85)	(1,094)	(1,018)
Unused Tax Losses	336	240	(852)	(740)
Lease Liabilities	27	(70)	(743)	(683)
Compensation and Benefits	(20)	34	(140)	(118)
Other	(25)	(37)	(237)	(185)
Net Deferred Income Tax Expense (Recovery) and Liability	(231)	(474)	4,279	2,981

Change in Deferred Income Tax Balances

	2025	2024
Net Deferred Income Tax Liability, Beginning of Year	2,981	3,492
Recognized in Deferred Income Tax Expense (Recovery)	(231)	(474)
Recognized in Other Comprehensive Income	3	15
Foreign Currency Translation Adjustment	45	(52)
Recognized on Acquisitions	1,481	—
Net Deferred Income Tax Liability, End of Year	4,279	2,981

Deferred Income Tax in Other Comprehensive Income

For the years ended December 31,	2025	2024
Deferred Income Tax Expense (Recovery) in OCI (1)
Pension and Other Post-Retirement Benefits	5	5
Private Equity Instruments	(2)	10
	3	15

(1)Other comprehensive income (“OCI”).

The deferred income tax asset of $1.6 billion as at December 31, 2025 (December 31, 2024 – $1.1 billion) 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, 2025, or December 31, 2024, 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,	2025	2024
Canada	12,135	10,086
United States	8,730	9,905
Asia Pacific	338	351
	21,203	20,342

As at December 31, 2025, the above tax pools included $38 million (December 31, 2024 – $197 million) of Canadian federal non-capital losses that expire no earlier than 2033, and $3.6 billion (December 31, 2024 – $3.0 billion) of U.S. federal net operating losses that have an indefinite carry forward period.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	25

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

As at December 31, 2025, the Company had Canadian net capital losses totaling $96 million (December 31, 2024 – $85 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $210 million (December 31, 2024 – $362 million) of deductible temporary differences associated with unrealized foreign exchange losses on its U.S. denominated debt.

11. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Common Share – Basic and Diluted

For the years ended December 31,	2025	2024
Net Earnings (Loss)	3,930	3,142
Effect of Cumulative Dividends on Preferred Shares	(14)	(36)
Net Earnings (Loss) – Basic	3,916	3,106
Effect of Stock-Based Compensation	(1)	3
Net Earnings (Loss) – Diluted	3,915	3,109
Basic – Weighted Average Number of Shares (thousands)	1,809,902	1,850,193
Dilutive Effect of Warrants	2,782	4,483
Dilutive Effect of Stock-Based Compensation	7,177	8,540
Diluted – Weighted Average Number of Shares (thousands)	1,819,861	1,863,216
Net Earnings (Loss) Per Common Share – Basic ($)	2.16	1.68
Net Earnings (Loss) Per Common Share – Diluted (1) ($)	2.15	1.67

(1)For the year ended December 31, 2025, 9.0 million common shares (2024 – 9.8 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

	2025		2024
For the years ended December 31,	Per Share	Amount	Per Share	Amount
Base Dividends	0.780	1,423	0.680	1,255
Variable Dividends	—	—	0.135	251
Total Common Share Dividends Declared and Paid	0.780	1,423	0.815	1,506

The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.

On February 18, 2026, the Company’s Board of Directors declared a first quarter base dividend of $0.200 per common share, payable on March 31, 2026, to common shareholders of record as at March 13, 2026.

C) Preferred Share Dividends

For the years ended December 31,	2025	2024
Series 1 First Preferred Shares	7	7
Series 2 First Preferred Shares	1	2
Series 3 First Preferred Shares	—	12
Series 5 First Preferred Shares	2	9
Series 7 First Preferred Shares	4	6
Total Preferred Share Dividends Declared	14	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, 2025, the Company paid $14 million in preferred share dividends (December 31, 2024 – $45 million).

On February 18, 2026, the Company’s Board of Directors declared first quarter preferred share dividends of $2 million payable on March 31, 2026, to preferred shareholders of record as at March 13, 2026.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	26

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

| 12. CASH AND CASH EQUIVALENTS | | --- || As at December 31, | 2025 | 2024 | | --- | --- | --- | | Cash | 1,963 | 2,723 | | Short-Term Investments | 777 | 370 | | | 2,740 | 3,093 |

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with an original maturity of three months or less.

| 13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES | | --- || As at December 31, | 2025 | 2024 | | --- | --- | --- | | Trade and Accruals | 3,046 | 2,378 | | Prepaids and Deposits | 260 | 187 | | Joint Operations Receivables | 36 | 40 | | Other | 93 | 9 | | | 3,435 | 2,614 | | 14. INVENTORIES | | --- || As at December 31, | 2025 | 2024 | | --- | --- | --- | | Product | | | | Crude Oil | 1,643 | 2,297 | | Diluent | 548 | 401 | | Natural Gas and NGLs | 55 | 77 | | Refined Products | 631 | 1,176 | | Total Product | 2,877 | 3,951 | | Parts and Supplies | 472 | 545 | | | 3,349 | 4,496 |

For the year ended December 31, 2025, approximately $36.6 billion of produced and purchased inventory, excluding DD&A, was recorded as an expense (2024 – approximately $42.8 billion).

As at December 31, 2025, and December 31, 2024, the Company had no product inventory write-downs.

| 15. EXPLORATION AND EVALUATION ASSETS, NET | | --- || | Total | | --- | --- | | As at December 31, 2023 | 738 | | Acquisitions | 7 | | Additions | 65 | | Transfer to PP&E (Note 16) | (285) | | Write-downs (1) | (37) | | Change in Decommissioning Liabilities | (5) | | Exchange Rate Movements and Other | 1 | | As at December 31, 2024 | 484 |

(1)For the year ended December 31, 2024, previously capitalized E&E costs of $37 million in the Offshore segment, was written off as exploration expense, as the carrying value was not considered to be recoverable.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	27

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

	Total
As at December 31, 2024	484
Acquisitions (Note 4)	174
Additions	87
Transfer to PP&E (Note 16)	(145)
Write-downs (1)	(25)
Exchange Rate Movements and Other	—
As at December 31, 2025	575

(1)For the year ended December 31, 2025, previously capitalized E&E costs of $4 million and $21 million in the Oil Sands and Conventional segments, respectively, were written off as exploration expense, as the carrying value was not considered to be recoverable.

| 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, 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 8) | (270) | — | — | (1) | (271) | | Exchange Rate Movements and Other (2) | 108 | 3 | 890 | 2 | 1,003 | | As at December 31, 2024 | 52,090 | 280 | 14,325 | 1,975 | 68,670 | | Acquisitions (Note 4) | 9,990 | — | — | — | 9,990 | | Additions | 4,244 | 4 | 543 | 29 | 4,820 | | Transfer from E&E (Note 15) | 145 | — | — | — | 145 | | Change in Decommissioning Liabilities | 184 | (1) | 1 | (4) | 180 | | Divestitures (Note 8) | (593) | — | (7,243) | (18) | (7,854) | | Exchange Rate Movements and Other (2) | (493) | (8) | (479) | (23) | (1,003) | | As at December 31, 2025 | 65,567 | 275 | 7,147 | 1,959 | 74,948 | | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | | | | | | | 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 8) | (208) | — | — | — | (208) | | Exchange Rate Movements and Other (2) | 133 | 1 | 469 | 2 | 605 | | As at December 31, 2024 | 21,849 | 141 | 6,675 | 1,437 | 30,102 | | Depreciation, Depletion and Amortization | 4,154 | 11 | 617 | 79 | 4,861 | | Divestitures (Note 8) | (408) | — | (4,195) | (8) | (4,611) | | Exchange Rate Movements and Other (2) | (387) | (9) | (263) | (5) | (664) | | As at December 31, 2025 | 25,208 | 143 | 2,834 | 1,503 | 29,688 | | CARRYING VALUE | | | | | | | As at December 31, 2024 | 30,241 | 139 | 7,650 | 538 | 38,568 | | As at December 31, 2025 | 40,359 | 132 | 4,313 | 456 | 45,260 |

(1)Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2)Includes derecognition of fully depreciated and depleted assets no longer owned by Cenovus of $362 million (2024 – $6 million).

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	28

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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,	2025	2024
Crude Oil and Natural Gas Properties	2,268	3,359
Refining Assets	147	400
	2,415	3,759
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, 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
Acquisitions (Note 4)	9	292	—	—	301
Additions	8	153	—	15	176
Modifications	4	143	1	2	150
Divestitures (Note 8)	(1)	(175)	(23)	(9)	(208)
Exchange Rate Movements and Other	(1)	(170)	(8)	(11)	(190)
As at December 31, 2025	611	2,635	148	122	3,516
ACCUMULATED DEPRECIATION
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
Depreciation	35	248	11	37	331
Divestitures (Note 8)	(1)	(144)	(8)	(9)	(162)
Exchange Rate Movements and Other	(4)	(126)	(5)	(8)	(143)
As at December 31, 2025	223	977	92	71	1,363
CARRYING VALUE
As at December 31, 2024	399	1,393	84	74	1,950
As at December 31, 2025	388	1,658	56	51	2,153

(1)Includes a pipeline, storage tanks, terminals, railcars, vessels, a natural gas processing plant and caverns.

(2)Includes assets in the commercial fuels business, fleet vehicles, camps and other equipment.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	29

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

B) Lease Liabilities

	2025	2024
Lease Liabilities, Beginning of Year	2,927	2,658
Acquisitions (Note 4)	366	—
Additions	174	363
Interest Expense (Note 6)	171	162
Lease Payments	(521)	(461)
Divestitures (Note 8)	(39)	—
Modifications	150	91
Exchange Rate Movements and Other	(53)	114
Lease Liabilities, End of Year	3,175	2,927
Less: Current Portion	369	359
Long-Term Portion	2,806	2,568

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.

18. JOINT ARRANGEMENTS

A) Joint Operations

Cenovus has a number of joint operations in the Upstream segments. On September 30, 2025, Cenovus divested its entire 50 percent interest in WRB in the U.S. Refining segment, which was a jointly controlled entity with Phillips 66 (see Note 8).

B) Joint Ventures

Husky-CNOOC Madura Limited

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,	2025	2024
Revenue	646	736
Expenses	610	605
Net Earnings (Loss)	36	131

Balance Sheet

As at December 31,	2025	2024
Current Assets (1)	270	441
Non-Current Assets	1,227	1,594
Current Liabilities	82	188
Non-Current Liabilities	868	1,046
Net Assets	547	801

(1)Includes cash and cash equivalents of $82 million (December 31, 2024 – $108 million).

For the year ended December 31, 2025, the Company’s share of income from the equity-accounted affiliate was $31 million (2024 – $53 million). As at December 31, 2025, the carrying amount of the Company’s share of net assets was $202 million (December 31, 2024 – $294 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, 2025, the Company received $94 million in distributions from HCML (2024 – $107 million) and paid $nil in contributions (2024 – $nil).

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	30

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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,	2025	2024
Cenovus's Share of Net Earnings (Loss)	(26)	(16)
Cenovus's Share of Other Comprehensive Income (Loss)	—	(2)
Cenovus's Share of Total Comprehensive Income (Loss)	(26)	(18)

The Company's share of equity investment income related to HMLP, in excess of the cumulative unrecognized losses, distributions received and contributions paid, is recorded in (income) loss from equity-accounted affiliates. Cenovus had unrecognized cumulative losses from earnings and OCI, net of tax, of $58 million as at December 31, 2025 (2024 – $48 million) related to HMLP.

For the year ended December 31, 2025, the Company received $40 million in distributions from HMLP (2024 – $65 million) and paid $2 million in contributions (2024 – $51 million).

As at December 31, 2025, the aggregate carrying value of the Company's investment in these joint ventures was $93 million (December 31, 2024 – $105 million).

| 19. OTHER ASSETS | | --- || As at December 31, | 2025 | 2024 | | --- | --- | --- | | Private Equity Investments (Note 31) | 193 | 219 | | Precious Metals | 54 | 92 | | Long-Term Receivables and Prepaids | 130 | 68 | | Net Investment in Finance Leases | 64 | 61 | | Intangible Assets | 23 | 11 | | | 464 | 451 | | 20. GOODWILL | | --- || | 2025 | 2024 | | --- | --- | --- | | Carrying Value, Beginning of Year | 2,923 | 2,923 | | Goodwill Disposed | (11) | — | | Carrying Value, End of Year | 2,912 | 2,923 |

The carrying amount of goodwill is allocated to the following CGUs:

As at December 31,	2025	2024
Primrose (Foster Creek)	1,171	1,171
Christina Lake	1,101	1,101
Lloydminster Thermal	640	651
	2,912	2,923
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	31
---	---

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

| 21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES | | --- || As at December 31, | 2025 | 2024 | | --- | --- | --- | | Trade and Accruals | 5,502 | 5,907 | | Joint Operations Payable | 66 | 110 | | Employee Long-Term Incentives | 163 | 132 | | Interest | 80 | 72 | | Provisions for Onerous and Unfavourable Contracts | 26 | 11 | | Other | 10 | 10 | | | 5,847 | 6,242 | | 22. DEBT AND CAPITAL STRUCTURE | | --- |

For the year ended December 31, 2025, the annualized weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings, was 4.5 percent (2024 – 4.5 percent).

A) Short-Term Borrowings

As at December 31,	Notes	2025	2024
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	—	173
Total Debt Principal		—	173

i) Uncommitted Demand Facilities

As at December 31, 2025, the Company had uncommitted demand facilities of $1.5 billion (December 31, 2024 – $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, 2025, there were outstanding letters of credit aggregating to $341 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).

ii) WRB Uncommitted Demand Facilities

On September 30, 2025, Cenovus completed the divestiture of its entire 50 percent interest in WRB, which included the Company’s proportionate share of the WRB uncommitted demand facilities outstanding of US$225 million (C$313 million) (see Note 8). Cenovus’s proportionate share of the WRB uncommitted demand facilities outstanding as at December 31, 2024, was US$120 million (C$173 million).

B) Long-Term Debt

As at December 31,	Notes	2025	2024
Committed Credit Facility	i	—	—
Term Loan Facility	ii	2,700	—
U.S. Dollar Denominated Senior Unsecured Notes	iii	5,887	5,470
Canadian Dollar Senior Unsecured Notes	iii	2,450	2,000
Total Debt Principal		11,037	7,470
Debt Premiums (Discounts), Net, and Transaction Costs		(5)	64
Long-Term Debt		11,032	7,534
Less: Current Portion		—	192
Long-Term Portion		11,032	7,342

i) Committed Credit Facility

On September 19, 2025, Cenovus renewed its existing committed credit facility to extend the maturity dates by more than one year. As at December 31, 2025, the committed credit facility consists of a $3.3 billion tranche maturing on September 19, 2029, and a $2.2 billion tranche maturing on September 19, 2028. As at December 31, 2025, no amount was drawn on the credit facility (December 31, 2024 – $nil).

The committed credit facility may include Canadian Overnight Repo Rate Average (“CORRA”) loans, Secured Overnight Financing Rate (“SOFR”) loans, prime rate loans and U.S. Base Rate (“USBR”) loans.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	32

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

ii) Term Loan Facility

Cenovus obtained a $2.7 billion term loan facility maturing on February 28, 2029, to fund a portion of the cash consideration for the MEG Acquisition (see Note 4). The term loan facility is unsecured and bears interest at the CORRA, SOFR, prime lending rate or USBR, as selected by the Company, plus the applicable pricing margins, which vary based on the Company’s credit rating.

iii) U.S. Dollar Denominated and Canadian Dollar Denominated Senior Unsecured Notes

Upon maturity on July 15, 2025, the Company repaid its 5.38 percent senior unsecured notes with a principal of US$133 million, in full.

Upon closing of the MEG Acquisition, the Company assumed MEG’s U.S. dollar senior unsecured notes with a fair value of $843 million (notional value – US$600 million) (see Note 4). The notes were subsequently redeemed on December 1, 2025, in full.

On November 20, 2025, the Company closed public offerings in Canada and the U.S. of senior unsecured notes of $2.6 billion, composed of $650 million 4.25 percent notes due in 2033, $550 million 4.60 percent notes due in 2035, US$500 million 4.65 percent notes due in 2031 and US$500 million 5.40 percent notes due in 2036.

On December 1, 2025, the Company redeemed its 4.25 percent senior unsecured notes with a principal of US$373 million, in full. On December 22, 2025, the Company redeemed its 3.60 percent senior unsecured notes with a principal of $750 million, in full. For the year ended December 31, 2025, a premium on redemption, net of amortization costs, of $9 million was recorded in finance costs.

The principal amounts of the Company’s outstanding senior unsecured notes are:

	2025		2024
As at December 31,	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Denominated Senior Unsecured Notes
5.38% due July 15, 2025	—	—	133	192
4.25% due April 15, 2027	—	—	373	537
4.40% due April 15, 2029	183	250	183	262
4.65% due March 20, 2031	500	685	—	—
2.65% due January 15, 2032	500	685	500	720
5.40% due March 20, 2036	500	685	—	—
5.25% due June 15, 2037	333	457	333	479
6.80% due September 15, 2037	191	262	191	275
6.75% due November 15, 2039	652	894	652	938
4.45% due September 15, 2042	91	125	91	131
5.20% due September 15, 2043	27	37	27	39
5.40% due June 15, 2047	569	779	569	818
3.75% due February 15, 2052	750	1,028	750	1,079
	4,296	5,887	3,802	5,470
Canadian Dollar Senior Unsecured Notes
3.60% due March 10, 2027		—		750
3.50% due February 7, 2028		1,250		1,250
4.25% due March 20, 2033		650		—
4.60% due November 20, 2035		550		—
		2,450		2,000
Total Senior Unsecured Notes		8,337		7,470

As at December 31, 2025, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility and term loan facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is below this limit.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	33

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

C) Mandatory Debt Payments

	U.S. Dollar Senior<br>Unsecured Notes		Canadian Dollar Senior Unsecured Notes	Term Loan Facility	Total
As at December 31, 2025	US$ Principal	C$ Principal Equivalent	C$ Principal	C$ Principal	C$ Principal and Equivalent
2026	—	—	—	—	—
2027	—	—	—	—	—
2028	—	—	1,250	—	1,250
2029	183	250	—	2,700	2,950
2030	—	—	—	—	—
Thereafter	4,113	5,637	1,200	—	6,837
	4,296	5,887	2,450	2,700	11,037

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 28, 2025, 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 2028. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.

To provide the Company with additional flexibility in managing liquidity and optimizing working capital, Cenovus leverages uncommitted receivables purchase agreements (the “Receivables Purchase Agreements”) with financial institutions, which may be used from time to time as part of the Company's working capital management strategy. The Receivables Purchase Agreements, when utilized, provide the Company with the ability, at its discretion, to sell interests in certain trade and accrued receivables. Transactions under the Receivables Purchase Agreements are structured such that the Company retains ongoing involvement with the receivables, including servicing activities, and continues to reflect the related receivables on its consolidated balance sheets. As at December 31, 2025, there were no transactions executed under the Receivables Purchase Agreements.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	34

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

Net Debt to Adjusted EBITDA

As at December 31,	2025	2024
Short-Term Borrowings	—	173
Current Portion of Long-Term Debt	—	192
Long-Term Portion of Long-Term Debt	11,032	7,342
Total Debt	11,032	7,707
Less: Cash and Cash Equivalents	(2,740)	(3,093)
Net Debt	8,292	4,614
Net Earnings (Loss)	3,930	3,142
Add (Deduct):
Finance Costs, Net	569	514
Income Tax Expense (Recovery)	547	929
Depreciation, Depletion and Amortization	5,192	4,871
Exploration and Evaluation Asset Write-downs	25	37
(Income) Loss From Equity-Accounted Affiliates	(53)	(66)
Unrealized (Gain) Loss on Risk Management	(15)	12
Foreign Exchange (Gain) Loss, Net	(361)	462
(Gain) Loss on Divestiture of Assets	(87)	(119)
Re-measurement of Contingent Payments	—	30
Other (Income) Loss, Net	(115)	(55)
Adjusted EBITDA (1)	9,632	9,757
Net Debt to Adjusted EBITDA (times)	0.9	0.5

(1)Calculated on a trailing twelve-month basis.

Net Debt to Adjusted Funds Flow

As at December 31,	2025	2024
Net Debt	8,292	4,614
Cash From (Used in) Operating Activities	8,228	9,235
(Add) Deduct:
Settlement of Decommissioning Liabilities	(280)	(234)
Net Change in Non-Cash Working Capital	(363)	1,305
Adjusted Funds Flow (1)	8,871	8,164
Net Debt to Adjusted Funds Flow (times)	0.9	0.6

(1)Calculated on a trailing twelve-month basis.

Net Debt to Capitalization

As at December 31,	2025	2024
Net Debt	8,292	4,614
Shareholders’ Equity	31,622	29,754
Capitalization	39,914	34,368
Net Debt to Capitalization (percent)	21	13
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	35
---	---

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

| 23. DECOMMISSIONING LIABILITIES | | --- || | 2025 | 2024 | | --- | --- | --- | | Decommissioning Liabilities, Beginning of Year | 4,534 | 4,155 | | Liabilities Acquired (Note 4) | 267 | — | | Liabilities Incurred | 269 | 24 | | Liabilities Settled | (280) | (234) | | Change in Estimated Future Cash Flows | 54 | 276 | | Change in Discount Rates | (143) | 132 | | Unwinding of Discount on Decommissioning Liabilities (Note 6) | 243 | 225 | | Liabilities Disposed (Note 8) | (61) | (72) | | Exchange Rate Movements and Other | (11) | 28 | | Decommissioning Liabilities, End of Year | 4,872 | 4,534 |

As at December 31, 2025, the undiscounted amount of estimated future cash flows required to settle the obligation is $17.7 billion (December 31, 2024 – $15.6 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 $222 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 5.5 percent (December 31, 2024 – 5.2 percent) and assumes an inflation rate of two percent (December 31, 2024 – 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, 2025, the Company had $256 million in long-term restricted cash (December 31, 2024 – $241 million).

Sensitivities

Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:

	Sensitivity	2025		2024
As at December 31,	Range	Increase	Decrease	Increase	Decrease
Credit-Adjusted Risk-Free Rate	± one percent	(548)	669	(487)	595
Inflation Rate	± one percent	685	(567)	615	(507)
24. OTHER LIABILITIES
---		As at December 31,	2025	2024
---	---	---
Renewable Volume Obligation, Net (1)	235	284
Pension and Other Post-Employment Benefit Plan	260	269
Employee Long-Term Incentives	169	96
Provisions for Onerous and Unfavourable Contracts	83	66
Provision for West White Rose Expansion Project	—	54
Other	142	150
	889	919

(1)The gross amounts of the renewable volume obligation (“RVO”) and RINs asset were $853 million and $618 million, respectively (December 31, 2024 – $652 million and $368 million, respectively).

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	36

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

25. 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, 2025, and the next required actuarial valuation was dated January 1, 2026.

A) Plan Obligations, Assets and Funded Status

	DB Pension Plan		OPEB Plans
	2025	2024	2025	2024
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year	214	202	252	249
Current Service Costs	16	14	7	2
Interest Costs (1)	10	9	12	12
Benefits Paid	(13)	(12)	(8)	(9)
Plan Participant Contributions	3	3	—	—
Re-measurements:
(Gains) Losses From Experience Adjustments	(1)	—	(3)	1
(Gains) Losses From Changes in Financial Assumptions	(5)	(3)	(2)	(6)
Exchange Rate Movements and Other	(1)	1	(2)	3
Defined Benefit Obligation, End of Year	223	214	256	252
Plan Assets
Fair Value of Plan Assets, Beginning of Year	201	178	—	—
Employer Contributions	12	11	8	9
Plan Participant Contributions	3	3	—	—
Benefits Paid	(13)	(12)	(8)	(9)
Interest Income (1)	10	8	—	—
Re-measurements:
Return on Plan Assets Excluding Interest Income	11	11	—	—
Exchange Rate Movements and Other	(1)	2	—	—
Fair Value of Plan Assets, End of Year	223	201	—	—
Defined Benefit Pension and OPEB Asset (Liability) (2)	—	(13)	(256)	(252)

(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 15 years and 13 years, respectively.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	37

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

B) Costs

	DB Pension Plan and <br>DC Pension Plan		OPEB Plans
For the years ended December 31,	2025	2024		2025	2024
Defined Benefit Plan Cost
Current Service Costs	16	14		7	2
Net Interest Costs	—	1		12	12
Re-measurements:
Return on Plan Assets Excluding Interest Income	(11)	(11)		—	—
(Gains) Losses From Experience Adjustments	(1)	—		(3)	1
(Gains) Losses From Changes in Financial Assumptions	(5)	(3)		(2)	(6)
Defined Benefit Plan Cost (Recovery)	(1)	1		14	9
Defined Contribution Plan Cost (1)	113	107		—	—
Total Plan Cost	112	108		14	9

(1)Includes defined contribution and U.S. 401(k) plans.

C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the DB Pension Plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns, and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark composed 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,	2025	2024
Level 1 – Cash and Cash Equivalents	4	3
Level 2 – Equity and Fixed Income Funds	206	185
Level 3 – Real Estate Funds and Other	13	13
	223	201

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, 2026, 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, 2026, the Company expects to contribute $12 million to the OPEB plans.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	38

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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,	2025	2024		2025	2024
Discount Rate (percent)	4.93	4.65		5.02	4.85
Future Salary Growth Rate (percent)	3.94	3.95		N/A	N/A
Average Longevity (years)	88.5	88.4		88.5	88.4
Health Care Cost Trend Rate (percent)	N/A	N/A		5.45	5.24

Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations.

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. The sensitivity analysis below shows the impact that a one percent change in the discount rate, while holding all other assumptions constant, would have on the DP Pension Plan and OPEB plan obligations:

	2025		2024
As at December 31,	Increase	Decrease	Increase	Decrease
Discount Rate	(57)	69	(56)	69

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.

26. 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

	2025		2024
	Number of<br><br>Common<br><br>Shares<br><br>(thousands)	Amount	Number of<br><br>Common<br><br>Shares<br><br>(thousands)	Amount
Outstanding, Beginning of Year	1,825,038	15,659	1,871,868	16,031
Issued Under the MEG Acquisition, Net of Issuance Costs (Note 4)	143,935	3,667	—	—
Issued Upon Exercise of Warrants	2,471	24	3,982	39
Issued Under Stock Option Plans	1,394	20	5,049	68
Purchase of Common Shares under NCIB	(89,438)	(771)	(55,861)	(479)
Outstanding, End of Year	1,883,400	18,599	1,825,038	15,659

As at December 31, 2025, there were 24.9 million common shares available for future issuance under the stock option plan.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	39

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

C) Normal Course Issuer Bid

For the year ended December 31, 2025, the Company purchased and cancelled 89.4 million common shares (2024 – 55.9 million) through the NCIB. The shares were purchased at a volume weighted average price of $21.87 per common share (2024 – $25.38) for a total of $2.0 billion (2024 – $1.4 billion). Paid in surplus representing the retained earnings prior to the split with Encana Corporation, now known as Ovintiv Inc. (“Ovintiv”), was reduced in full by $541 million. Retained earnings was then reduced by $683 million. The cumulative reduction to paid in surplus and retained earnings was $1.2 billion, which relates to the excess of the purchase price of the common shares over their average carrying value and share buyback tax of $38 million.

For the year ended December 31, 2024, paid in surplus was reduced by $966 million, representing the excess of the purchase price of the common shares over their average carrying value of $939 million and share buyback tax of $27 million.

On November 7, 2025, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 120.3 million common shares during the period from November 11, 2025, to November 10, 2026.

From January 1, 2026, to February 13, 2026, the Company purchased an additional 5.0 million common shares for $126 million. As at February 13, 2026, the Company can further purchase up to 107.9 million common shares under the NCIB.

D) Treasury Shares

Cenovus has 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.

	2025		2024
	Number of<br><br>Common<br><br>Shares<br><br>(thousands)	Amount	Number of<br><br>Common<br><br>Shares<br><br>(thousands)	Amount
Outstanding, Beginning of Year	2,000	43	—	—
Purchase of Common Shares Under Employee Benefit Plan	7,100	155	2,000	43
Distributed Under Employee Benefit Plan	(3,842)	(82)	—	—
Outstanding, End of Year	5,258	116	2,000	43

Paid in surplus was reduced by $6 million, representing the difference between the long-term incentive obligation and the weighted average carrying value of the treasury shares on settlement.

E) Issued and Outstanding – Preferred Shares

First Preferred Shares

	2025		2024
	Number of Preferred Shares (thousands)	Amount	Number of<br><br>Preferred<br><br>Shares<br><br>(thousands)	Amount
Outstanding, Beginning of Year	26,000	356	36,000	519
Preferred Shares Redeemed	(14,000)	(243)	(10,000)	(163)
Outstanding, End of Year	12,000	113	26,000	356

On March 31, 2025, and June 30, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company's series 5 preferred shares and all 6.0 million of the Company's series 7 preferred shares, respectively. The preferred shares were redeemed at a price of $25.00 per share for a total of $350 million. Paid in surplus was reduced by $107 million, representing the excess of the purchase price of the preferred shares over their carrying value.

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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	40

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

The Company had the following preferred shares outstanding as at December 31, 2025:

As at December 31, 2025	Dividend Reset Date	Dividend Rate<br><br>(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	3.95	1,260

(1)The floating-rate dividend was 5.21 percent from December 31, 2024, to March 30, 2025 (December 31, 2023, to March 30, 2024 – 6.77 percent); 4.57 percent from March 31, 2025, to June 29, 2025 (March 31, 2024, to June 29, 2024 – 6.71 percent); 4.37 percent from June 30, 2025, to September 29, 2025 (June 30, 2024, to September 29, 2024 – 6.60 percent); and 4.39 percent from September 30, 2025, to December 30, 2025 (September 30, 2024, to December 30, 2024 – 5.94 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.

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 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. For the series 2 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.

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 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).

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, 2025 (December 31, 2024 – nil).

F) Issued and Outstanding – Warrants

	2025		2024
	Number of<br><br>Warrants<br><br>(thousands)	Amount	Number of<br><br>Warrants<br><br>(thousands)	Amount
Outstanding, Beginning of Year	3,643	12	7,625	25
Exercised	(2,471)	(8)	(3,982)	(13)
Outstanding, End of Year	1,172	4	3,643	12

The exercise price of the warrants was $6.54 per share. The warrants expired on January 1, 2026.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	41

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

G) Paid in Surplus

	Retained Earnings Prior to Ovintiv Split	Stock-Based Compensation	Total
As at December 31, 2023	1,707	295	2,002
Common Shares Issued on Exercise of Stock Options	—	(16)	(16)
Purchase of Common Shares Under NCIB	(966)	—	(966)
Preferred Shares Redeemed	(87)	—	(87)
Stock-Based Compensation Expense	—	11	11
As at December 31, 2024	654	290	944
Common Shares Issued on Exercise of Stock Options	—	(4)	(4)
Purchase of Common Shares Under NCIB	(541)	—	(541)
Common Shares Issued Under Employee Benefit Plan	(6)	—	(6)
Preferred Shares Redeemed	(107)	—	(107)
Stock-Based Compensation Expense	—	12	12
As at December 31, 2025	—	298	298
27. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
---			Pension and Other Post-Retirement Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
---	---	---	---	---
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
Other Comprehensive Income (Loss), Before Tax	22	(27)	(643)	(648)
Reclassification on Divestiture (Note 8)	—	—	(1,261)	(1,261)
Income Tax (Expense) Recovery	(5)	2	—	(3)
As at December 31, 2025	86	131	184	401
28. STOCK-BASED COMPENSATION PLANS
---

Cenovus has a number of stock-based compensation plans that include net settlement rights (“NSRs”), 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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	42

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

Stock Options With Associated Net Settlement Rights

The weighted average unit fair value of NSRs granted during the year ended December 31, 2025, was $2.64 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)	2.61
Expected Dividend Yield (percent)	3.60
Expected Volatility (1) (percent)	20.65
Expected Life (years)	5.30

(1)Expected volatility has been based on historical share volatility of the Company.

For the year ended December 31, 2025, 328 thousand NSRs, with a weighted average exercise price of $9.48, were exercised and settled for 328 thousand common shares.

	Number of<br><br>Stock Options<br><br>with Associated Net Settlement Rights	Weighted <br>Average <br>Exercise Price
For the year ended December 31, 2025	(thousands)	($/unit)
Outstanding, Beginning of Year	8,653	17.83
Granted	4,389	20.42
Exercised	(1,384)	11.70
Forfeited	(568)	20.77
Expired	(228)	22.99
Outstanding, End of Year	10,862	19.40			Outstanding			Exercisable
---	---	---	---	---	---
As at December 31, 2025	Number of <br>Stock Options with Associated Net Settlement Rights	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of <br>Stock Options with Associated Net Settlement Rights	Weighted Average Exercise Price
Range of Exercise Price ($/unit)	(thousands)	(years)	($/unit)	(thousands)	($/unit)
5.00 to 9.99	916	2.14	8.69	916	8.69
10.00 to 14.99	1,246	0.93	11.69	1,246	11.69
15.00 to 19.99	1,398	3.19	19.86	1,376	19.88
20.00 to 24.99	7,083	5.58	21.81	1,279	23.86
25.00 to 29.99	219	5.49	27.18	66	27.18
	10,862	4.45	19.40	4,883	16.83

Cenovus Replacement Stock Options

For the year ended December 31, 2025, 317 thousand Cenovus replacement stock options with a weighted average exercise price of $3.54 were exercised and net settled for cash, and 12 thousand Cenovus replacement stock options were exercised with a weighted average price of $3.54 and settled for 10 thousand common shares.

As at December 31, 2025, no Cenovus replacement stock options were outstanding.

B) Performance Share Units

Cenovus 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.

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 $128 million as at December 31, 2025, (December 31, 2024 – $80 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, 2025.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	43

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

	Number of Performance Share Units
For the year ended December 31, 2025	(thousands)
Outstanding, Beginning of Year	7,210
Granted	3,365
Vested and Paid Out	(2,305)
Forfeited	(1,016)
Units Granted in Lieu of Base Dividends	275
Outstanding, End of Year	7,529

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 Restricted Share Unit Plan for Local Employees in the Asia Pacific region may only be settled in cash.

In connection with the MEG Acquisition, the Company assumed all outstanding MEG restricted share awards that were not accelerated at closing. The MEG restricted share awards continue to be governed by and are subject to the terms and conditions of the corresponding legacy MEG plans, which were assumed by Cenovus. No additional share awards will be granted under the legacy MEG plans. As at December 31, 2025, 1,748 thousand restricted share units were outstanding under the legacy MEG plans.

The Company recorded a liability of $161 million as at December 31, 2025, (December 31, 2024 – $105 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, 2025.

	Number of Restricted Share Units
For the year ended December 31, 2025	(thousands)
Outstanding, Beginning of Year	8,148
Granted	4,358
Assumed Pursuant to the MEG Acquisition (Note 4)	2,630
Vested and Paid Out	(2,828)
Forfeited	(928)
Units Granted in Lieu of Base Dividends	383
Outstanding, End of Year	11,763

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 $43 million as at December 31, 2025 (December 31, 2024 – $38 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. – 2025 Consolidated Financial Statements	44

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

	Number of Deferred <br>Share Units
For the year ended December 31, 2025	(thousands)
Outstanding, Beginning of Year	1,761
Granted to Directors	186
Granted	187
Units Granted in Lieu of Base Dividends	71
Redeemed	(371)
Outstanding, End of Year	1,834

E) Total Stock-Based Compensation

For the years ended December 31,	2025	2024
Stock Options With Associated Net Settlement Rights	10	12
Cenovus Replacement Stock Options	(1)	1
Performance Share Units	96	48
Restricted Share Units	76	60
Deferred Share Units	10	5
Total Stock-Based Compensation Expense (Recovery)	191	126
29. EMPLOYEE SALARIES AND BENEFIT EXPENSES
---		For the years ended December 31,	2025	2024
---	---	---
Salaries, Bonuses and Other Short-Term Employee Benefits	1,541	1,526
Pension and Post-Employment Benefits	130	119
Stock-Based Compensation (Note 28)	191	126
Termination Benefits	110	41
	1,972	1,812
30. 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,	2025	2024
Salaries, Director Fees and Other Short-Term Benefits	44	47
Pension and Post-Employment Benefits	3	4
Stock-Based Compensation	60	48
Termination Benefits	11	11
	118	110

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,	2025	2024
Revenues from Construction and Management Services	164	155
Transportation Expenses	258	278
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	45
---	---

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

31. 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 certain portions of 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, 2025, the carrying value of Cenovus’s long-term debt was $11.0 billion and the fair value was $10.6 billion (December 31, 2024 carrying value – $7.5 billion, fair value – $6.9 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:

	2025	2024
Fair Value, Beginning of Year	219	131
Acquisitions	6	7
Transfer to Investments in Equity-Accounted Affiliates	(5)	—
Changes in Fair Value	(27)	81
Fair Value, End of Year	193	219

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), and 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

	2025			2024
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Condensate, Natural Gas and Refined Products	27	30	(3)	9	10	(1)
Power Contracts	2	—	2	6	—	6
Renewable Power Contracts	17	6	11	5	—	5
Foreign Exchange Rate Contracts	—	—	—	—	3	(3)
	46	36	10	20	13	7
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	46
---	---

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

As at December 31,	2025	2024
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(1)	2
Level 3 – Prices Sourced From Partially Unobservable Data	11	5
	10	7

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

	2025	2024
Fair Value of Contracts, Beginning of Year	7	12
Change in Fair Value of Contracts in Place at Beginning of Year	2	(20)
Change in Fair Value of Contracts Entered Into During the Year	23	(30)
Fair Value of Contracts Realized During the Year	(22)	46
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	—	(1)
Fair Value of Contracts, End of Year	10	7

Offsetting Financial Assets and Liabilities

Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same.

	2025			2024
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	80	70	10	38	31	7
Amount Offset	(34)	(34)	—	(18)	(18)	—
Net Amount	46	36	10	20	13	7

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, 2025, $26 million was pledged as cash collateral (December 31, 2024 – $18 million).

C) Earnings Impact of (Gains) Losses From Risk Management Positions

For the years ended December 31,	2025	2024
Realized (Gain) Loss	(22)	46
Unrealized (Gain) Loss	(15)	12
(Gain) Loss on Risk Management	(37)	58

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

The variable payment (Level 3) associated with the transaction with BP Canada Energy Group ULC to purchase the remaining 50 percent interest in Sunrise Oil Sands Partnership ended on August 31, 2024.

	2024
Contingent Payments, Beginning of Year	164
Liabilities Settled or Payable	(194)
Re-measurement	30
Contingent Payments, End of Year	—
Cenovus Energy Inc. – 2025 Consolidated Financial Statements	47
---	---

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

32. RISK MANAGEMENT

Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates and 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 and interest costs on short-term borrowings, the Company may enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts.

As at December 31, 2025, the fair value of risk management positions was a net asset of $10 million (see Note 31). As at December 31, 2025, there were no foreign exchange contracts or interest rate contracts outstanding. As at December 31, 2024, there were foreign exchange contracts with a notional value of US$250 million and no interest rate contracts outstanding.

Net Fair Value of Risk Management Positions

As at December 31, 2025	Notional Volumes (1) (2)	Terms	Weighted<br><br>Average<br><br>Price (2)	Fair Value Asset (Liability)
WTI Contracts Related to Blending (3)
WTI Fixed – Sell	9.3 MMbbls	January 2026 - December 2026	US$59.15/bbl	25
WTI Fixed – Buy	0.7 MMbbls	January 2026 - December 2026	US$60.14/bbl	(3)
Power Contacts				2
Renewable Power Contracts				11
Other Financial Positions (4)				(25)
Total Fair Value				10

(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)    WTI futures contracts are used to help manage price exposure to condensate used for blending. Includes individual WTI contracts with varying terms, the longest of which is 12 months.

(4)    Includes risk management positions related to WCS, heavy oil, light oil and condensate differentials, benchmark delivery location spreads, Belvieu and heating oil fixed price contracts, natural gas basis and fixed price contracts, and reformulated blendstock for oxygenate blending gasoline contracts.

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 has used crude oil, condensate, refined product, power and natural gas risk management contracts, and swaps, and may enter into options or forwards. 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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	48

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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 7). As at December 31, 2025, Cenovus had US$4.3 billion in U.S. dollar debt (December 31, 2024 – US$3.8 billion). 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,	2025	2024
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate	215	196
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate	(215)	(196)

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, 2025	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	1	(1)
WCS (Hardisty) Differential Price	± US$2.50/bbl Applied to WCS Differential Hedges Tied to Production	13	(13)
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(4)	4
Natural Gas Commodity Price	± US$0.50/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$10.00/MWh (2) Applied to Power Hedges	39	(39)
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 Tie 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	± $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”).

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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	49

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

As at December 31, 2025, approximately 81 percent (December 31, 2024 – 79 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss (“ECL”) on these accounts was 0.3 percent as at December 31, 2025 (December 31, 2024 – 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, 2025, the Company’s sources of capital included:

•$2.7 billion in cash and cash equivalents.

•$5.5 billion available on its committed credit facility.

•$1.2 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.

•The base shelf prospectus, availability of which is dependent on market conditions.

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2025	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	5,847	—	—	—	5,847
Long-Term Debt (1)	473	2,206	3,633	9,718	16,030
Lease Liabilities (1)	519	922	688	2,719	4,848
As at December 31, 2024	1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,242	—	—	—	6,242
Short-Term Borrowings	173	—	—	—	173
Long-Term Debt (1)	526	1,910	1,989	7,286	11,711
Lease Liabilities (1)	538	824	645	2,606	4,613

(1)Principal and interest, including current portion, if applicable.

33. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital

As at December 31,	2025	2024
Total Current Assets	9,890	10,434
Total Current Liabilities	6,314	7,362
Working Capital	3,576	3,072

B) Changes in Non-Cash Working Capital

For the years ended December 31,	2025 (1)	2024
Accounts Receivable and Accrued Revenues	(575)	547
Income Tax Receivable	(124)	199
Inventories	716	(117)
Accounts Payable and Accrued Liabilities	(318)	299
Income Tax Payable	(298)	322
Total Change in Non-Cash Working Capital	(599)	1,250
Net Change in Non-Cash Working Capital – Operating Activities	(363)	1,305
Net Change in Non-Cash Working Capital – Investing Activities	(236)	(55)
Total Change in Non-Cash Working Capital	(599)	1,250

(1)Excludes the impacts of acquisitions (see Note 4) and the divestiture of WRB (see Note 8).

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	50

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

C) Cash Flows Related to Interest and Taxes

For the years ended December 31,	2025	2024
Interest Paid	381	356
Interest Received	141	163
Income Taxes Paid	1,225	868

D) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable	Repurchase Agreements Payable (1)	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
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
Acquisition	—	—	—	855	—
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	152	—	—
Issuance of Long-Term Debt	—	—	—	5,265	—
Repayment of Long-Term Debt	—	—	—	(2,324)	—
Principal Repayment of Leases	—	—	—	—	(350)
Proceeds on Repurchase Agreements	—	840	—	—	—
Repayment of Repurchase Agreements	—	(427)	—	—	—
Dividends Paid	(1,437)	—	—	—	—
Non-Cash Changes:
Divestiture of Short-Term Borrowings	—	—	(313)	—	—
Finance and Transaction Costs	—	—	—	(7)	—
Lease Acquisitions	—		—	—	366
Lease Additions	—	—	—	—	174
Lease Divestitures	—	—	—	—	(39)
Lease Modifications	—	—	—	—	150
Base Dividends Declared on Common Shares	1,423	—	—	—	—
Dividends Declared on Preferred Shares	14	—	—	—	—
Exchange Rate Movements and Other	—	(12)	(12)	(291)	(53)
As at December 31, 2025	—	401	—	11,032	3,175

(1)Repurchase Agreements primarily relate to RINs.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	51

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

34. 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, 2025	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	2,603	2,623	2,775	2,802	2,531	23,591	36,925
Real Estate	64	65	65	69	70	474	807
Obligation to Fund HCML	99	94	54	42	41	59	389
Other Long-Term Commitments	547	184	151	117	111	484	1,594
Total Commitments	3,313	2,966	3,045	3,030	2,753	24,608	39,715		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

(1)Includes transportation commitments that are subject to regulatory approval or were approved but are not yet in service of $7.7 billion (December 31, 2024 – $854 million), of which $1.6 billion were assumed from the MEG Acquisition. Terms are up to 15 years on commencement.

(2)As at December 31, 2025, includes $1.7 billion related to transportation and storage commitments with HMLP (December 31, 2024 – $1.8 billion).

Through the MEG Acquisition, the Company assumed $8.3 billion of various transportation and storage commitments.

There were outstanding letters of credit aggregating to $341 million (December 31, 2024 – $355 million) issued as security for financial and performance conditions under certain contracts.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	52

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

35. 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 not to 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.

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.

The Company may enter into certain transactions whereby an asset is sold with the commitment to repurchase the same, or similar, asset from the same counterparty at a later date. These transactions are accounted for as repurchase agreements and are recognized as financing arrangements when the cost to repurchase is higher than the original price received. The asset remains on the balance sheet with any payments received recorded to accounts payable until repurchased. Any excess on repurchase is recorded to finance expense.

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 (income) 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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	53

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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).

F) Exploration and Evaluation Assets

E&E assets consist of exploratory projects for crude oil, NGLs and natural gas that are generally pending the determination of proved reserves. The costs to acquire non-producing oil and gas properties, licences 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 recorded 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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	54

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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.

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 ECLs 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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	55

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

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 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 to their fair value at the date of acquisition, with certain exceptions such as ROU assets, lease liabilities, income taxes and stock-based compensation.

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).

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 or preferred 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 to the extent available, and subsequently to retained earnings. 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 long-term incentive liability recognized in paid in surplus to the extent available and subsequently to retained earnings.

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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	56

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

M) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans that include stock options with associated NSRs, 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.

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 based on the objective of the business model for managing the instrument or group of instruments, and the contractual terms of the cash flows as noted below. 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, contingent payments and equity investments in public companies.
Fair Value Through Other Comprehensive<br>   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.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	57

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2025

O) Foreign Currency Translation

The Company’s functional and presentation currency is Canadian dollars. The Company uses the direct method of consolidation. Translation gains and losses relating to foreign operations with a functional currency different from the presentation currency are recognized in OCI as cumulative translation adjustments. When the Company disposes of an interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings.

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the reporting date. Any gains or losses are recognized in net earnings (loss).

P) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2026, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2025. The standards applicable to Cenovus are as follows and will be adopted on their respective dates:

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 amendments to IFRS 9 and IFRS 7 will not have a material impact on the Consolidated Financial Statements.

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 continuing to evaluate the impacts of adopting IFRS 18 on the Consolidated Financial Statements. Cenovus will adopt IFRS 18 effective January 1, 2027, using the retrospective approach.

Cenovus Energy Inc. – 2025 Consolidated Financial Statements	58

Document

Exhibit 99.4

Cenovus Energy Inc.

Supplementary Information – Oil and Gas Activities (unaudited)

For the Year Ended December 31, 2025

(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, 2025, 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 2025 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 on production history will result in variations in the estimated reserves, which may be material. 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 17, 2026, with an effective date of December 31, 2025.

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
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
2025
Beginning of year		3,853		105		28		766		4,115
Technical revisions and improved recovery		(96)		2		2		84		(78)
Revisions due to price		161		(2)		1		20		163
Total revisions to prior estimates		66		(1)		3		104		85
Extensions and discoveries		212		8		3		106		240
Purchase of reserves in place		535		3		—		2		538
Sale of reserves in place		(22)		—		—		—		(22)
Production		(179)		(14)		(7)		(212)		(235)
End of year		4,464		101		27		766		4,721
Developed		867		42		24		679		1,046
Undeveloped		3,597		59		4		87		3,674
Total		4,464		101		27		766		4,721
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
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
2025
Beginning of year		—		—		8		225		46
Technical revisions and improved recovery		—		—		1		27		5
Revisions due to price		—		—		—		(1)		—
Total revisions to prior estimates		—		—		1		26		5
Production		—		—		(2)		(66)		(13)
End of year		—		—		7		184		38
Developed		—		—		7		184		38
Undeveloped		—		—		—		—		—
Total		—		—		7		184		38
Total Consolidated Entities
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
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)
2025
Beginning of year		3,853		105		37		991		4,160
Technical revisions and improved recovery		(96)		2		3		111		(72)
Revisions due to price		161		(2)		1		19		163
Total revisions to prior estimates		66		(1)		4		130		90
Extensions and discoveries		212		8		3		106		240
Purchase of reserves in place		535		3		—		2		538
Sale of reserves in place		(22)		—		—		—		(22)
Production		(179)		(14)		(9)		(278)		(248)
End of year		4,464		101		35		951		4,758
Developed		867		42		31		864		1,084
Undeveloped		3,597		59		4		87		3,674
Total		4,464		101		35		951		4,758
Equity-Accounted Affiliates
Indonesia
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
2025
Beginning of year		—		—		2		108		20
Technical revisions and improved recovery		—		—		—		(11)		(2)
Revisions due to price		—		—		—		—		—
Total revisions to prior estimates		—		—		—		(10)		(2)
Extensions and discoveries		—		—		—		5		1
Production		—		—		—		(25)		(4)
End of year		—		—		1		78		14
Developed		—		—		1		78		14
Undeveloped		—		—		—		—		—
Total		—		—		1		78		14
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
2025
Beginning of year		—		7		1		17		11
Technical revisions and improved recovery		—		—		—		1		—
Revisions due to price		—		—		—		—		—
Total revisions to prior estimates		—		—		—		1		—
Extensions and discoveries		—		1		—		2		2
Production		—		—		—		(1)		—
End of year		—		8		1		20		12
Developed		—		1		—		3		2
Undeveloped		—		7		1		16		10
Total		—		8		1		20		12

(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, 2025, and December 31, 2024, is set forth below.

Year ended December 31, 2025

The changes to the Company's net proved bitumen reserves in 2025 are explained as follows:

•Technical revisions and improved recovery: Decreases to recovery factors at Christina Lake and Foster Creek were partially offset by improvements to recovery performance at Sunrise and Lloydminster thermal and resulted in a decrease in net proved reserves of 178 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 82 million barrels.

•Revisions due to price: Decreased bitumen prices decreased royalties payable for the Oil Sands segment, which resulted in an increase 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.

Cenovus Energy Inc.	6	Supplementary Information – Oil and Gas Activities (unaudited)

•Purchase of reserves in place: The acquisition of MEG Energy Corp. increased net proved reserves.

•Sale of reserves in place: The sale of a minor property in Lloydminster thermal decreased net proved reserves.

The changes to the Company's net proved reserves of crude oil, natural gas liquids and natural gas in 2025 are explained as follows:

•Technical revisions and improved recovery: Improved base performance in the Conventional segment and increases to original natural gas in place volumes for China and Indonesia were partially offset by updates to the Conventional segment development plan and reductions to recovery performance in Indonesia, increasing net proved reserves.

•Revisions due to price: In the Conventional segment, higher natural gas prices increased recoverable volumes of natural gas, partially offset by higher royalties, which resulted in an increase in net proved reserves.

•Extensions and discoveries: Development within the Conventional segment and Lloydminster conventional heavy oil increased net proved reserves.

•Purchase of reserves in place: The acquisition of minor interests in Lloydminster conventional heavy oil and the Conventional segment increased net proved reserves.

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.

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

Cenovus Energy Inc.	7	Supplementary Information – Oil and Gas Activities (unaudited)

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)CushingOklahoma	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)
2025		69.38
2024		81.17

All values are in US Dollars.

(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.	8	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, 2025
		Consolidated Entities				Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
Future cash inflows		290,184		2,760	292,944		917		690
Less future:
Production costs		89,655		666	90,321		540		209
Development costs		39,812		81	39,893		—		277
Asset retirement obligation payments (1)		8,665		46	8,711		35		7
Income taxes		33,644		422	34,066		137		47
Future net cash flows		118,408		1,545	119,953		205		150
Less 10 percent annual discount for estimated timing of cash flow		69,578		252	69,830		35		93
Discounted future net cash flow		48,830		1,293	50,123		170		57			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

(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.	9	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, 2025
	Consolidated Entities						Equity-Accounted Affiliates
($ millions)	Canada		China			Total	Indonesia	Canada
Balance, beginning of year		51,493		1,658		53,151	254	58
Changes resulting from:
Sales of oil and gas produced during the period, net of operating costs (1)		(9,505)		(898)		(10,403)	(203)	(12)
Extensions, discoveries and improved recovery, net of related cost		8,350		—		8,350	16	40
Purchases of proved reserves in place		9,117		—	9,117		—	—
Sales of proved reserves in place		(365)		—		(365)	—	—
Net change in prices and production costs (1)		(14,021)		(119)		(14,140)	64	(33)
Revisions to quantity estimates		1,260		237		1,497	(43)	—
Accretion of discount		5,963		138		6,101	32	9
Changes in estimated future development costs		(6,343)		(31)		(6,374)	—	(28)
Costs incurred		4,158		86		4,244	—	21
Other		(1,032)		298		(734)	23	—
Net change in income taxes		(245)		(76)		(321)	27	2
Balance, end of year		48,830		1,293		50,123	170	57
	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

(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.	10	Supplementary Information – Oil and Gas Activities (unaudited)

OTHER FINANCIAL INFORMATION

Results of Operations

	Year Ended December 31, 2025
	Consolidated Entities					Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
External sales		23,266		1,088	24,354		343		23
Intersegment sales		8,141		—	8,141		—		—
Royalties, purchased product, transportation and blending and realized risk management		(18,449)		(76)	(18,525)		(83)		(4)
Oil and gas sales, net of royalties, purchased product, transportation and blending and realized risk management		12,958		1,012	13,970		260		19
Less:
Operating costs and accretion of asset retirement obligations		3,672		127	3,799		60		7
Depreciation, depletion and amortization		3,995		357	4,352		121		13
Exploration expense		35		6	41		4		—
Operating income		5,256		522	5,778		75		(1)
Income taxes		1,527		199	1,726		30		—
Results of operations		3,729		323	4,052		45		(1)
	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<br><br>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)
Cenovus Energy Inc.	11	Supplementary Information – Oil and Gas Activities (unaudited)
---	---	---

Capitalized Costs

	Year Ended December 31, 2025
	Consolidated Entities					Equity-Accounted Affiliates
($ millions)	Canada		China		Total	Indonesia		Canada
Proved oil and gas properties		62,279		3,288	65,567		452	242
Unproved oil and gas properties (1)		568		7	575		—	—
Total capital costs		62,847		3,295	66,142		452	242
Accumulated depreciation, depletion and amortization		22,844		2,364	25,208		297	157
Net capitalized costs		40,003		931	40,934		155	85			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 costs		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

(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, 2025
	Consolidated Entities						Equity-Accounted Affiliates
($ millions)	Canada		China		Total		Indonesia		Canada
Acquisitions
Unproved (1)		174		—		174		—	—
Proved (2) (3)		9,990		—		9,990		—	—
Total acquisitions		10,164		—		10,164		—	—
Exploration costs		87		—		87		—	—
Development costs		4,158		86		4,244		—	21
Total costs incurred		14,409		86		14,495		—	21
	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

(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.	12	Supplementary Information – Oil and Gas Activities (unaudited)

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 19, 2026

/s/ Jonathan M. McKenzie
Jonathan M. McKenzie<br><br>President & Chief Executive Officer

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 19, 2026

/s/ Karamjit S. Sandhar
Karamjit S. Sandhar<br><br>Executive Vice-President & Chief Financial Officer

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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, 2025, 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 19, 2026

/s/ Jonathan M. McKenzie
Jonathan M. McKenzie<br><br>President & Chief Executive Officer

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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, 2025, 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 19, 2026

/s/ Karamjit S. Sandhar
Karamjit S. Sandhar<br><br>Executive Vice-President & Chief Financial Officer

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, 2025 of Cenovus Energy Inc. of our report dated February 18, 2026, 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. 333-291853), Form S-8 (File Nos. 333-163397, 333-251886 and 333-283967) and Form F-3D (File No. 333-202165) of Cenovus Energy Inc. of our report dated February 18, 2026 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.

Chartered Professional Accountants

Calgary, Alberta, Canada February 19, 2026

PricewaterhouseCoopers LLP

Suncor Energy Centre, 111 5th Avenue South West, Suite 2900, Calgary, Alberta, Canada T2P 5L3

T.: +1 403 509 7500, F.: +1 403 781 1825

Fax to mail: ca_calgary_main_fax@pwc.com

"PwC" refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.

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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, 2025, 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, 2025 and Cenovus Energy Inc.’s registration statements on Form F-10 (File No. 333-291853), 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 Verney

______________________________

Michael Verney, P. Eng.

Executive Vice President

Calgary, Alberta

February 19, 2026

2000, Eighth Avenue Place, East Tower, 525 – 8 Avenue SW, Calgary, AB, T2P 1G1 Tel: (403) 262-5506 www.mcdan.com

Document

Exhibit 99.11

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the use of and reference to our name and report evaluating a portion of Cenovus Energy Inc.’s oil and gas reserves data, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2025, 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, 2025 and Cenovus Energy Inc.’s registration statements on Form F-10 (File No. 333-291853), 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.

Yours truly,

GLJ LTD.

“Originally Signed By”

Jodi L. Anhorn, M. Sc., P. Eng.

President and Chief Executive Officer

Calgary, Alberta

February 19, 2026

1920, 401 – 9th Ave SW Calgary, AB, Canada T2P 3C5 I teI 403-266-9500 I gIjpc.com