6-K - CVE - Equibles

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

under the Securities Exchange Act of 1934

For October 2025

Commission File Number: 1-34513

CENOVUS ENERGY INC.

(Translation of registrant’s name into English)

4100, 225 6 Avenue S.W.

Calgary, Alberta, Canada T2P 1N2

(Address of principal executive office)

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

Form 20-F ☐ Form 40-F ☒

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

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

DOCUMENTS FILED AS PART OF THIS FORM 6-K

See the Exhibit Index to this Form 6-K.

SIGNATURES

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

Date: October 31, 2025

CENOVUS ENERGY INC.
(Registrant)
By:	/s/ Amanda D. Pankiw
---	---	---
	Name:	Amanda D. Pankiw
	Title:	Assistant Corporate Secretary

Form 6-K Exhibit Index

Exhibit No.
99.1	News Release dated October 31, 2025
99.2	Management’s Discussion and Analysis dated October 30, 2025 for the period ended September 30, 2025
99.3	Interim Consolidated Financial Statements (unaudited) for the period ended September 30, 2025
99.4	Form 52-109F2 Full Certificate, dated October 31, 2025, of Jonathan M. McKenzie, President & Chief Executive Officer
99.5	Form 52-109F2 Full Certificate, dated October 31, 2025, of Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer

Document

	Exhibit 99.1
News release

Cenovus announces third-quarter 2025 results

Calgary, Alberta (October 31, 2025) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) today announced its third-quarter 2025 financial and operating results. The company generated approximately $2.1 billion in cash from operating activities, $2.5 billion of adjusted funds flow and $1.3 billion of free funds flow. Operating results in the quarter included record Upstream production of 832,900 barrels of oil equivalent per day (BOE/d)1 and record Downstream crude throughput of 710,700 barrels per day (bbls/d), representing an overall utilization rate of 99%.

Highlights

•Highest recorded Upstream production of 832,900 BOE/d in the third quarter, including record production of approximately 642,800 BOE/d from the Oil Sands segment.

•Highest recorded U.S. Refining crude throughput of 605,300 bbls/d, representing a utilization rate of 99%, with per unit operating expenses, excluding turnarounds costs, of $9.67 per barrel, a decrease of 8% relative to the prior quarter and 24% from the third quarter of 2024.

•Substantially completed the Foster Creek optimization project, with four new steam generators brought online in the quarter, contributing to increased production rates. Commissioning of remaining facilities is underway and new well pads will be brought online in early 2026.

•The commissioning of the West White Rose project is nearing completion, with drilling expected to commence in the fourth quarter of 2025 and first oil expected in the second quarter of 2026.

•Closed the sale of Cenovus’s 50% interest in WRB Refining LP (WRB) on September 30 and received cash proceeds of $1.8 billion, net of preliminary closing adjustments, on October 1.

•Returned $1.3 billion to common shareholders, including $918 million through common share purchases, and $356 million through common share dividends.

•Subsequent to the quarter, announced an amended agreement to acquire MEG Energy Corp. (“MEG”). MEG’s shareholder vote is scheduled for November 6, 2025, and the transaction is anticipated to close in mid-November subject to shareholder and court approvals.

“We delivered record volumes in both our Upstream and Downstream businesses this quarter, while maintaining our commitment to safe, reliable and cost-effective operations,” said Jon McKenzie, Cenovus President & Chief Executive Officer. “Our major growth projects are all approaching completion and our Downstream business is reaching its potential with consistently strong operating performance this quarter.”

Financial summary

($ millions, except per share amounts)	2025 Q3	2025 Q2	2024 Q3
Cash from (used in) operating activities	2,131	2,374	2,474
Adjusted funds flow2	2,466	1,519	1,960
Per share (diluted)2	1.38	0.84	1.05
Capital investment	1,154	1,164	1,346
Free funds flow2	1,312	355	614
Excess free funds flow2	745	(306)	146
Net earnings (loss)	1,286	851	820
Per share (diluted)	0.72	0.45	0.42
Long-term debt, including current portion	7,156	7,241	7,199
Net debt	5,255	4,934	4,196

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Production and throughput

(before royalties, net to Cenovus)	2025 Q3	2025 Q2	2024 Q3
Oil and NGLs (bbls/d)1	684,700	624,000	630,500
Conventional natural gas (MMcf/d)1	889.5	851.4	844.6
Total upstream production (BOE/d)1	832,900	765,900	771,300
Total downstream crude throughput (bbls/d)1	710,700	665,800	642,900

1 See Advisory for production by product type and by operating segment.

2 Non-GAAP financial measure or contains a non-GAAP financial measure. See Advisory.

Third-quarter results

Operating1

Cenovus’s total revenues were $13.2 billion in the third quarter, up from $12.3 billion in the second quarter of 2025. Upstream revenues were $6.7 billion, a slight decrease from $6.8 billion in the previous quarter, while Downstream revenues were $8.4 billion, an increase from $7.7 billion in the second quarter.

Total operating margin3 was $3.0 billion, compared with $2.1 billion in the previous quarter. Upstream operating margin4 was $2.6 billion, an increase from $2.1 billion in the second quarter due to higher production and sales volumes, an increase in benchmark oil prices, and lower per unit operating costs. Downstream operating margin4 was $364 million, exceeding a shortfall of $71 million in the previous quarter, with favourable U.S. market crack spreads, lower per unit operating costs, and higher crude throughput following the completion of major turnaround activity in the prior quarter. Operating margin in the U.S. Refining segment was $253 million, which included a $67 million benefit from the receipt of Small Refinery Exemption (SRE) waivers related to the Superior Refinery, an $80 million inventory holding loss and $38 million of turnaround expenses.

Total Upstream production was 832,900 BOE/d in the third quarter, up from 765,900 BOE/d in the second quarter. Christina Lake production was 251,700 bbls/d compared with 217,900 bbls/d in the prior quarter, as Narrows Lake volumes began contributing and the facility benefited from flush production following a wildfire-related shutdown in the second quarter. Foster Creek production was 215,400 bbls/d, up from 186,100 bbls/d in the second quarter, as additional steam capacity from the Foster Creek optimization project supported higher production rates and a turnaround was completed in the prior quarter. Sunrise production was 52,400 bbls/d compared with 50,300 bbls/d in the second quarter, with both periods impacted by turnaround activities.

Production from the Lloydminster thermal assets was 95,700 bbls/d compared with 97,800 bbls/d in the prior quarter. The Rush Lake facilities in west-central Saskatchewan remain temporarily shut-in following a steam release from a casing failure in an injection well which took place in the second quarter of 2025. Plans are being progressed to begin a phased restart of production by the end of the year. Lloydminster conventional heavy oil output was 25,400 bbls/d, a slight increase from 25,000 bbls/d in the second quarter.

Production in the Conventional segment was 126,900 BOE/d, an increase from 119,800 BOE/d in the previous quarter due to strong performance from base and new development wells.

In the Offshore segment, production was 63,200 BOE/d compared with 66,300 BOE/d in the second quarter. In Asia Pacific, production volumes were 51,900 BOE/d, lower than the 53,800 BOE/d in the previous quarter, primarily due to maintenance activity in China. In the Atlantic region, production was 11,300 bbls/d, down from 12,500 bbls/d in the prior quarter, as production at the White Rose field was

CENOVUS ENERGY NEWS RELEASE | 2

temporarily offline to complete subsea tie-ins between the West White Rose platform and the SeaRose floating production, storage and offloading (FPSO) vessel.

Total Downstream crude throughput in the third quarter was 710,700 bbls/d, up from 665,800 bbls/d in the second quarter. Crude throughput in Canadian Refining was 105,400 bbls/d, representing a utilization rate of 98%, compared with 112,400 bbls/d in the previous quarter.

In U.S. Refining, crude throughput was 605,300 bbls/d, representing a utilization rate of 99%, compared with 553,400 bbls/d in the second quarter. U.S. Refining revenues were $7.1 billion, up from $6.5 billion in the prior quarter. Adjusted market capture5 in U.S. Refining was 65%, compared with 58% in the second quarter, driven by stronger performance at Cenovus’s operated refineries and the impact of SRE waivers received in the quarter. Excluding the impact of SRE waivers, adjusted market capture in the third quarter would have been approximately 5% lower.

3 Non-GAAP financial measure. Total operating margin is the total of Upstream operating margin plus Downstream operating margin. See Advisory.

4 Specified financial measure. See Advisory.

5 Adjusted market capture excludes the impact of inventory holding gains or losses. Contains a non-GAAP financial measure. See Advisory.

Financial

Cash from operating activities in the third quarter decreased to approximately $2.1 billion from $2.4 billion in the second quarter. Adjusted funds flow was $2.5 billion, compared with $1.5 billion in the prior quarter, and excess free funds flow (EFFF) was $745 million, compared with a shortfall of $306 million in the prior quarter. Net earnings in the third quarter increased to $1.3 billion from $851 million in the previous quarter. Third-quarter financial results reflected higher Upstream production and sales, increased Downstream utilization, stronger oil prices and market crack spreads, and lower turnaround costs relative to the second quarter.

Long-term debt, including the current portion, was $7.2 billion as at September 30, 2025. Net debt was $5.3 billion as at September 30, 2025, slightly increased from the previous quarter, as common share repurchases of $918 million exceeded EFFF of $745 million. As noted, on October 1, the company received $1.8 billion of cash proceeds from the sale of its 50% interest in WRB. The company continues to steward toward a long-term net debt target of $4.0 billion.

Growth projects

In the Oil Sands segment, Narrows Lake achieved first oil in mid-July. Three well pads were brought online in the quarter as the project continues to ramp up towards full rates. The optimization project at Foster Creek is approximately 98% complete and four steam generators brought online in July have supported higher production from the asset ahead of schedule. Commissioning of the water treating and de-oiling infrastructure is now underway and new well pads will be operating in early 2026. At Sunrise, one new well pad is being prepared for steaming in the fourth quarter, which will support continued production growth from the asset.

At West White Rose, the project’s topsides were safely lifted and set in place atop the concrete gravity structure in mid-July, and subsea tie-ins from the West White Rose platform to the SeaRose FPSO were completed in the quarter. Hookup and commissioning activities are underway, and the project is approximately 98% complete. Drilling is expected to begin by the end of the year and the project remains on schedule to produce first oil in the second quarter of 2026.

2025 guidance update

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Cenovus has revised its 2025 corporate guidance to reflect the disposition of the company’s 50% interest in WRB effective September 30. A copy of the updated guidance is available on cenovus.com under Investors.

Changes to the company’s 2025 guidance include:

•U.S. Downstream throughput of 510,000 bbls/d to 515,000 bbls/d, a decrease of 52,500 bbls/d at the midpoint.

•Downstream turnaround expenses of $360 million to $380 million have been reduced by $65 million at the midpoint.

MEG transaction update

Subsequent to the quarter, on October 27, 2025, Cenovus announced an amended agreement to acquire MEG, for a combination of cash and Cenovus common shares valued at approximately $30.00 per MEG share. On Thursday, October 30, MEG adjourned its scheduled special meeting of shareholders related to the transaction, with Cenovus’s consent, to Thursday, November 6, 2025. The adjournment will allow MEG time to respond to a regulatory inquiry related to MEG’s consideration of the amended terms of the transaction and related matters. Subject to the approval of the Court, the approval of the MEG shareholders and the satisfaction or waiver of other customary closing conditions, Cenovus expects the transaction to close in mid-November.

Sustainability

In the third quarter, Cenovus announced the expansion of its Indigenous Housing Initiative, committing up to $8 million annually in ongoing funding. Launched in 2020 with a five-year, $50 million commitment, the program has supported the construction of nearly 200 homes in six First Nation and Métis communities near the company’s oil sands operations in northeast Alberta. As the initial program closes, three new communities — Saddle Lake Cree Nation, Kikino Métis Settlement and Whitefish Lake First Nation #128 — will join the initiative in 2026. The sustained funding reflects Cenovus’s long-term commitment to advancing Indigenous reconciliation and supports efforts to address housing shortages in additional communities.

Dividend declarations and share purchases

The Board of Directors has declared a quarterly base dividend of $0.20 per common share, payable on December 31, 2025, to shareholders of record as of December 15, 2025.

In addition, the Board has declared a quarterly dividend on each of the Cumulative Redeemable First Preferred Shares – Series 1 and Series 2 – payable on December 31, 2025, to shareholders of record as of December 15, 2025, as follows:

Preferred shares dividend summary

Share series	Rate (%)	Amount ($/share)
Series 1	2.577	0.16106
Series 2	4.391	0.27669

All dividends paid on Cenovus’s common and preferred shares will be designated as “eligible dividends” for Canadian federal income tax purposes. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis.

CENOVUS ENERGY NEWS RELEASE | 4

In the third quarter, the company returned $1.3 billion to shareholders, composed of $918 million from its purchase of 40.4 million shares through its normal course issuer bid (NCIB) and $356 million through common and preferred share dividends. Subsequent to the quarter, the company purchased 17.0 million common shares through October 27, 2025 for $409 million. The current NCIB will expire on November 10, 2025. Cenovus has received approval from the Board to apply for another NCIB program. Cenovus will apply for approval to repurchase up to approximately 120 million of the company’s common shares, representing approximately 10% of its public float, as defined by the TSX.

2025 planned maintenance

The following table provides details on planned maintenance activities at Cenovus assets in 2025 and anticipated production or throughput impacts.

Potential quarterly production/throughput impact (Mbbls/d or MBOE/d)

(MBOE/d or Mbbls/d)	Q4	Annual impact
Upstream
Oil Sands	-	6 - 8
Offshore	-	1 - 2
Conventional	-	-
Downstream
Canadian Refining	-	-
U.S. Refining	8 - 12	12 - 14

Potential turnaround expenses

($ millions)	Q4	Annual impact
Downstream
Canadian Refining	-	-
U.S. Refining	10 - 15	360 - 380

Conference call today

Cenovus will host a conference call today, October 31, 2025, starting at 9 a.m. MT (11 a.m. ET).

For analysts wanting to join the call, please register in advance.

To participate in the conference call, complete the online registration form in advance of the call start time. Once registered, you will receive a unique PIN to access the call by phone. You can either dial into the conference call using the unique PIN or select the "Call Me" option to receive an automated call.

A live audio webcast of the conference call will also be available and will remain archived for approximately 30 days.

Advisory

Basis of Presentation

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Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS) Accounting Standards.

Barrels of Oil Equivalent

Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) to one barrel (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.

Product types

Product type by operating segment	Three months ended<br><br>September 30, 2025
Oil Sands
Bitumen (Mbbls/d)	615.2
Heavy crude oil (Mbbls/d)	25.4
Conventional natural gas (MMcf/d)	13.7
Total Oil Sands segment production (MBOE/d)	642.8
Conventional
Light crude oil (Mbbls/d)	5.0
Natural gas liquids (Mbbls/d)	23.0
Conventional natural gas (MMcf/d)	593.2
Total Conventional segment production (MBOE/d)	126.9
Offshore
Light crude oil (Mbbls/d)	11.3
Natural gas liquids (Mbbls/d)	4.8
Conventional natural gas (MMcf/d)	282.6
Total Offshore segment production (MBOE/d)	63.2
Total Upstream production (MBOE/d)	832.9

Forward‐looking Information

This news release contains certain forward‐looking statements and forward‐looking information (collectively referred to as “forward‐looking information”) within the meaning of applicable securities legislation about Cenovus’s current expectations, estimates and projections about the future of the company, based on certain assumptions made in light of the company’s experiences and perceptions of historical trends. Although Cenovus 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.

Forward‐looking information in this document is identified by words such as “anticipate”, “continue”, “deliver”, “expect”, “plan”, “steward”, and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: acquiring all of the issued and outstanding common shares of MEG pursuant to a plan of arrangement (the “Acquisition”), and timing thereof; expectations regarding the fully pro-rated consideration for the Acquisition; the timing of the special meeting of MEG shareholders; net debt target; growth plans and projects; maximizing value; production guidance; timing of completion of the Foster Creek optimization project; ramping up

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production at Narrows Lake; continued production growth at Sunrise; progressing a plan to restart production at Rush Lake; timing of drilling at the West White Rose project; 2025 planned maintenance; and dividend payments.

Developing forward‐looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward‐looking information in this news release are based include, but are not limited to: the satisfaction of customary closing conditions and obtaining court and MEG shareholder approvals for the Acquisition; general economic, market and business conditions; that actions by third parties do not delay or otherwise adversely affect completion of the Acquisition; that any competing bids do not materially impact the completion of the Acquisition or Cenovus’s or MEG’s business operations, approvals or key stakeholder relationships; potential litigation relating to the Acquisition that could be instituted against Cenovus or MEG; Cenovus’s portfolio and business plan, including if the Acquisition is not completed; potential adverse reactions or changes to business relationships, including with employees, suppliers, customers, competitors or credit rating agencies, resulting from the announcement or completion of the Acquisition; that there will be no material change to MEG’s operations prior to completion of the Acquisition; no material changes to laws and regulations adversely affecting Cenovus’s or MEG’s operations or the Acquisition; the interests of MEG shareholders; the allocation of free funds flow; commodity prices, inflation and supply chain constraints; Cenovus’s ability to produce on an unconstrained basis; Cenovus’s ability to access sufficient insurance coverage to pursue development plans; Cenovus’s ability to deliver safe and reliable operations and demonstrate strong governance; and the assumptions inherent in Cenovus’s updated 2025 corporate guidance available on cenovus.com.

The risk factors and uncertainties that could cause actual results to differ materially from the forward‐looking information in this news release include, but are not limited to: changes to general economic, market and business conditions; not completing the Acquisition on anticipated terms and timing, or at all, including the satisfaction of customary closing conditions and obtaining key regulatory, court and MEG shareholder approvals; a change in the current voting expectations of MEG shareholders and/or that such expectations do not prove to be accurate; a change in the interests of MEG shareholders; the accuracy of analyst predictions and calculations; failing to complete the Acquisition on the terms contemplated by the arrangement agreement between Cenovus and MEG; the impact of any competing bids or from any additional offers for MEG securities that may arise after the date hereof; potential litigation relating to the Acquisition that could be instituted against Cenovus or MEG; the consequences of not completing the Acquisition, including the volatility of the share prices of Cenovus and MEG, negative reactions from the investment community and the required payment of certain costs related to the Acquisition; the delay or inability to integrate Cenovus’s and MEG’s respective businesses and operations and realize the anticipated strategic, operational and financial benefits and synergies from the Acquisition; potential undisclosed liabilities in respect of MEG unidentified during the due diligence process; the interpretation of the Acquisition by tax authorities; the focus of management’s time and attention on the Acquisition and other disruptions arising from the Acquisition; the accuracy of estimates regarding commodity production and operating expenses, inflation, taxes, royalties, capital costs and currency and interest rates; risks inherent in the operation of Cenovus’s business; and risks associated with climate change and Cenovus’s assumptions relating thereto and other risks identified under “Risk Management and Risk Factors” and “Advisory” in Cenovus’s Management’s Discussion and Analysis (MD&A) for the year ended December 31, 2024.

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 actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward‐looking information. For additional information regarding Cenovus’s material risk factors, the assumptions made, and risks and uncertainties which could cause actual results to differ from the anticipated results, refer to “Risk

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Management and Risk Factors” and “Advisory” in Cenovus’s MD&A for the periods ended December 31, 2024 and September 30, 2025 and to the risk factors, assumptions and uncertainties described in other documents Cenovus files from time to time with securities regulatory authorities in Canada (available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and Cenovus’s website at cenovus.com).

Specified Financial Measures

This news release contains references to certain specified financial measures that do not have standardized meanings prescribed by IFRS Accounting Standards. Readers should not consider these measures in isolation or as a substitute for analysis of the company’s results as reported under IFRS Accounting Standards. These measures are defined differently by different companies and, therefore, might not be comparable to similar measures presented by other issuers. For information on the composition of these measures, as well as an explanation of how the company uses these measures, refer to the Specified Financial Measures Advisory located in Cenovus’s MD&A for the period ended September 30, 2025 (available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on Cenovus's website at cenovus.com), which is incorporated by reference into this news release.

Upstream Operating Margin and Downstream Operating Margin

Upstream Operating Margin and Downstream Operating Margin, and the individual components thereof, are included in Note 1 to the interim Consolidated Financial Statements.

Total Operating Margin

Total Operating Margin is the total of Upstream Operating Margin plus Downstream Operating Margin.

	Upstream (6)			Downstream (6)			Total
($ millions)	Q3 2025	Q2 2025	Q3 2024	Q3 2025	Q2 2025	Q3 2024	Q3 2025	Q2 2025	Q3 2024
Revenues
Gross Sales	7,562	7,394	8,259	8,435	7,743	8,798	15,997	15,137	17,057
Less: Royalties	(858)	(621)	(929)	—	—	—	(858)	(621)	(929)
	6,704	6,773	7,330	8,435	7,743	8,798	15,139	14,516	16,128
Expenses
Purchased Product	674	1,111	1,088	7,321	6,878	8,207	7,995	7,989	9,295
Transportation and Blending	2,543	2,621	2,661	—	—	—	2,543	2,621	2,661
Operating	885	896	860	751	947	918	1,636	1,843	1,778
Realized (Gain) Loss on Risk Management	12	8	(10)	(1)	(11)	(4)	11	(3)	(14)
Operating Margin	2,590	2,137	2,731	364	(71)	(323)	2,954	2,066	2,408

6Found in Note 1 of the September 30, 2025, or the June 30, 2025, interim Consolidated Financial Statements. Revenues and purchased product for the third quarter of 2024 Downstream operations were revised. See Note 23 of our September 30, 2025, interim Consolidated Financial Statements.

Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow

The following table provides a reconciliation of cash from (used in) operating activities found in Cenovus’s interim Consolidated Financial Statements to Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow. Adjusted Funds Flow per Share – Basic and Adjusted Funds Flow per Share – Diluted are calculated by dividing Adjusted Funds Flow by the respective basic or diluted weighted average number of common shares outstanding during the period and may be useful to evaluate a company’s ability to generate cash.

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	Three Months Ended
($ millions)	September 30, 2025	June 30, 2025	September 30, 2024
Cash From (Used in) Operating Activities (7)	2,131	2,374	2,474
(Add) Deduct:
Settlement of Decommissioning Liabilities	(94)	(68)	(74)
Net Change in Non-Cash Working Capital	(241)	923	588
Adjusted Funds Flow	2,466	1,519	1,960
Capital Investment	1,154	1,164	1,346
Free Funds Flow	1,312	355	614
Add (Deduct):
Base Dividends Paid on Common Shares	(356)	(364)	(329)
Purchase of Common Shares under Employee Benefit Plan	(21)	(15)	—
Dividends Paid on Preferred Shares	—	(4)	(9)
Settlement of Decommissioning Liabilities	(94)	(68)	(74)
Principal Repayment of Leases	(89)	(94)	(74)
Acquisitions, Net of Cash Acquired	(7)	(129)	(4)
Proceeds From Divestitures	—	13	22
Excess Free Funds Flow	745	(306)	146

7 Found in the September 30, 2025, or the June 30, 2025, interim Consolidated Financial Statements.

Adjusted Market Capture

Adjusted market capture contains a non-GAAP financial measure and is used in the company’s U.S. Refining segment to provide an indication of margin captured relative to what was available in the market based on widely-used benchmarks. Cenovus defines adjusted market capture as refining margin, net of holding gains and losses, 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.

The company previously disclosed market capture which did not exclude the effect of inventory holding gains or losses. Cenovus replaced market capture with adjusted market capture to exclude the impact of inventory holding gains or losses. The company believes this metric provides more comparability and accuracy when measuring the cash generating performance of our downstream operations. Comparative periods were revised to conform with our current presentation.

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($ millions)	Three months ended<br><br>September 30, 2025	Three months ended<br>June 30, 2025
Revenues (8)	7,082	6,455
Purchased Product (8)	6,219	5,838
Gross Margin	863	617
Inventory Holding (Gain) Loss	80	62
Adjusted Gross Margin	943	679
Total Processed Inputs (Mbbls/d)	642.8	594.2
Adjusted Gross Margin ($/bbl)	15.92	12.57
Operable Capacity (Mbbls/d)	612.3	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81
Group 3 3-2-1 Crack Spread Weighting	19	19
Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	24.24	21.64
Group 3 3-2-1 Crack Spread (US$/bbl)	23.72	23.07
RINs (US$/bbl)	6.33	6.12
US$ per C$1 - Average	0.726	0.723
Weighted Average Crack Spread, Net of RINs ($/bbl)	24.53	21.86
Adjusted Market Capture (percent)	0.65	0.58

8 Found in Note 1 of the September 30, 2025, or the June 30, 2025, interim Consolidated Financial Statements.

Cenovus Energy Inc.

Cenovus Energy Inc. is an integrated energy company with 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. The company is committed to maximizing value by developing its assets in a safe, responsible and cost-efficient manner, integrating environmental, social and governance considerations into its business plans. Cenovus common shares and warrants are listed on the Toronto and New York stock exchanges, and the company’s preferred shares are listed on the Toronto Stock Exchange. For more information, visit cenovus.com.

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CENOVUS ENERGY NEWS RELEASE | 10

Document

Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Periods Ended September 30, 2025

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the periods ended September 30, 2025
TABLE OF CONTENTS
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OVERVIEW OF CENOVUS	3
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QUARTERLY RESULTS OVERVIEW	4
OPERATING AND FINANCIAL RESULTS	6
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	11
OUTLOOK	15
REPORTABLE SEGMENTS	17
UPSTREAM	17
OIL SANDS	17
CONVENTIONAL	23
OFFSHORE	25
DOWNSTREAM	30
CANADIAN REFINING	30
U.S. REFINING	32
CORPORATE AND ELIMINATIONS	34
LIQUIDITY AND CAPITAL RESOURCES	35
RISK MANAGEMENT AND RISK FACTORS	40
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	40
CONTROL ENVIRONMENT	40
ADVISORY	41
ABBREVIATIONS AND DEFINITIONS	44
SPECIFIED FINANCIAL MEASURES	45
PRIOR PERIOD REVISIONS	58

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 October 30, 2025, should be read in conjunction with our September 30, 2025 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2024 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2024 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as at October 30, 2025, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (“the Board”) reviewed and recommended the MD&A for approval by the Board, which occurred on October 30, 2025. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, do not constitute part of this MD&A.

Basis of Presentation

This MD&A and the interim 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. – Q3 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 Canada and internationally. Our physically and economically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil price differentials and contribute to our net earnings by capturing value from crude oil, natural gas and NGLs production through to the sale of finished products such as transportation fuels.

Our Strategy

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

On December 12, 2024, we released our 2025 corporate guidance, which focused on disciplined capital allocation in support of increasing shareholder returns over time. We will continue to be focused on controlling costs, improving the profitability of our strategic downstream business and optimizing our advantaged portfolio to deliver value for our shareholders. Our 2025 corporate guidance was updated on July 30, 2025, and October 30, 2025, and is available on our website at cenovus.com. For further details, see the Outlook section of this MD&A.

Our Operations

The Company operates through the following reportable segments:

Upstream Segments

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

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

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

Downstream Segments

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

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	3

•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment includes the jointly-owned Wood River and Borger refineries held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. On September 30, 2025, Cenovus divested its entire 50 percent interest in WRB. 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.

QUARTERLY RESULTS OVERVIEW

In the third quarter, we achieved record production in our upstream operations and record crude oil unit throughput (“throughput”) in our downstream operations. Our financial results reflect our strong operating results, as well as an improved commodity price environment compared to the second quarter.

•Delivered safe and reliable operations. We maintained safe operations throughout our business and are continually striving to improve our safety record. Safety continues to be our top priority.

•Sale of interest in WRB. We divested our entire 50 percent interest in WRB, as announced on September 9, 2025. Proceeds of US$1.3 billion (C$1.8 billion), net of preliminary closing adjustments, were included in accounts receivable and accrued revenues as at September 30, 2025, and were received on October 1, 2025. The divestiture aligns with our strategy of owning and operating assets that are core to our business.

•Record quarterly upstream production. We achieved record quarterly upstream production of 832.9 thousand BOE per day. This included record production from our Oil Sands segment of 642.8 thousand BOE per day driven by optimization activities, the ramp-up of sustaining well pads and the ramp-up of production at Narrows Lake. Total upstream production increased from 765.9 thousand BOE per day in the second quarter of 2025, due to the return to full production at Christina Lake following the wildfire related shut-in and resuming full production at Foster Creek after completion of the turnaround in the second quarter.

•Substantially completed key Oil Sands growth projects. We have completed the Narrows Lake tie-back to Christina Lake and are now ramping up production. The optimization project at Foster Creek was approximately 98 percent complete as at September 30, 2025, with four new steam generators brought online in the quarter, supporting higher production ahead of schedule. Commissioning of the water treating and de-oiling units is underway and new well pads will be brought online in early 2026. At Sunrise, we are preparing a well pad for steaming in the fourth quarter to support continued production growth. At our Lloydminster conventional heavy oil assets, we continue to progress our heavy oil drilling program.

•Achieved Offshore milestones at the West White Rose Project. In the quarter, 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”). The remainder of the platform hookup and commissioning work is expected to be completed in the fourth quarter. We are on track to begin drilling by the end of 2025.

•Record crude throughput in our downstream assets. Average throughput in our downstream assets was 710.7 thousand barrels per day, compared with 665.8 thousand barrels per day in the second quarter of 2025. This represented a total downstream crude unit utilization of 99 percent. Our Canadian assets continue to run near capacity, while the completion of turnarounds and operational improvement initiatives in our operated U.S. assets drove higher process unit utilization and lower per-unit operating costs.

•Reported solid financial results. Adjusted Funds Flow was $2.5 billion, up from $1.5 billion in the second quarter of 2025, mainly due to higher sales volumes and lower operating expenses, driven by strong operating performance across our assets. The increases were also due in part to higher realized pricing in our oil sands assets and stronger refining margins in our U.S. Refining operations. Cash from operating activities was $2.1 billion, a decrease from $2.4 billion in the second quarter of 2025, mainly due to changes in non-cash working capital.

•Increased our returns to shareholders. We returned $1.3 billion to common shareholders, including the purchase of 40.4 million common shares for $918 million through our normal course issuer bid (“NCIB”) and $356 million through common share dividends. On October 30, 2025, our Board of Directors declared a fourth quarter dividend of $0.200 per common share.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	4

•Acquisition of MEG Energy Corp. On August 21, 2025, we entered into a definitive agreement to acquire all of the issued and outstanding common shares of MEG Energy Corp. (“MEG”) through a plan of arrangement (the “MEG Acquisition”). From October 8, 2025, to October 15, 2025, the Company acquired an aggregate of 25.0 million MEG common shares for $752 million. On October 26, 2025, Cenovus entered into a second amending agreement. The MEG Acquisition is subject to shareholder, court and other customary approvals.

Summary of Quarterly Results

	Nine Months <br>Ended <br>September 30,		2025			2024				2023
($ millions, except where indicated)	2025	2024	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Upstream Production Volumes (1) (MBOE/d)	805.9	790.9	832.9	765.9	818.9	816.0	771.3	800.8	800.9	808.6
Downstream Total Processed Inputs (2) (3) (Mbbls/d)	724.5	670.4	757.6	714.9	700.5	700.5	674.4	652.9	683.8	605.7
Crude Oil Unit Throughput (2) (Mbbls/d)	680.9	640.3	710.7	665.8	665.4	666.7	642.9	622.7	655.2	579.1
Downstream Production Volumes (1) (2) (Mbbls/d)	741.1	683.3	770.3	729.4	722.4	722.6	685.2	659.5	702.1	627.4
Revenues (4)	38,813	41,464	13,195	12,319	13,299	12,813	13,819	14,582	13,063	13,134
Operating Margin (5)	7,831	8,535	2,954	2,066	2,811	2,274	2,408	2,936	3,191	2,151
Operating Margin – Upstream (6)	7,775	8,451	2,590	2,137	3,048	2,670	2,731	3,089	2,631	2,455
Operating Margin – Downstream (6)	56	84	364	(71)	(237)	(396)	(323)	(153)	560	(304)
Cash From (Used In) Operating Activities	5,820	7,206	2,131	2,374	1,315	2,029	2,474	2,807	1,925	2,946
Adjusted Funds Flow (5)	6,197	6,563	2,466	1,519	2,212	1,601	1,960	2,361	2,242	2,062
Per Share – Basic (5) ($)	3.43	3.53	1.38	0.84	1.21	0.88	1.06	1.27	1.20	1.10
Per Share – Diluted (5) ($)	3.42	3.50	1.38	0.84	1.21	0.87	1.05	1.26	1.19	1.08
Capital Investment	3,547	3,537	1,154	1,164	1,229	1,478	1,346	1,155	1,036	1,170
Free Funds Flow (5)	2,650	3,026	1,312	355	983	123	614	1,206	1,206	892
Excess Free Funds Flow (5)	812	1,713	745	(306)	373	(416)	146	735	832	471
Net Earnings (Loss)	2,996	2,996	1,286	851	859	146	820	1,000	1,176	743
Per Share – Basic ($)	1.65	1.60	0.72	0.47	0.47	0.08	0.44	0.53	0.62	0.39
Per Share – Diluted ($)	1.65	1.59	0.72	0.45	0.47	0.07	0.42	0.53	0.62	0.32
Total Assets	53,573	54,680	53,573	55,820	56,380	56,539	54,680	56,000	54,994	53,915
Long-Term Debt, Including Current Portion	7,156	7,199	7,156	7,241	7,524	7,534	7,199	7,275	7,227	7,108
Net Debt	5,255	4,196	5,255	4,934	5,079	4,614	4,196	4,258	4,827	5,060
Cash Returns to Common and Preferred Shareholders	2,688	2,540	1,274	819	595	706	1,070	1,034	436	731
Common Shares – Base Dividends	1,047	925	356	364	327	330	329	334	262	261
Base Dividends Per Common Share ($)	0.580	0.500	0.200	0.200	0.180	0.180	0.180	0.180	0.140	0.140
Common Shares – Variable Dividends	—	251	—	—	—	—	—	251	—	—
Variable Dividends Per Common Share ($)	—	0.135	—	—	—	—	—	0.135	—	—
Purchase of Common Shares Under NCIB	1,281	1,337	918	301	62	108	732	440	165	350
Payment for Purchase of Warrants	—	—	—	—	—	—	—	—	—	111
Dividends Paid on Preferred Shares	10	27	—	4	6	18	9	9	9	9
Preferred Share Redemptions	350	—	—	150	200	250	—	—	—	—

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

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

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

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

(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. – Q3 2025 Management's Discussion and Analysis	5
OPERATING AND FINANCIAL RESULTS
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Selected Operating and Financial Results — Upstream

					Nine Months Ended September 30,
	Percent Change					Percent Change
		2024		2025			2024
Production Volumes by Segment (1) (MBOE/d)
Oil Sands	9		587.7		616.4	2		604.8
Conventional (2)	7		118.1		123.6	3		120.5
Offshore (3)	(4)		65.5		65.9	—		65.6
Total Production Volumes	8		771.3		805.9	2		790.9
Production Volumes by Product (1)
Bitumen (Mbbls/d)	8		569.6		589.9	1		585.4
Heavy Crude Oil (Mbbls/d)	56		16.3		24.1	39		17.4
Light Crude Oil (Mbbls/d)	20		13.6		16.7	27		13.2
NGLs (Mbbls/d)	(10)		31.0		29.1	(10)		32.2
Conventional Natural Gas (MMcf/d)	5		844.6		876.3	2		855.8
Total Production Volumes (MBOE/d)	8		771.3		805.9	2		790.9
Per-Unit Operating Expenses by Segment (/BOE)
Oil Sands (4)	—		11.17		12.14	6		11.50
Conventional (2) (5)	(19)		12.77		10.40	(16)		12.35
Offshore (3) (5)	7		17.97		16.86	(13)		19.36

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 by segment.

(2)For the three and nine months ended September 30, 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 interim Consolidated Financial Statements. Operating expenses for the Conventional segment, excluding our equity interests in the Duvernay joint venture, were $127 million and $369 million, respectively.

(3)Reported Offshore segment production and per-unit operating expenses include Cenovus’s 40 percent equity interest in the HCML joint venture, which is accounted for using the equity method in the interim Consolidated Financial Statements. Operating expenses for the Offshore segment, excluding our equity interests in the HCML joint venture, for the three and nine months ended September 30, 2025, were $103 million and $273 million, respectively (2024 – $92 million and $319 million, respectively).

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

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

Production

Total upstream production increased in the three and nine months ended September 30, 2025, compared with 2024, due to:

•Optimization activities and the ramp-up of well pads at our Foster Creek, Lloydminster thermal, Sunrise and Christina Lake assets.

•Strong performance from base and new development wells at our Conventional assets.

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

•The ramp-up of production at Narrows Lake.

The increases were partially offset by the temporary shut-in of production at our Rush Lake facilities as we respond to and recover from a casing failure at a steam injection well that occurred in the second quarter of 2025. Plans to safely commence and ramp-up production are expected by the end of the year.

In the third quarter of 2024, production volumes were lower due to turnaround activities at Christina Lake and in our Conventional segment.

The year-over-year increase was primarily due to the factors discussed above, partially offset by:

•Turnaround activities at Foster Creek in the second quarter of 2025 and at Sunrise in the second and third quarters of 2025.

•The temporary shut-in of production at Christina Lake in response to wildfire activity.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	6

Per-Unit Operating Expenses

For the nine months ended September 30, 2025, per-unit operating expenses increased in the Oil Sands segment compared with 2024, primarily due to higher costs in our Lloydminster thermal assets related to the incident at Rush Lake and higher turnaround costs at Foster Creek and Sunrise. 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 operating expenses as the White Rose field resumed production following the completion of the SeaRose asset life extension (“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

					Nine Months Ended September 30,
	Percent Change					Percent Change
		2024		2025			2024
Crude Oil Unit Throughput by Segment (Mbbls/d)
Canadian Refining	6		99.4		109.9	28		85.8
U.S. Refining	11		543.5		571.0	3		554.5
Total Crude Oil Unit Throughput	11		642.9		680.9	6		640.3
Production Volumes by Product (1) (Mbbls/d)
Gasoline	17		259.7		288.9	6		273.4
Distillates (2)	14		217.1		231.4	7		216.7
Synthetic Crude Oil	2		47.3		52.0	35		38.4
Asphalt	3		46.1		43.7	1		43.4
Ethanol	(4)		5.5		4.9	(4)		5.1
Other	7		109.5		120.2	13		106.3
Total Production Volumes	12		685.2		741.1	8		683.3
Per-Unit Operating Expenses by Segment (3) (/bbl)
Canadian Refining	(22)		14.63		10.96	(59)		26.65
U.S. Refining	(28)		14.37		12.89	—		12.89
Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3) (/bbl)
Canadian Refining	(7)		12.22		10.93	(34)		16.67
U.S. Refining	(24)		12.74		10.73	(9)		11.77

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 by segment.

(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, the Lloydminster Refinery and the commercial fuels business.

Total downstream throughput and refined product production increased in the three and nine months ended September 30, 2025, compared with the same periods in 2024. The increases were primarily due to our Canadian Refining assets running near, or above, full capacity and ongoing operational improvement initiatives at our operated U.S. Refining assets.

In the nine months ended September 30, 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 the major turnaround completed at the Upgrader in the second quarter of 2024.

In the nine months ended September 30, 2025, per-unit operating expenses excluding turnaround costs decreased in the U.S. Refining segment compared with 2024, primarily due to lower repairs and maintenance, and project costs, partially offset by higher electricity costs.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	7

Selected Consolidated Financial Results

Revenues

Revenues decreased five percent to $13.2 billion and decreased six percent to $38.8 billion in the three and nine months ended September 30, 2025, respectively, compared with the same periods in 2024. The decrease for both periods was primarily due to lower benchmark crude oil and refined product pricing, offset by higher sales volumes.

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.

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Gross Sales
External Sales (1)	14,053	14,748	41,198	43,999
Intersegment Sales	1,944	2,309	6,893	6,620
	15,997	17,057	48,091	50,619
Royalties	(858)	(929)	(2,385)	(2,535)
Revenues (1)	15,139	16,128	45,706	48,084
Expenses
Purchased Product (1)	7,995	9,295	24,233	25,562
Transportation and Blending	2,543	2,661	8,411	8,515
Operating Expenses	1,636	1,778	5,226	5,451
Realized (Gain) Loss on Risk Management	11	(14)	5	21
Operating Margin	2,954	2,408	7,831	8,535

(1)Comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.

Operating Margin by Segment

Three Months Ended September 30, 2025 and 2024

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

•Higher market crack spreads and higher sales volumes in our U.S. Refining segment.

•Lower operating expenses in our U.S. and Canadian refining segments.

The increases above were partially offset by a lower operating margin in our Oil Sands segment due to lower Realized Sales Prices, partially offset by higher sales volumes and a narrower condensate-WCS differential. Realized Sales Prices decreased quarter-over-quarter due to lower WTI benchmark prices, partially offset by a narrower WTI-WCS differential.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	8

Nine Months Ended September 30, 2025 and 2024

Operating Margin decreased in the nine months ended September 30, 2025, compared with 2024, primarily due to:

•Lower Realized Sales Prices impacting revenues in our Oil Sands segment, due to lower benchmark prices, as discussed above.

•The narrowing of the WTI-WCS differential impacting our U.S. Refining and Canadian Refining segments.

The decrease was partially offset by:

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

•Lower operating expenses in our Canadian Refining segment due to lower turnaround costs, as there were no significant turnarounds in 2025.

•An increase in market crack spreads impacting our U.S. Refining segment.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Cash From (Used in) Operating Activities	2,131	2,474	5,820	7,206
(Add) Deduct:
Settlement of Decommissioning Liabilities	(94)	(74)	(198)	(170)
Net Change in Non-Cash Working Capital	(241)	588	(179)	813
Adjusted Funds Flow	2,466	1,960	6,197	6,563

In the three and nine months ended September 30, 2025, cash from operating activities decreased compared with the same periods in 2024. Quarter-over-quarter, the decrease was primarily due to changes in non-cash working capital, partially offset by higher Operating Margin. Year-over-year, the decrease was due to changes in non-cash working capital and lower Operating Margin.

For the three months ended September 30, 2025, changes in non-cash working capital decreased cash from operating activities by $241 million, primarily due to changes in accounts payable and accounts receivable, excluding the impact of the divestiture of WRB.

For the nine months ended September 30, 2025, changes in non-cash working capital decreased cash from operating activities by $179 million, primarily due to changes in accounts receivable and income tax payable, partially offset by changes in inventories, excluding the impact of the divestiture of WRB.

Adjusted Funds Flow increased in the three months ended September 30, 2025, compared with 2024, primarily due to higher Operating Margin, as discussed above. Adjusted Funds Flow in the nine months ended September 30, 2025, decreased compared with 2024, due to lower Operating Margin, as discussed above, partially offset by lower long-term incentive costs.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	9

Net Earnings (Loss)

Net earnings in the three months ended September 30, 2025, were $1.3 billion, compared with $820 million in 2024, due to higher Operating Margin, as discussed above, and lower income tax expense, partially offset by foreign exchange losses in 2025, compared with gains in 2024.

In the nine months ended September 30, 2025, and 2024, net earnings were consistent at $3.0 billion as the lower Operating Margin discussed above, was offset by lower income tax expense and foreign exchange gains in 2025, compared with losses in 2024.

Net Debt

As at ($ millions)	September 30, 2025	December 31, 2024
Short-Term Borrowings	—	173
Current Portion of Long-Term Debt	—	192
Long-Term Portion of Long-Term Debt	7,156	7,342
Total Debt	7,156	7,707
Cash and Cash Equivalents	(1,901)	(3,093)
Net Debt	5,255	4,614

Total debt decreased by $551 million from December 31, 2024, primarily due to the repayment of unsecured notes during the third quarter, unrealized foreign exchange gains on long-term debt and lower short-term borrowings due to the divestiture of our 50 percent interest in WRB.

Net Debt increased by $641 million from December 31, 2024, mainly due to capital investment of $3.5 billion, common share purchases of $1.3 billion, base dividends of $1.0 billion and preferred share redemptions of $350 million, partially offset by cash from operating activities of $5.8 billion. Proceeds from the WRB divestiture were included in accounts receivable and accrued revenues as at September 30, 2025, and were received on October 1, 2025. For further details, see the Liquidity and Capital Resources section of this MD&A.

Capital Investment (1)

	Three Months Ended September 30,			Nine Months Ended September 30,
($ millions)	2025	2024		2025	2024
Upstream
Oil Sands	675		681	2,082	1,941
Conventional	107		106	302	300
Offshore	217		355	728	809
Total Upstream	999		1,142	3,112	3,050
Downstream
Canadian Refining	33		44	83	145
U.S. Refining	120		153	343	320
Total Downstream	153		197	426	465
Corporate and Eliminations	2		7	9	22
Total Capital Investment	1,154		1,346	3,547	3,537

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

For the nine months ended September 30, 2025, capital investment 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.

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Drilling Activity

	Net Stratigraphic Test Wells<br><br>and Observation Wells		Net Production Wells (1)
Nine Months Ended September 30,	2025	2024	2025	2024
Foster Creek	73	82	32	17
Christina Lake	65	58	21	16
Sunrise	21	40	10	8
Lloydminster Thermal	14	25	12	18
Lloydminster Conventional Heavy Oil	1	8	65	23
	174	213	140	82

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

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

	Nine Months Ended September 30, 2025 (1)			Nine Months Ended September 30, 2024
(net wells)	Drilled	Completed	Tied-in	Drilled	Completed	Tied-in
Conventional	35	33	28	24	24	17

(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 the first nine months of 2025 (2024 – drilled and evaluated one exploration well in China).

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined product prices and refining crack spreads, as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.

Selected Benchmark Prices and Exchange Rates (1)

	Nine Months Ended September 30,
(Average US$/bbl, unless otherwise indicated)	2025	Percent Change	2024	Q3 2025	Q2 2025	Q3 2024
Dated Brent	70.85	(14)	82.79	69.07	67.82	80.18
WTI	66.70	(14)	77.54	64.93	63.74	75.09
Differential Dated Brent – WTI	4.15	(21)	5.25	4.14	4.08	5.09
WCS at Hardisty	55.59	(10)	62.05	54.54	53.47	61.54
Differential WTI – WCS at Hardisty	11.11	(28)	15.49	10.39	10.27	13.55
WCS at Hardisty (C$/bbl)	77.79	(8)	84.45	75.11	73.96	83.95
WCS at Nederland	63.78	(10)	71.03	62.58	61.00	68.51
Differential WTI – WCS at Nederland	2.92	(55)	6.51	2.35	2.74	6.58
Condensate (C5 at Edmonton)	65.48	(11)	73.71	63.10	63.46	71.19
Differential Condensate – WTI Premium/(Discount)	(1.22)	(68)	(3.83)	(1.83)	(0.28)	(3.90)
Differential Condensate – WCS at Hardisty Premium/(Discount)	9.89	(15)	11.66	8.56	9.99	9.65
Condensate (C$/bbl)	91.66	(9)	100.28	86.91	87.77	97.10
Synthetic at Edmonton	66.68	(13)	76.38	66.26	64.72	76.41
Differential Synthetic – WTI Premium/(Discount)	(0.02)	(98)	(1.16)	1.33	0.98	1.32
Synthetic at Edmonton (C$/bbl)	93.30	(10)	103.96	91.27	89.52	104.22
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	84.19	(10)	93.62	84.87	84.61	92.29
Chicago Ultra-low Sulphur Diesel (“ULSD”)	91.27	(9)	100.21	97.78	86.91	96.55

(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.

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Selected Benchmark Prices and Exchange Rates — Continued (1)

	Nine Months Ended September 30,
(Average US$/bbl, unless otherwise indicated)	2025	Percent Change	2024	Q3 2025	Q2 2025	Q3 2024
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)	19.85	9	18.27	24.24	21.64	18.62
Group 3 3-2-1 Crack Spread (2)	21.09	16	18.19	23.72	23.07	18.95
Renewable Identification Numbers (“RINs”)	5.74	57	3.65	6.33	6.12	3.89
Upgrading Differential (3) (C$/bbl)	15.38	(21)	19.40	15.99	15.46	20.26
Natural Gas Prices
AECO (4) (C$/Mcf)	1.50	3	1.45	0.63	1.69	0.69
NYMEX (5) (US$/Mcf)	3.39	61	2.10	3.07	3.44	2.16
Foreign Exchange Rates
US$ per C$1 – Average	0.715	(3)	0.735	0.726	0.723	0.733
US$ per C$1 – End of Period	0.718	(3)	0.741	0.718	0.733	0.741
RMB per C$1 – Average	5.164	(2)	5.293	5.197	5.226	5.255

(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 the third quarter of 2025, global crude oil benchmark prices, Brent and WTI, decreased compared with the third quarter of 2024, due to uncertainty surrounding the U.S. economy, tariff policies and increasing global supply with the continued unwinding of OPEC+ production cuts. In the third quarter of 2025, Brent and WTI increased compared with the second quarter of 2025, as strong seasonal demand for crude supported prices.

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. In the nine months ended September 30, 2025, the WTI-WCS differential at Hardisty narrowed compared with 2024, due to:

•The start-up of 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.

•Declining output from Mexico and Venezuela.

•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 the nine months ended September 30, 2025, the WTI-WCS at Nederland differential narrowed compared with 2024, due to strong global demand for heavy crudes, as well as other factors 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 the nine months ended September 30, 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.

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Crude Oil Benchmark Prices (1)

(1)Forward pricing as at September 30, 2025.

Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated as diluent volumes as a percentage of total blended volumes, range from approximately 20 percent to 35 percent. The Condensate-WCS differential is an important benchmark, as a higher premium generally results in a decrease in Operating Margin when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending, as well as timing of blended product sales.

In the nine months ended September 30, 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.

In the nine months ended September 30, 2025, refined product crack spreads in Chicago and Group 3 increased compared with the same period in 2024. The increase can be largely attributed to strong third quarter product cracks as global and North American refinery outages supported refined product pricing and new refining capacity has been slow to ramp up. Crack spreads increased in the third quarter of 2025, compared with the second quarter of 2025, consistent with seasonal trends as driving season increases demand and due to refinery outages mentioned above. The average cost of RINs was higher in the nine months ended September 30, 2025, compared with the same period of 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, and 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.

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Refined Product Benchmarks (1)

(1)Forward pricing as at September 30, 2025.

Natural Gas Benchmarks

In the nine months ended September 30, 2025, AECO prices increased compared with 2024, though not as much as the increase in NYMEX pricing, as the AECO discount widened due to strong production levels and limited Western Canadian takeaway capacity. In the nine months ended September 30, 2025, NYMEX natural gas prices increased compared with 2024. This is largely a rebound from weak 2024 pricing due to oversupply and high inventories, whereas prices in 2025 have been supported by strong liquified natural gas (“LNG”) demand. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.

Foreign Exchange Benchmarks

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. dollar benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported revenue. In addition to our revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. Changes in foreign exchange rates also impact the translation of our U.S. and Asia Pacific operations.

In the three and nine months ended September 30, 2025, on average, the Canadian dollar weakened relative to the U.S. dollar compared with the same periods of 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 the three and nine months ended September 30, 2025, on average, the Canadian dollar weakened relative to RMB, compared with the same periods of 2024, positively impacting our reported revenues.

Interest Rate Benchmarks

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

As at September 30, 2025, the Bank of Canada’s policy interest rate was 2.50 percent. On October 29, 2025, the Bank of Canada reduced the policy interest rate by 25 basis points to 2.25 percent.

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OUTLOOK
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Commodity Price Outlook

Global crude oil prices have fallen in 2025 relative to 2024 and have been relatively range bound over the last two quarters. OPEC+ policy continues to remain crucial to global oil supply and demand balances, and prices. The unwinding of OPEC+ voluntary production cuts that started in May 2025 has weighed on oil prices. Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers as global crude markets remain reactionary to geopolitical headlines.

The policies around tariffs, trade relations and global geopolitical conflicts will be key considerations for energy prices. Global policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shift global trade patterns. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing geopolitical tensions between Israel and Iran, the Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-OPEC+ supply growth, and tensions between Venezuela and Guyana.

The global trade war has the potential to reduce global GDP growth and global oil demand, while increasing recessionary risks, but the actual effects have been less pronounced than expected and repeated pauses to tariffs have limited the direct economic impacts. We expect heightened price volatility across all commodities to continue until there is a firm resolution on the duration and magnitude of the tariffs. Impacts of the One Big Beautiful Bill Act in the U.S. are generally positive for the oil and gas industry in the long-term, but it is unlikely that there will be significant near-term implications. While energy products from Canada have been protected from ad valorem tariffs and are expected to remain so, the renegotiation of the Canada-United States-Mexico Agreement (“CUSMA”) may impact the supply of energy products into the United States from Canada and Mexico.

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. As expected, the start-up of TMX in 2024 is having a narrowing impact on the WTI-WCS differential.

•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 range bound. 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 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.

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While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product differentials through the following:

•Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.

•Integration – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil and spreads on refined products.

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

•Traditional crude oil storage tanks in various geographic locations.

Key Priorities for 2025

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

Top-tier Safety Performance

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

Oil Sands Business

Our Oil Sands business is the backbone of our company. Maintaining and growing our competitive advantage through our asset development and operating strategy, while operating safely and reliably, is critical to our Company.

Project Execution

Investing in future growth is a focus for us, with several key projects underway, including the West White Rose project, the optimization and sulphur recovery projects at Foster Creek, the Sunrise growth program and the Lloydminster conventional heavy oil drilling program.

We have completed the Narrows Lake tie-back to Christina Lake. We achieved first oil at Narrows Lake and we continue to ramp-up production as planned.

Downstream Competitiveness

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

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

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 targets in our sustainability focus areas and we continue to advance work to support progress against these targets.

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

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Additional information on Cenovus’s performance in safety, Indigenous reconciliation, and acceptance and belonging is available in Cenovus’s 2024 Corporate Social Responsibility report on our website at cenovus.com.

2025 Corporate Guidance

Our 2025 corporate guidance, as updated on October 30, 2025, is available on our website at cenovus.com. Updates reflect the divestiture of our 50 percent interest in WRB, which includes reductions to U.S. Refining throughput and downstream turnaround expenses.

The following table is a sub-set of our full updated guidance for 2025:

	Capital Investment<br><br>($ millions)	Production<br><br>(MBOE/d)	Crude Oil Unit Throughput<br><br>(Mbbls/d)
Upstream
Oil Sands	2,700 - 2,800	620 - 625
Conventional	350 - 400	120 - 125
Offshore	900 - 1,000	65 - 75
Upstream Total	3,950 - 4,200	805 - 825
Downstream
Canadian Refining			105 - 110
U.S. Refining			510 - 515
Downstream Total	650 - 750		615 - 625
Corporate and Eliminations	Up to 50

We continue to execute our capital program and there have been no changes to our full year capital investment range of $4.6 billion and $5.0 billion. This includes $3.2 billion directed towards sustaining capital to maintain base production and support continued safe and reliable operations, and between $1.4 billion and $1.8 billion in optimization growth capital.

REPORTABLE SEGMENTS

UPSTREAM

Oil Sands

In the third quarter of 2025, we:

•Delivered safe and reliable operations, including the safe execution of a turnaround at Sunrise.

•Achieved record production of 642.8 thousand BOE per day (2024 – 587.7 thousand BOE per day).

•Generated Operating Margin of $2.3 billion, a decrease of $174 million compared with 2024, primarily due to lower Realized Sales Prices, partially offset by higher sales volumes.

•Averaged a Netback of $39.56 per barrel (2024 – $45.16 per barrel).

•Invested capital of $675 million for sustaining activities and growth projects.

All major growth projects remain on track. We have completed the Narrows Lake tie-back to Christina Lake and are now ramping up production. The optimization project at Foster Creek was approximately 98 percent complete as at September 30, 2025, with four new steam generators brought online in the quarter, supporting higher production ahead of schedule. Commissioning of the water treating and de-oiling units is underway and new well pads will be brought online in early 2026. At Sunrise, we are preparing a well pad for steaming in the fourth quarter to support continued production growth. We continue to progress the Lloydminster conventional heavy oil drilling program.

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Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Gross Sales
External Sales	5,177	5,456	15,874	16,525
Intersegment Sales	1,571	1,719	5,241	4,831
	6,748	7,175	21,115	21,356
Royalties	(831)	(889)	(2,281)	(2,400)
Revenues	5,917	6,286	18,834	18,956
Expenses
Purchased Product	507	629	1,995	1,321
Transportation and Blending	2,452	2,579	8,138	8,265
Operating	655	621	2,032	1,896
Realized (Gain) Loss on Risk Management	10	(10)	10	23
Operating Margin	2,293	2,467	6,659	7,451
Unrealized (Gain) Loss on Risk Management	(12)	(1)	(3)	(13)
Depreciation, Depletion and Amortization	867	784	2,450	2,330
Exploration Expense	1	2	7	6
(Income) Loss from Equity-Accounted Affiliates	—	—	(38)	(14)
Segment Income (Loss)	1,437	1,682	4,243	5,142

Operating Margin Variance

Three Months Ended September 30, 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.

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Nine Months Ended September 30, 2025

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

Operating Results

		Nine Months Ended September 30,
	2024	2025	2024
Total Sales Volumes (1) (MBOE/d)	595.3	612.8	596.3
Crude Oil Production by Asset (Mbbls/d)
Foster Creek	198.0	201.4	196.3
Christina Lake	211.8	235.8	228.4
Sunrise	50.4	51.6	48.4
Lloydminster Thermal	109.4	101.1	112.3
Lloydminster Conventional Heavy Oil	16.3	24.1	17.4
Total Crude Oil Production (2) (Mbbls/d)	585.9	614.0	602.8
Natural Gas (1) (MMcf/d)	10.4	13.9	10.9
Total Production (MBOE/d)	587.7	616.4	604.8
Effective Royalty Rate (3) (percent)
Foster Creek	25.9	23.7	24.0
Christina Lake	27.7	26.4	26.2
Sunrise	7.0	6.0	6.2
Lloydminster (4)	14.3	12.1	10.9
Total Effective Royalty Rate	22.4	20.8	20.4
Netback (5) (/bbl)
Realized Sales Price	81.77	75.43	81.01
Royalties	16.26	13.66	14.68
Transportation and Blending	9.18	9.67	8.89
Operating	11.17	12.14	11.50
Total Netback (/bbl)	45.16	39.96	45.94
Per-Unit DD&A (6) (/BOE)	13.62	13.94	13.53

All values are in US Dollars.

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

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

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

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

(5)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. – Q3 2025 Management's Discussion and Analysis	19

Revenues

Gross sales decreased for the three months ended September 30, 2025, compared with 2024, due to lower Realized Sales Prices, partially offset by higher sales volumes. Gross sales were consistent for the nine months ended September 30, 2025, compared with 2024.

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 averaged $74.07 per barrel and $75.43 per barrel, respectively, in the three and nine months ended September 30, 2025, (2024 – $81.77 per barrel and $81.01 per barrel, respectively) mainly due to a lower WTI benchmark price, partially offset by a narrower WTI-WCS differential.

For the three and nine months ended September 30, 2025, approximately 36 percent and 38 percent, respectively (2024 – approximately 38 percent and 31 percent, respectively), of our sales volumes were sold at destinations outside of Alberta. Approximately 25 percent of our sales volumes were sold to our downstream operations in both the three and nine months ended September 30, 2025 (2024 – approximately 25 percent and 20 percent, respectively).

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.

Production Volumes

Oil Sands crude oil production increased in the three months ended September 30, 2025, compared with 2024, primarily due to:

•Optimization activities and the ramp-up of well pads at our Foster Creek, Lloydminster thermal, Sunrise and Christina Lake assets.

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

•The ramp-up of production at Narrows Lake.

In the third quarter of 2024, production volumes were lower due to the completion of a turnaround at Christina Lake.

The increases in the quarter were partially offset by the temporary shut-in of production at our Rush Lake facilities as we respond to and recover from a casing failure at a steam injection well that occurred in the second quarter of 2025. Plans to safely commence and ramp-up production are expected by the end of the year.

Oil Sands crude oil production increased in the nine months ended September 30, 2025, compared with 2024, due to the factors discussed above, partially offset by:

•Turnaround activities at Foster Creek in the second quarter of 2025 and turnaround activities at Sunrise in the second and third quarters of 2025.

•The temporary shut-in of production at Christina Lake in response to wildfire activity in the second quarter of 2025.

Royalties

Our Alberta oil sands royalty projects are based on government prescribed pre- and post-payout royalty rates. Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.

For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes each project's Crown and freehold split.

Refer to our 2024 annual MD&A for further details.

In the three and nine months ended September 30, 2025, Oil Sands royalties decreased compared with 2024, mainly due to lower realized pricing, partially offset by higher sales volumes. For the three months ended September 30, 2025, the Oil Sands effective royalty rate decreased, primarily due to lower Alberta sliding scale oil sands royalty rates. For the nine months ended September 30, 2025, the Oil Sands effective royalty rate increased, primarily due to annual adjustments in 2024, partially offset by lower Alberta sliding scale oil sands royalty rates.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	20

Expenses

Transportation and Blending

In the three and nine months ended September 30, 2025, blending expenses were $1.9 billion and $6.5 billion, respectively (2024 – $2.0 billion and $6.7 billion, respectively). The decrease for both periods was primarily due to lower condensate prices, partially offset by higher sales volumes.

Transportation expenses were consistent for the three months ended September 30, 2025, compared with 2024, as the increase in sales volumes was offset by a decrease in per-unit transportation expenses. Per-unit transportation expenses slightly decreased in the three months ended September 30, 2025, compared with 2024, due to lower sales volumes at U.S. and West Coast destinations. Transportation expenses and per-unit transportation expenses increased in the nine months ended September 30, 2025, 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)

	Three Months Ended September 30,		Nine Months Ended September 30,
($/bbl)	2025	2024	2025	2024
Foster Creek	13.13	12.90	15.67	12.58
Christina Lake	7.14	7.63	6.47	6.69
Sunrise	14.97	15.36	16.06	17.41
Lloydminster (2)	3.24	3.63	3.31	4.02
Total Oil Sands	9.02	9.18	9.67	8.89

(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 in the three and nine months ended September 30, 2025, compared with 2024, primarily due to higher sales to U.S. destinations. The quarter-over-quarter increase was partially offset by lower use of TMX. The year-over-year cost increase was also due to higher use of TMX, partially offset by lower rail costs. In the three and nine months ended September 30, 2025, 37 percent and 39 percent, respectively, of our sales volumes were sold at U.S. destinations (2024 – 32 percent and 35 percent, respectively). In the three and nine months ended September 30, 2025, 31 percent and 33 percent, respectively, of our sales volumes were sold at West Coast destinations (2024 – 34 percent and 15 percent, respectively).

At Christina Lake, per-unit transportation expenses decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations. In the three and nine months ended September 30, 2025, we shipped 17 percent and 16 percent, respectively, of our sales volumes to U.S. destinations (2024 – 24 percent and 19 percent, respectively).

At Sunrise, per-unit transportation expenses decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations, partially offset by higher use of TMX. In the three and nine months ended September 30, 2025, 47 percent and 57 percent, respectively, of our sales volumes were sold at West Coast destinations (2024 – 38 percent and 20 percent, respectively). In the three and nine months ended September 30, 2025, 37 percent and 34 percent, respectively, of our sales volumes were sold at U.S. destinations (2024 – 50 percent and 72 percent, respectively).

At Lloydminster, per-unit transportation expenses decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations. In the three and nine months ended September 30, 2025, we shipped less than one percent and two percent, respectively, of our sales volumes to U.S. destinations (2024 – one percent and four percent, respectively).

Operating

Primary drivers of our operating expenses in the first nine months of 2025 were fuel, repairs and maintenance, and workforce. Total operating expenses increased in the three and nine months ended September 30, 2025, compared with the same periods in 2024, primarily due to higher costs at our Lloydminster thermal assets related to the incident at Rush Lake and higher turnaround costs at Sunrise. Year-over-year also increased due to higher turnaround costs at Foster Creek.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	21

Per-Unit Operating Expenses (1)

	Three Months Ended September 30,			Nine Months Ended September 30,
($/bbl)	2025	Percent <br>Change	2024	2025	Percent <br>Change	2024
Foster Creek
Fuel	1.41	(7)	1.52	2.21	(1)	2.24
Non-Fuel	7.16	(4)	7.49	7.93	3	7.72
Total	8.57	(5)	9.01	10.14	2	9.96
Christina Lake
Fuel	1.37	(3)	1.41	2.03	(1)	2.05
Non-Fuel	5.24	(34)	7.92	5.94	(12)	6.72
Total	6.61	(29)	9.33	7.97	(9)	8.77
Sunrise
Fuel	2.50	38	1.81	3.76	27	2.95
Non-Fuel	14.95	34	11.16	14.63	30	11.24
Total	17.45	35	12.97	18.39	30	14.19
Lloydminster (2)
Fuel	1.79	3	1.74	2.88	6	2.71
Non-Fuel	20.78	37	15.17	17.81	20	14.88
Total	22.57	33	16.91	20.69	18	17.59
Total Oil Sands
Fuel	1.56	1	1.55	2.41	4	2.32
Non-Fuel	9.65	—	9.62	9.73	6	9.18
Total	11.21	—	11.17	12.14	6	11.50

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

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

In the three months ended September 30, 2025, per-unit fuel expenses were relatively consistent compared with 2024, due to increased consumption volumes from well pads coming online at our Sunrise assets and lower sales volumes as a result of the incident at Rush Lake, offset by lower AECO benchmark pricing. In the nine months ended September 30, 2025, per-unit fuel expenses increased compared with 2024, due to increased consumption volumes and lower sales volumes, as discussed above, and higher AECO benchmark pricing.

Foster Creek per-unit non-fuel costs decreased in the three months ended September 30, 2025, compared with 2024, primarily due to higher sales volumes. Per-unit non-fuel costs increased in the nine months ended September 30, 2025, compared with 2024, primarily due turnaround activities in the second quarter of 2025, partially offset by higher sales volumes.

Christina Lake per-unit non-fuel costs decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower turnaround expenses and higher sales volumes.

Sunrise per-unit non-fuel costs increased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to turnaround activities in the second and third quarters of 2025.

Lloydminster per-unit non-fuel costs increased in the three and nine months ended September 30, 2025, compared with 2024, due to higher costs and lower sales volumes related to the Rush Lake incident.

MEG Acquisition and Asset Disposition

On August 21, 2025, we entered into a definitive agreement to acquire all of the issued and outstanding common shares of MEG through a plan of arrangement. On October 26, 2025, we entered into a second amending agreement. The MEG Acquisition is subject to shareholder, court and other customary approvals. The MEG Acquisition will expand our Christina Lake assets and is expected to add approximately 110.0 thousand barrels per day of production.

On October 26, 2025, we entered into an agreement to dispose of certain Lloydminster thermal assets in our Oil Sands segment, representing approximately 5.0 thousand barrels per day of production, for total proceeds of up to $150 million, including $75 million in cash paid on closing and up to $75 million in variable consideration. The disposition is expected to close in the fourth quarter of 2025, subject to closing conditions.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	22

Conventional

In the third quarter of 2025, we:

•Delivered safe and reliable operations.

•Produced 126.9 thousand BOE per day (2024 – 118.1 thousand BOE per day).

•Generated Operating Margin of $41 million, an increase of $29 million from 2024.

•Earned a Netback of $3.85 per BOE (2024 – $1.12 per BOE), primarily due to lower operating expenses.

•Invested capital of $107 million, primarily related to drilling, completion, tie-in and infrastructure projects.

Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Gross Sales
External Sales	212	225	936	866
Intersegment Sales	217	488	986	1,417
	429	713	1,922	2,283
Royalties	(12)	(15)	(44)	(61)
Revenues	417	698	1,878	2,222
Expenses
Purchased Product	161	459	951	1,353
Transportation and Blending	86	80	259	241
Operating	127	147	369	432
Realized (Gain) Loss on Risk Management	2	—	1	(7)
Operating Margin	41	12	298	203
Unrealized (Gain) Loss on Risk Management	(6)	2	(7)	10
Depreciation, Depletion and Amortization	125	109	362	330
(Income) Loss From Equity-Accounted Affiliates	—	—	1	1
Segment Income (Loss)	(78)	(99)	(58)	(138)

Operating Margin Variance

Three Months Ended September 30, 2025

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

(2)Reflects Operating Margin from processing facilities.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	23

Nine Months Ended September 30, 2025

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

(2)Reflects Operating Margin from processing facilities.

Operating Results

		Nine Months Ended September 30,
	2024	2025	2024
Total Sales Volumes (1) (MBOE/d)	118.1	123.6	120.5
Realized Sales Price (1) (2) (/BOE)
Light Crude Oil (/bbl)	93.68	81.69	93.18
NGLs (/bbl)	53.77	52.30	55.84
Conventional Natural Gas (/Mcf)	1.53	2.95	2.43
Production by Product (1)
Light Crude Oil (Mbbls/d)	4.6	4.9	5.0
NGLs (Mbbls/d)	21.1	21.3	21.5
Conventional Natural Gas (MMcf/d)	554.8	583.9	564.8
Total Production (MBOE/d)	118.1	123.6	120.5
Conventional Natural Gas Production (percentage of total)	78	79	78
Crude Oil and NGLs Production (percentage of total)	22	21	22
Effective Royalty Rate (1) (3) (percent)	10.7	8.6	10.9
Netback (1) (2) (/BOE)
Realized Sales Price	20.42	26.23	25.18
Royalties	1.38	1.35	1.86
Transportation and Blending	5.15	5.41	5.03
Operating	12.77	10.40	12.35
Total Netback (/BOE)	1.12	9.07	5.94
Per-Unit DD&A (4) (/BOE)	9.97	10.35	9.89

All values are in US Dollars.

(1)For the three and nine months ended September 30, 2025, reported production volumes, sales volumes, associated per-unit values and effective royalty rates reflect 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.

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

Revenues

Gross sales decreased in the three and nine months ended September 30, 2025, compared with 2024, due to lower commodity trading volumes sourced from third parties, partially offset by higher sales volumes and higher realized pricing.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	24

Price

Our total Realized Sales Price increased for the three and nine months ended September 30, 2025, compared with 2024, primarily due to higher sales volumes to U.S. destinations. For the three and nine months ended September 30, 2025, 34 percent and 31 percent, respectively, of our natural gas sales volumes were sold at U.S. destinations (2024 – 29 percent for both periods), where NYMEX natural gas benchmark prices were higher. For the three and nine months ended September 30, 2025, NYMEX natural gas benchmark prices were US$3.07 per Mcf and US$3.39 per Mcf, respectively (2024 – US$2.16 per Mcf and US$2.10 per Mcf, respectively). The quarter-over-quarter increase was partially offset by AECO natural gas benchmark prices decreasing to $0.63 per Mcf (2024 – $0.69 per Mcf). The year-over-year increase was also due to AECO natural gas benchmark prices increasing to $1.50 per Mcf (2024 – $1.45 per Mcf).

Production Volumes

For the three and nine months ended September 30, 2025, production volumes increased compared with 2024, primarily due to strong performance from base and new development wells. In the third quarter of 2024, production volumes were lower due to turnaround activities in the period.

Royalties

Royalties and the effective royalty rate decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower natural gas 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 the three and nine months ended September 30, 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, due to increased pipeline transportation rates.

Operating

Primary drivers of operating expenses in the first nine months of 2025 were repairs and maintenance, workforce and property tax costs. Total operating expenses and per-unit operating expenses decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower turnaround costs, and processing and gathering costs.

Offshore

In the third quarter of 2025, we:

•Delivered safe and reliable operations.

•Produced 63.2 thousand BOE per day of light crude oil, NGLs and natural gas (2024 – 65.5 thousand BOE per day).

•Generated Operating Margin of $256 million, an increase of $4 million from 2024.

•Averaged a Netback of $48.59 per BOE (2024 – $53.20 per BOE).

•Invested capital of $217 million mainly related to the progression of the West White Rose project.

In the quarter, 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. The remainder of the platform hookup and commissioning work is expected to be completed in the fourth quarter. As at September 30, 2025, the project was approximately 98 percent complete. We are on track to begin drilling by the end of 2025 and deliver first oil in the second quarter of 2026. Since our decision in 2022 to restart the project, we have invested approximately $2.2 billion.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	25

Financial Results

	Three Months Ended September 30,
	2025			2024
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	140	245	385	71	300	371
Intersegment Sales	—	—	—	—	—	—
	140	245	385	71	300	371
Royalties	(2)	(13)	(15)	(1)	(24)	(25)
Revenues	138	232	370	70	276	346
Expenses
Purchased Product	6	—	6	—	—	—
Transportation and Blending	5	—	5	2	—	2
Operating	75	28	103	58	34	92
Operating Margin (1)	52	204	256	10	242	252
Depreciation, Depletion and Amortization			106			134
Exploration Expense			—			42
(Income) Loss from Equity-Accounted Affiliates			(9)			(11)
Segment Income (Loss)			159			87	Nine Months Ended September 30,
---	---	---	---	---	---	---
	2025			2024
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	358	813	1,171	264	935	1,199
Intersegment Sales	—	—	—	—	—	—
	358	813	1,171	264	935	1,199
Royalties	(4)	(56)	(60)	(2)	(72)	(74)
Revenues	354	757	1,111	262	863	1,125
Expenses
Purchased Product	6	—	6	—	—	—
Transportation and Blending	14	—	14	9	—	9
Operating	187	86	273	225	94	319
Operating Margin (1)	147	671	818	28	769	797
Depreciation, Depletion and Amortization			329			421
Exploration Expense			2			50
(Income) Loss from Equity-Accounted Affiliates			(24)			(34)
Segment Income (Loss)			511			360

(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. – Q3 2025 Management's Discussion and Analysis	26

Operating Margin Variance

Three Months Ended September 30, 2025

Nine Months Ended September 30, 2025

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

Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
Sales Volumes
Atlantic (Mbbls/d)	13.6	7.2	12.4	8.6
Asia Pacific (MBOE/d)
China	35.2	40.5	38.1	42.6
Indonesia (1)	16.7	16.0	16.0	14.8
Total Asia Pacific	51.9	56.5	54.1	57.4
Total Sales Volumes (MBOE/d)	65.5	63.7	66.5	66.0

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

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	27

Operating Results — Continued

	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
Production by Product
Atlantic – Light Crude Oil (Mbbls/d)	11.3	9.0	11.8	8.2
Asia Pacific (1)
NGLs (Mbbls/d)	4.8	9.9	7.8	10.7
Conventional Natural Gas (MMcf/d)	282.6	279.4	278.5	280.1
Total Asia Pacific (MBOE/d)	51.9	56.5	54.1	57.4
Total Production (MBOE/d)	63.2	65.5	65.9	65.6
Effective Royalty Rate (2) (percent)
Atlantic	1.0	1.0	1.0	0.6
Asia Pacific (1)	10.4	8.7	11.7	8.6
Per-Unit DD&A (3) ($/BOE)	15.95	22.16	17.06	22.51

(1)Reported 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.

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

Netbacks (1)

	Three Months Ended September 30, 2025
($/BOE, except where indicated)	Atlantic (/bbl)	China	Indonesia		Total Offshore (2)
Realized Sales Price		75.41		55.57		74.50
Royalties		4.03		13.77		5.87
Transportation and Blending		—		—		0.85
Operating Expenses		8.26		8.89		19.19
Netback		63.12		32.91		48.59

All values are in US Dollars.

	Three Months Ended September 30, 2024
($/BOE, except where indicated)	Atlantic (/bbl)	China	Indonesia		Total Offshore (2)
Realized Sales Price		80.52		55.93		77.28
Royalties		6.31		6.54		5.77
Transportation and Blending		—		—		0.34
Operating Expenses		8.20		10.95		17.97
Netback		66.01		38.44		53.20

All values are in US Dollars.

	Nine Months Ended September 30, 2025
($/BOE, except where indicated)	Atlantic (/bbl)	China	Indonesia		Total Offshore (2)
Realized Sales Price		77.79		59.59		77.46
Royalties		5.40		15.85		7.08
Transportation and Blending		—		—		0.78
Operating Expenses		7.59		10.01		16.86
Netback		64.80		33.73		52.74

All values are in US Dollars.

	Nine Months Ended September 30, 2024
($/BOE, except where indicated)	Atlantic (/bbl)	China	Indonesia		Total Offshore (2)
Realized Sales Price		80.22		56.47		78.95
Royalties		6.17		6.94		5.62
Transportation and Blending		—		—		0.48
Operating Expenses		7.22		10.83		19.36
Netback		66.83		38.70		53.49

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.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	28

Revenues

For the three months ended September 30, 2025, gross sales increased compared with 2024, due to higher Atlantic sales volumes, partially offset by lower Realized Sales Prices. For the nine months ended September 30, 2025, gross sales decreased slightly compared with 2024, primarily due to lower Realized Sales Prices.

Price

Our Atlantic Realized Sales Price decreased in the three and nine months ended September 30, 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

Atlantic production increased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to the ramp-up of production at the White Rose field early in the second quarter of 2025. Atlantic production was lower in the same periods in 2024, as production at the White Rose field was suspended in late December 2023 in preparation for the SeaRose ALE project. Operations resumed and production restarted safely in the first quarter of 2025. The quarter-over-quarter increase was partially offset by decreased production at the Terra Nova field and turnaround activities at SeaRose while we completed subsea tie-ins. 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.

Asia Pacific production decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower contracted sales volumes in China, partially offset by increased production in Indonesia due to higher buyer nominations. The quarter-over-quarter decrease was also due to maintenance activities in China.

Royalties

For the three months ended September 30, 2025, the Atlantic effective royalty rate was consistent compared with 2024. For the nine months ended September 30, 2025, the Atlantic effective royalty rate increased compared with 2024, primarily due to a credit received in the second quarter of 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 three and nine months ended September 30, 2025, increased to $5 million and $14 million, respectively (2024 – $2 million and $9 million, respectively), primarily due to higher sales volumes.

Operating

Primary drivers of our Atlantic operating expenses in the first nine months of 2025 were repairs and maintenance, costs related to vessels and air services, and workforce. In the three months ended September 30, 2025, operating expenses increased compared with 2024, primarily due to higher sales volumes. In the nine months ended September 30, 2025, operating expenses decreased compared with 2024, 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. In the three and nine months ended September 30, 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 above.

Primary drivers of our China operating expenses in the first nine months of 2025 were repairs and maintenance, workforce and insurance costs. Per-unit operating expenses increased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower sales volumes, partially offset by lower insurance costs. The quarter-over-quarter increase was also partially offset by lower repairs and maintenance costs.

Primary drivers of our Indonesia operating expenses in the first nine months of 2025 were repairs and maintenance, and workforce costs. Indonesia per-unit operating expenses decreased in the three and nine months ended September 30, 2025, compared with 2024, due to higher sales volumes. The quarter-over-quarter decrease was also due to lower repairs and maintenance costs. The year-over-year decrease was partially offset by higher repairs and maintenance costs.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	29

DOWNSTREAM

Canadian Refining

In the third quarter of 2025, we:

•Delivered safe and reliable operations.

•Achieved crude oil throughput of 105.4 thousand barrels per day and crude unit utilization of 98 percent (2024 – 99.4 thousand barrels per day and 92 percent, respectively).

•Incurred per-unit operating expenses excluding turnaround costs of $11.38 per barrel (2024 – $12.22 per barrel).

•Recorded Operating Margin of $111 million, an increase of $51 million from the third quarter of 2024. The increase was primarily due to lower operating costs and lower feedstock costs due to lower benchmark crude pricing, partially offset by lower refined product pricing and the narrowing of the WCS-WTI differential.

•Invested capital of $33 million, primarily focused on sustaining activities.

Financial and Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Revenues	1,353	1,580	3,923	4,047
Purchased Product	1,102	1,353	3,218	3,415
Gross Margin (1)	251	227	705	632
Expenses
Operating	140	167	419	759
Operating Margin	111	60	286	(127)
Depreciation, Depletion and Amortization	40	49	139	147
Segment Income (Loss)	71	11	147	(274)

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

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions, except where indicated)	2025	2024	2025	2024
Gross Margin	251	227	705	632
Add (Deduct):
Inventory Holding (Gain) Loss (1)	8	16	(1)	(2)
Adjusted Gross Margin (2)	259	243	704	630
Adjusted Refining Margin (3) ($/bbl)	21.76	22.17	19.56	22.27

(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 three and nine months ended September 30, 2025, were $1.3 billion and $3.7 billion, respectively (2024 – $1.5 billion and $3.8 billion, respectively).

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.

Sales from the Lloydminster Refinery are seasonal and increase during paving season, which typically runs from May through October each year.

Revenues decreased in the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower refined product pricing.

Adjusted Gross Margin increased in the three and nine months ended September 30, 2025, compared with the same periods in 2024, primarily due to lower feedstock costs as a result of lower benchmark crude pricing, partially offset by lower refined product pricing and the narrowing of the WTI-WCS differential.

Adjusted Refining Margin decreased in the three and nine months ended September 30, 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. – Q3 2025 Management's Discussion and Analysis	30
	Three Months Ended September 30,		Nine Months Ended September 30,
---	---	---	---	---
(Mbbls/d, except where indicated)	2025	2024	2025	2024
Operable Capacity	108.0	108.0	108.0	108.0
Total Processed Inputs	114.8	106.4	118.3	91.4
Crude Oil Unit Throughput	105.4	99.4	109.9	85.8
Crude Unit Utilization (percent)	98	92	102	79
Total Production	122.3	113.6	126.0	98.0
Synthetic Crude Oil	48.3	47.3	52.0	38.4
Asphalt	19.5	16.5	17.6	15.4
Diesel	14.2	11.8	14.9	10.0
Other	35.0	32.5	36.6	29.1
Ethanol	5.3	5.5	4.9	5.1

The Upgrader and Lloydminster Refinery source their crude oil feedstock from our Oil Sands segment. In the three and nine months ended September 30, 2025, 14 percent and 15 percent, respectively, of our Oil Sands segment’s sales volumes were purchased by our Canadian Refining segment (2024 – 14 percent and 11 percent, respectively).

Throughput and total production increased in the three and nine months ended September 30, 2025, compared with 2024. In 2025, our assets ran near, or above full capacity due to ongoing improvement initiatives and high asset reliability. In the second quarter of 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.

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions, except where indicated)	2025	2024	2025	2024
Operating Expenses – Upgrading and Refining	120	143	354	667
Operating Expenses – Excluding Turnaround Costs	120	119	353	417
Operating Expenses – Turnaround Costs	—	24	1	250
Per-Unit Operating Expenses (1) ($/bbl)	11.38	14.63	10.96	26.65
Per-Unit Operating Expenses – Excluding Turnaround Costs	11.38	12.22	10.93	16.67
Per-Unit Operating Expenses – Turnaround Costs	—	2.41	0.03	9.98

(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 the three and nine months ended September 30, 2025, operating expenses decreased compared with the same periods in 2024, mainly due to lower turnaround costs and other project costs. Turnaround costs and other project costs were higher in the same periods in 2024, due to the turnaround completed at the Upgrader.

Operating expenses excluding turnaround costs were relatively consistent in the three months ended September 30, 2025, compared with 2024. Operating expenses excluding turnaround costs decreased in the nine months ended September 30, 2025, compared with 2024, due to lower project costs.

In the three and nine months ended September 30, 2025, the decrease in operating expenses, combined with increased total processed inputs, resulted in decreased per-unit operating metrics compared with 2024.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	31

U.S. Refining

In the third quarter of 2025, we:

•Delivered safe and reliable operations.

•Achieved record throughput of 605.3 thousand barrels per day compared with 543.5 thousand barrels per day in the third quarter of 2024, and crude unit utilization of 99 percent (2024 – 89 percent).

•Decreased per-unit operating expenses excluding turnaround costs to $9.67 per barrel (2024 – $12.74 per barrel).

•Recorded Operating Margin of $253 million, an increase of $636 million from the third quarter of 2024, primarily due to higher market crack spreads, lower operating expenses, increased sales volumes and the receipt of Small Refinery Exemption (“SRE”) waivers.

•Invested capital of $120 million, primarily focused on reliability and sustaining activities.

•Divested our 50 percent interest in WRB.

Financial and Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Revenues (1)	7,082	7,218	19,960	21,734
Purchased Product (1)	6,219	6,854	18,063	19,473
Gross Margin (2)	863	364	1,897	2,261
Expenses
Operating	611	751	2,133	2,045
Realized (Gain) Loss on Risk Management	(1)	(4)	(6)	5
Operating Margin	253	(383)	(230)	211
Unrealized (Gain) Loss on Risk Management	3	5	(5)	3
Depreciation, Depletion and Amortization	160	115	467	338
Segment Income (Loss)	90	(503)	(692)	(130)

(1)Comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions, except where indicated)	2025	2024	2025	2024
Gross Margin	863	364	1,897	2,261
Add (Deduct):
Inventory Holding (Gain) Loss (1)	80	209	165	(68)
Adjusted Gross Margin (2)	943	573	2,062	2,193
Adjusted Refining Margin (2) ($/bbl)	15.92	10.97	12.45	13.82
Adjusted Market Capture (2) (percent)	65	54	62	70

(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 the three and nine months ended September 30, 2025, compared with 2024, primarily due to lower refined product pricing, partially offset by higher sales volumes in the three months ended September 30, 2025.

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 the three months ended September 30, 2025, the Chicago 3-2-1 crack spread increased 30 percent and the Group 3 3-2-1 crack spread increased 25 percent compared with 2024. The increase in crack spreads was partially offset by an increase in the average cost of RINs of 63 percent. Quarter-over-quarter, Adjusted Gross Margin increased due to the increase in the weighted average crack spread, net of RINs, higher sales volumes and the receipt of SRE waivers.

In the nine months ended September 30, 2025, the Chicago 3-2-1 crack spread increased nine percent and the Group 3 3-2-1 crack spread increased 16 percent compared with 2024. The increase in crack spreads were largely offset by an increase in the average cost of RINs of 57 percent, which contributed to a slight increase in weighted average crack spreads, net of RINs. Year-over-year, Adjusted Gross Margin decreased due to the narrowing of the WTI-WCS differential impacting our feedstock costs, partially offset by a slight increase in the weighted average crack spreads, net of RINs.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	32

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 the three months ended September 30, 2025, compared with the same period in 2024, due to the increase in Adjusted Gross Margin and improved process unit utilization at our operated refineries.

Adjusted Refining Margin and Adjusted Market Capture decreased in the nine months ended September 30, 2025, compared with the same period in 2024, due to the decrease in Adjusted Gross Margin and higher total processed inputs. While the turnaround at the Toledo Refinery, completed during the second quarter of 2025 impacted the Adjusted Refining Margin and Adjusted Market Capture, this was offset by ongoing operational improvements in our operated U.S. Refining business.

	Three Months Ended September 30,		Nine Months Ended September 30,
(Mbbls/d, except where indicated)	2025	2024	2025	2024
Operable Capacity	612.3	612.3	612.3	612.3
Total Processed Inputs	642.8	568.0	606.2	579.0
Crude Oil Unit Throughput	605.3	543.5	571.0	554.5
Heavy Crude Oil	224.7	215.7	221.7	219.9
Light/Medium Crude Oil	380.6	327.8	349.3	334.6
Crude Unit Utilization (percent)	99	89	93	91
Total Refined Product Production	648.0	571.6	615.1	585.3
Gasoline	304.7	259.7	288.9	273.4
Distillates (1)	233.4	205.3	216.5	206.7
Asphalt	28.2	29.6	26.1	28.0
Other	81.7	77.0	83.6	77.2

(1)Includes diesel and jet fuel.

Throughput and refined product production increased in the three and nine months ended September 30, 2025, compared with the same periods in 2024. The increase was primarily due to improved process unit utilization across our operated refineries driven by ongoing operational improvements made to the U.S. Refining business. In the three and nine months ended September 30, 2024, throughput and refined product production were lower, and operating expenses were higher due to the turnaround at the Lima Refinery, which was completed in October 2024.

Operating Expenses

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions, except where indicated)	2025	2024	2025	2024
Operating Expenses	611	751	2,133	2,045
Operating Expenses – Excluding Turnaround Costs	573	666	1,776	1,868
Operating Expenses – Turnaround Costs	38	85	357	177
Per-Unit Operating Expenses (1) ($/bbl)	10.32	14.37	12.89	12.89
Per-Unit Operating Expenses – Excluding Turnaround Costs	9.67	12.74	10.73	11.77
Per-Unit Operating Expenses – Turnaround Costs	0.65	1.63	2.16	1.12

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

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

In the three months ended September 30, 2025, operating expenses decreased due to a decrease in turnaround costs, repairs and maintenance, and project costs, compared with 2024. In the third quarter of 2024, the Lima Refinery turnaround commenced, as discussed above.

In the nine months ended September 30, 2025, operating expenses increased compared with 2024. This was mainly due to the turnaround costs recognized in the first half of the year at the Toledo Refinery and the non-operated Wood River and Borger refineries, partially offset by lower repairs and maintenance, and project costs.

Operating expenses excluding turnaround costs and related per-unit metrics for the three and nine months ended September 30, 2025, decreased compared with 2024, primarily 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 decrease in operating expenses was partially offset by higher electricity costs and foreign exchange impacts from a slight weakening of the Canadian dollar, on average, relative to the U.S. dollar.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	33

CORPORATE AND ELIMINATIONS

Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Realized (Gain) Loss on Risk Management	6	(13)	(19)	(10)
Unrealized (Gain) Loss on Risk Management	(4)	1	(50)	31
General and Administrative	220	172	570	593
Finance Costs, Net	154	118	404	394
Integration, Transaction and Other Costs	44	41	123	113
Foreign Exchange (Gain) Loss, Net	157	(73)	(196)	81
(Gain) Loss on Divestiture of Assets	(106)	(17)	(109)	(121)
Other (Income) Loss, Net	(22)	(28)	(54)	(158)

General and Administrative

Primary drivers of our general and administrative expenses for the three and nine months ended September 30, 2025, were workforce and information technology related costs. For the three months ended September 30, 2025, general and administrative costs increased compared with 2024, due to higher long-term incentive costs. For the nine months ended September 30, 2025, general and administrative costs decreased compared with 2024, due to general cost saving initiatives.

Finance Costs, Net

Net finance costs were higher in the three months ended September 30, 2025, compared with the same period in 2024, due to lower interest income. Net finance costs slightly increased in the nine months ended September 30, 2025, compared with the same period in 2024. 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 the three and nine months ended September 30, 2025, was 4.52 percent and 4.53 percent, respectively (2024 – 4.54 and 4.50 percent, respectively).

Foreign Exchange (Gain) Loss, Net

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Unrealized Foreign Exchange (Gain) Loss	153	(108)	(248)	101
Realized Foreign Exchange (Gain) Loss	4	35	52	(20)
	157	(73)	(196)	81

For the three and nine months ended September 30, 2025, unrealized foreign exchange losses and gains were primarily due to the translation of U.S. denominated debt. Realized foreign exchange losses were primarily related to working capital. As at September 30, 2025, the Canadian dollar weakened relative to the U.S. dollar as at June 30, 2025, and strengthened relative to the U.S. dollar as at December 31, 2024. As at September 30, 2024, the Canadian dollar strengthened relative to the U.S. dollar as at June 30, 2024, and weakened relative to the U.S. dollar as at December 31, 2023.

(Gain) Loss on Divestiture of Assets

In the three months ended September 30, 2025, the Company recorded a before-tax gain of $106 million related to the divestiture of our 50 percent interest in WRB.

In the three and nine months ended September 30, 2024, we recorded gains on the divestiture of assets related to Duvernay, and the sale of non-core assets in our Conventional segment.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	34

Income Taxes

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Current Tax
Canada	288	184	791	830
United States	—	—	—	2
Asia Pacific	42	57	144	157
Other International	8	9	32	26
Total Current Tax Expense (Recovery)	338	250	967	1,015
Deferred Tax Expense (Recovery)	(327)	(46)	(520)	(124)
	11	204	447	891

For the nine months ended September 30, 2025, the Company recorded a deferred tax recovery, of which $315 million related to the divestiture of our 50 percent interest in WRB.

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.

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.

		Nine Months Ended September 30,
( millions)	2024	2025	2024
Cash From (Used In)
Operating Activities	2,474	5,820	7,206
Investing Activities	(1,308)	(4,039)	(3,613)
Net Cash Provided (Used) Before Financing Activities	1,166	1,781	3,593
Financing Activities	(1,175)	(2,891)	(2,764)
Effect of Foreign Exchange on Cash and Cash Equivalents	(41)	(82)	48
Increase (Decrease) in Cash and Cash Equivalents	(50)	(1,192)	877
		September 30,	December 31,
As at ( millions)		2025	2024
Cash and Cash Equivalents		1,901	3,093
Total Debt		7,156	7,707

All values are in US Dollars.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	35

Cash From (Used in) Operating Activities

Cash From (Used in) Investing Activities

Cash used in investing activities was relatively consistent in the three months ended September 30, 2025, and increased in the first nine months of 2025, compared with 2024. Cash used in investing activities primarily relates to capital investment.

Cash From (Used in) Financing Activities

Cash used in financing activities increased in the three and nine months ended September 30, 2025, compared with the same periods in 2024.

Quarter-over-quarter, the increase was primarily due to purchases under the Company’s NCIB program and repayment of its 5.38 percent unsecured notes with a principal of US$133 million.

In the nine months ended September 30, 2025, compared with 2024, increases were primarily due to payment for redemption of preferred shares and repayment of long-term debt, partially offset by lower dividends paid due to a variable dividend that was paid in the second quarter of 2024 that did not reoccur in 2025.

Working Capital

Working capital as at September 30, 2025, was $4.1 billion (December 31, 2024 – $3.1 billion). The increase was primarily driven by higher accounts receivable related to proceeds from the divestiture of WRB, partially offset by lower inventories. Proceeds from the divestiture of WRB were received on October 1, 2025.

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.

Over time, we plan to return 100 percent of Excess Free Funds Flow to shareholders, 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.

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Excess Free Funds Flow (1)	745	146	812	1,713
Target Return (2)	745	146	812	930
Shareholder Returns by way of:
Purchase of Common Shares Under NCIB	918	732	1,281	1,337
Variable Dividends Paid	—	—	—	251
Preferred Share Redemption	—	—	350	—
Total	918	732	1,631	1,588

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

(2)The target return for the three and nine months ended September 30, 2025, was 100 percent of Excess Free Funds Flow. The target return for the nine months ended September 30, 2024, includes 100 percent of Excess Free Funds Flow in the third quarter of 2024, and 50 percent of Excess Free Funds Flow in the first and second quarters of 2024.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	36

Short-Term Borrowings

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). 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

Long-term debt, including the current portion, as at September 30, 2025, was $7.2 billion (December 31, 2024 – $7.5 billion). We hold U.S. dollar denominated unsecured notes of US$3.7 billion (C$5.1 billion) (December 31, 2024 – US$3.8 billion (C$5.5 billion)) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2024 – $2.0 billion).

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

As at September 30, 2025, we were in compliance with all of the terms of our debt agreements, which includes the terms of our committed credit facility. We are required to maintain a debt to capitalization ratio, as defined in the debt agreements, not to exceed 65 percent. We are below this limit.

Available Sources of Liquidity

The following sources of liquidity are available as at September 30, 2025:

($ millions)	Maturity	Amount Available
Cash and Cash Equivalents	n/a	1,901
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	1,094

(1)No amounts were drawn on the committed credit facility as at September 30, 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 September 30, 2025, there were outstanding letters of credit aggregating to $338 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 September 30, 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 September 30, 2025, no amount was drawn on the credit facility (December 31, 2024 – $nil).

MEG Acquisition

On August 21, 2025, Cenovus obtained fully committed financing of a $2.7 billion three-year term loan and a $2.5 billion bridge facility to fund the cash consideration portion of the MEG Acquisition. No amounts were outstanding on the term loan and bridge facility as at September 30, 2025.

Base Shelf Prospectus

We have a base shelf prospectus that allows us to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. We plan to renew the base shelf prospectus that will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, Total Debt, the Net Debt to Adjusted EBITDA ratio, the Net Debt to Adjusted Funds Flow ratio and the Net Debt to Capitalization ratio. Refer to Note 12 of the interim Consolidated Financial Statements for further details.

We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents, and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholder’s Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA ratio, as net earnings (loss) before finance costs, net, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, (gain) loss on divestiture of assets, re-measurement of contingent payments and net other (income) loss calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and are measures of our overall financial strength.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	37
As at	September 30, 2025	December 31, 2024
---	---	---
Net Debt to Adjusted EBITDA Ratio (times)	0.6	0.5
Net Debt to Adjusted Funds Flow Ratio (times)	0.7	0.6
Net Debt to Capitalization Ratio (percent)	16	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 and Net Debt to Adjusted Funds Flow ratio as at September 30, 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.

Our Net Debt to Capitalization ratio as at September 30, 2025, increased compared with December 31, 2024, primarily due to higher Net Debt.

Share Capital and Stock-Based Compensation Plans

Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Our cumulative redeemable preferred shares series 1 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 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 September 30, 2025, there were approximately 1,766.3 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).

In the fourth quarter of 2024, Cenovus established an employee benefit plan trust (the “Trust”). The Trust, through an independent trustee, acquires Cenovus’s common shares on the open market, which are held to satisfy the Company’s obligations under certain stock-based compensation plans. For the nine months ended September 30, 2025, the Trust purchased 4.6 million common shares for a total of $94 million and distributed 3.8 million common shares for a total of $82 million under the employee benefit plan. As at September 30, 2025, there were 2.8 million common shares held by the Trust (December 31, 2024 – 2.0 million common shares). Refer to Note 15 of the interim Consolidated Financial Statements for further details.

As at September 30, 2025, there were approximately 2.9 million Cenovus Warrants outstanding (December 31, 2024 – 3.6 million). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years from the date of issue at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to Note 15 of the interim Consolidated Financial Statements for further details.

Refer to Note 17 of the interim 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 October 27, 2025	Units Outstanding<br><br>(thousands)	Units Exercisable<br><br>(thousands)
Common Shares	1,751,241	n/a
Cenovus Warrants	2,870	n/a
Series 1 First Preferred Shares	10,740	n/a
Series 2 First Preferred Shares	1,260	n/a
Stock Options	11,141	5,162
Other Stock-Based Compensation Plans	19,570	2,006
Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	38
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Common Share Dividends

In the three months ended September 30, 2025, we declared and paid base dividends of $356 million or $0.200 per common share (2024 – $329 million or $0.180 per common share). In the nine months ended September 30, 2025, we declared and paid base dividends of $1.0 billion or $0.580 per common share (2024 – $925 million or $0.500 per common share).

On October 30, 2025, the Board declared a fourth quarter base dividend of $0.200 per common share. The dividend is payable on December 31, 2025, to common shareholders of record as at December 15, 2025.

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

Cumulative Redeemable Preferred Share Dividends

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Series 1 First Preferred Shares	2	2	5	5
Series 2 First Preferred Shares	—	1	1	2
Series 3 First Preferred Shares	—	3	—	9
Series 5 First Preferred Shares	—	2	2	7
Series 7 First Preferred Shares	—	1	4	4
Total Preferred Share Dividends Declared	2	9	12	27

On October 30, 2025, the Board declared a fourth quarter dividend on the series 1 and 2 preferred shares for a total of $2 million, payable on December 31, 2025, to preferred shareholders of record as at December 15, 2025.

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

Share Repurchases

We have an NCIB program to purchase up to 127.5 million common shares from November 11, 2024, to November 10, 2025.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
Common Shares Purchased and Cancelled Under NCIB<br><br>(millions of common shares)	40.4	28.4	60.5	51.2
Weighted Average Price per Common Share ($)	22.31	25.22	20.75	25.60
Purchase of Common Shares Under NCIB ($ millions)	918	732	1,281	1,337

From October 1, 2025, to October 27, 2025, the Company purchased an additional 17.0 million common shares for $409 million. As at October 27, 2025, the Company can further purchase up to 48.8 million common shares under the NCIB.

On October 30, 2025, the Company received approval from the Board of Directors to apply to the TSX for an additional NCIB program. Subject to acceptance by the TSX, the Company will be able to purchase up to approximately 120 million common shares under the NCIB program for a period of twelve months from the date the program is renewed.

Contractual Obligations and Commitments

We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from our total commitments disclosed below. For further information, see Note 22 of the interim Consolidated Financial Statements.

Our total commitments were $27.2 billion as at September 30, 2025 (December 31, 2024 – $27.3 billion), of which $24.4 billion are for various transportation and storage commitments. Transportation commitments include $1.5 billion that are subject to regulatory approval or were approved but are not yet in service. Terms are up to 15 years on commencement.

As at September 30, 2025, our total commitments included commitments with HMLP of $1.7 billion related to long-term transportation and storage commitments (December 31, 2024 – $1.8 billion).

As at September 30, 2025, outstanding letters of credit issued as security for performance under certain contracts totaled $338 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 interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	39

Transactions with Related Parties

Husky Midstream Limited Partnership

The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. 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.

The following table summarizes revenues and associated expenses related to HMLP:

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Revenues from Construction and Management Services	50	47	116	116
Transportation Expenses	66	67	203	207
RISK MANAGEMENT AND RISK FACTORS
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For a full understanding of the risks that impact us, the following discussion should be read in conjunction with the Risk Management and Risk Factors section of our 2024 annual MD&A.

We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the energy industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, our business, reputation, financial condition, results of operations and cash flows, which may, without limitation, reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, respond to changes in our operating environment, repurchase our shares, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and/or may materially affect the market price of our securities.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, as well as use judgment, in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2024.

Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements. A full list of the critical judgments used in applying accounting policies and key sources of estimation uncertainty can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2024.

CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at September 30, 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 September 30, 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.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	40
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.

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; safety performance; sustainability; our commitment to the Pathways Alliance foundational project; maximizing value and profitability; disciplined capital allocation; cash flow volatility and stability; price alignment and volatility management strategies; dividends; focus on cost and sustainability improvements; liquidity; our 2025 corporate guidance; realizing the full value of our integrated strategy; capitalizing on opportunities; Net Debt target; allocating Excess Free Funds Flow; absolute and per share Free Funds Flow growth; our competitive, reliable downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; project execution; growing our competitive advantages while operating safely and reliably monitoring market fundamentals and optimizing run rates at our refineries; safe and reliable operations; being best-in-class operators; maintaining a strong balance sheet; costs; margins; long-term value for Cenovus; timing of commissioning and commencement of drilling at the West White Rose project; progressing growth projects, including ramping up production at Narrows Lake, the Foster Creek optimization, Lloydminster drilling program and Sunrise growth projects; our sustainability focus areas and targets; 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 U.S. tariffs on market benchmarks and Cenovus; Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; capitalizing on opportunities throughout the commodity price cycle; Net Debt to Adjusted EBITDA ratio; maintaining sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar, the factors that affect such outlook, and the influences and effects on Cenovus.

Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast bitumen, crude oil and natural gas, NGLs, condensate and refined products prices, and light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs, projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change Indigenous relations, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions and the supply and demand for bitumen, crude oil and natural gas, NGLs, condensate and refined products, the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, third party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company’s share price and market capitalization over the long-term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the Company’s ability to use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange rate and interest rates; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue and fund future investments and development plans and dividends, including any increase thereto; our downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials;

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	41

realization of expected capacity to store within the Company’s oil sands reservoirs barrels not yet produced, including that the Company will be able to time production and sales of its inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and future crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, 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, the commercial viability and scalability of related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2025 guidance available on cenovus.com and as set out below; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.

2025 guidance dated July 30, 2025, and October 30, 2025, and available on cenovus.com, assumes: Brent prices of US$69.00 per barrel, WTI prices of US$65.00 per barrel; WCS of US$53.50 per barrel; Differential WTI-WCS of US$11.50 per barrel; AECO natural gas prices of $2.00 per Mcf; Chicago 3-2-1 crack spread of US$18.50 per barrel; RINs of US$5.50 per barrel; and an exchange rate of $0.72 US$/C$.

The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; the Company’s ability to successfully integrate acquired business with its own in a timely and cost effective manner; 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 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 remaining 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, the impact of tariffs and responses thereto, currency and interest rates; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; the ability to complete and optimize drilling, completion, tie in and infrastructure projects; the ability of the Company to ramp-up activities at its refineries on its anticipated timelines; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; tax audits and reassessments; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and 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

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	42

and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying refining or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s business, including potential cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and the Company’s ability to attract and retain, critical and diverse talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; OPEC+ policy; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets for sustainability focus areas may have a negative impact on our existing business, growth plans and future results from operations.

Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward‐looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors in the Company’s most recently filed Annual MD&A, and the risk factors described in other documents the Company files from time to time with securities regulatory authorities in Canada, available on SEDAR+ at sedarplus.ca, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Company’s website at cenovus.com.

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

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	43

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
WCS	Western Canadian Select	MMcf/d	million cubic feet per day	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. – Q3 2025 Management's Discussion and Analysis	44
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SPECIFIED FINANCIAL MEASURES

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS Accounting Standards including Operating Margin, Operating Margin by asset, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, 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 and 2024 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 interim Consolidated Financial Statements.

Operating Margin

	Three Months Ended September 30,
	2025	2024	2025	2024	2025	2024
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales (2)	5,774	6,052	8,279	8,696	14,053	14,748
Intersegment Sales	1,788	2,207	156	102	1,944	2,309
	7,562	8,259	8,435	8,798	15,997	17,057
Royalties	(858)	(929)	—	—	(858)	(929)
Revenues (2)	6,704	7,330	8,435	8,798	15,139	16,128
Expenses
Purchased Product (2)	674	1,088	7,321	8,207	7,995	9,295
Transportation and Blending	2,543	2,661	—	—	2,543	2,661
Operating	885	860	751	918	1,636	1,778
Realized (Gain) Loss on Risk Management	12	(10)	(1)	(4)	11	(14)
Operating Margin	2,590	2,731	364	(323)	2,954	2,408

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

(2)Comparative period reflects certain revisions. See the Prior Period Revisions section of this MD&A for further details.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	45
	Nine Months Ended September 30,
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	2025	2024		2025	2024	2025	2024
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales (2)	17,981	18,590		23,217	25,409	41,198	43,999
Intersegment Sales	6,227	6,248		666	372	6,893	6,620
	24,208	24,838		23,883	25,781	48,091	50,619
Royalties	(2,385)	(2,535)		—	—	(2,385)	(2,535)
Revenues (2)	21,823	22,303		23,883	25,781	45,706	48,084
Expenses
Purchased Product (2)	2,952	2,674		21,281	22,888	24,233	25,562
Transportation and Blending	8,411	8,515		—	—	8,411	8,515
Operating	2,674	2,647		2,552	2,804	5,226	5,451
Realized (Gain) Loss on Risk Management	11	16		(6)	5	5	21
Operating Margin	7,775	8,451		56	84	7,831	8,535

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

(2)Comparative period reflects certain revisions. See the Prior Period Revisions section of this MD&A for further details.

Operating Margin by Asset

	Three Months Ended September 30, 2025			Nine Months Ended September 30, 2025
($ millions)	Atlantic	Asia Pacific	Offshore (1)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	140	245	385	358	813	1,171
Royalties	(2)	(13)	(15)	(4)	(56)	(60)
Revenues	138	232	370	354	757	1,111
Expenses
Purchased Product	6	—	6	6	—	6
Transportation and Blending	5	—	5	14	—	14
Operating	75	28	103	187	86	273
Operating Margin	52	204	256	147	671	818	Three Months Ended September 30, 2024	Nine Months Ended September 30, 2024
---	---	---	---	---	---	---
($ millions)	Atlantic	Asia Pacific	Offshore (1)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	71	300	371	264	935	1,199
Royalties	(1)	(24)	(25)	(2)	(72)	(74)
Revenues	70	276	346	262	863	1,125
Expenses
Purchased Product	—	—	—	—	—	—
Transportation and Blending	2	—	2	9	—	9
Operating	58	34	92	225	94	319
Operating Margin	10	242	252	28	769	797

(1)Found in Note 1 of the interim 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. – Q3 2025 Management's Discussion and Analysis	46

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 September 30,		Nine Months Ended September 30,
($ millions)	2025	2024	2025	2024
Cash From (Used in) Operating Activities	2,131	2,474	5,820	7,206
(Add) Deduct:
Settlement of Decommissioning Liabilities	(94)	(74)	(198)	(170)
Net Change in Non-Cash Working Capital	(241)	588	(179)	813
Adjusted Funds Flow	2,466	1,960	6,197	6,563
Capital Investment	1,154	1,346	3,547	3,537
Free Funds Flow	1,312	614	2,650	3,026
Add (Deduct):
Base Dividends Paid on Common Shares	(356)	(329)	(1,047)	(925)
Dividends Paid on Preferred Shares	—	(9)	(10)	(27)
Purchase of Common Shares Under Employee <br> Benefit Plan	(21)	—	(94)	—
Settlement of Decommissioning Liabilities	(94)	(74)	(198)	(170)
Principal Repayment of Leases	(89)	(74)	(266)	(219)
Acquisitions, Net of Cash Acquired	(7)	(4)	(236)	(19)
Proceeds From Divestitures	—	22	13	47
Excess Free Funds Flow	745	146	812	1,713

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.

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.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	47

Canadian Refining

	Three Months Ended September 30, 2025
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	1,271	82	1,353
Purchased Product	1,050	52	1,102
Gross Margin	221	30	251
Add (Deduct):
Inventory Holding (Gain) Loss	8	—	8
Adjusted Gross Margin	229	30	259
Total Processed Inputs (Mbbls/d)	114.8
Adjusted Refining Margin ($/bbl)	21.76

(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 September 30, 2024
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	1,493	87	1,580
Purchased Product	1,292	61	1,353
Gross Margin	201	26	227
Add (Deduct):
Inventory Holding (Gain) Loss	15	1	16
Adjusted Gross Margin	216	27	243
Total Processed Inputs (Mbbls/d)	106.4
Adjusted Refining Margin ($/bbl)	22.17

(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.

	Nine Months Ended September 30, 2025
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	3,703	220	3,923
Purchased Product	3,070	148	3,218
Gross Margin	633	72	705
Add (Deduct):
Inventory Holding (Gain) Loss	(1)	—	(1)
Adjusted Gross Margin	632	72	704
Total Processed Inputs (Mbbls/d)	118.3
Adjusted Refining Margin ($/bbl)	19.56

(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.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	48
	Nine Months Ended September 30, 2024
---	---	---	---
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining (2)
Revenues	3,807	240	4,047
Purchased Product	3,246	169	3,415
Gross Margin	561	71	632
Add (Deduct):
Inventory Holding (Gain) Loss	(4)	2	(2)
Adjusted Gross Margin	557	73	630
Total Processed Inputs (Mbbls/d)	91.4
Adjusted Refining Margin ($/bbl)	22.27

(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
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.

	Year Ended December 31, 2024
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian<br><br>Refining
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.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	49

U.S. Refining

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions, except where indicated)	2025	2024	2025	2024
Revenues (1)	7,082	7,218	19,960	21,734
Purchased Product (1)	6,219	6,854	18,063	19,473
Gross Margin	863	364	1,897	2,261
Add (Deduct):
Inventory Holding (Gain) Loss	80	209	165	(68)
Adjusted Gross Margin	943	573	2,062	2,193
Total Processed Inputs (Mbbls/d)	642.8	568.0	606.2	579.0
Adjusted Refining Margin ($/bbl)	15.92	10.97	12.45	13.82
Operable Capacity (Mbbls/d)	612.3	612.3	612.3	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81	81	81
Group 3 3-2-1 Crack Spread Weighting	19	19	19	19
Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	24.24	18.62	19.85	18.27
Group 3 3-2-1 Crack Spread (US$/bbl)	23.72	18.95	21.09	18.19
RINs (US$/bbl)	6.33	3.89	5.74	3.65
US$ per C$1 – Average	0.726	0.733	0.715	0.735
Weighted Average Crack Spread, Net of RINs ($/bbl)	24.53	20.18	20.07	19.87
Adjusted Market Capture (percent)	65	54	62	70

(1)Found in Note 1 of the interim Consolidated Financial Statements. Comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	50
	Three Months Ended	Twelve Months Ended
---	---	---
($ millions, except where indicated)	December 31, 2024	December 31, 2024
Revenues	6,574	28,308
Purchased Product	6,296	25,769
Gross Margin	278	2,539
Add (Deduct):
Inventory Holding (Gain) Loss	45	(23)
Adjusted Gross Margin	323	2,516
Total Processed Inputs (Mbbls/d)	588.4	581.4
Adjusted Refining Margin ($/bbl)	5.98	11.83
Operable Capacity (Mbbls/d)	612.3	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81
Group 3 3-2-1 Crack Spread Weighting	19	19
Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	12.12	16.74
Group 3 3-2-1 Crack Spread (US$/bbl)	12.66	16.81
RINs (US$/bbl)	4.02	3.74
US$ per C$1 – Average	0.715	0.730
Weighted Average Crack Spread, Net of RINs ($/bbl)	11.47	17.82
Adjusted Market Capture (percent)	52	67

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 BOE 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. – Q3 2025 Management's Discussion and Analysis	51

Oil Sands

	Basis of Netback Calculation
Three Months Ended September 30, 2025 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,507	1,616	396	786	4,305
Royalties	(320)	(405)	(17)	(89)	(831)
Revenues	1,187	1,211	379	697	3,474
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	249	165	74	35	523
Operating	163	153	87	250	653
Netback	775	893	218	412	2,298
Realized (Gain) Loss on Risk Management					10
Operating Margin					2,288		Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---
Three Months Ended September 30, 2025 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	4,305		1,892	429	122	6,748
Royalties	(831)		—	—	—	(831)
Revenues	3,474		1,892	429	122	5,917
Expenses
Purchased Product	—		—	429	78	507
Transportation and Blending	523		1,892	—	37	2,452
Operating	653		—	—	2	655
Netback	2,298		—	—	5	2,303
Realized (Gain) Loss on Risk Management	10		—	—	—	10
Operating Margin	2,288		—	—	5	2,293

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

(2)Includes bitumen and heavy oil.

(3)Other includes construction, transportation and blending.

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

	Basis of Netback Calculation
Three Months Ended September 30, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,494	1,622	416	939	4,471
Royalties	(329)	(406)	(23)	(131)	(889)
Revenues	1,165	1,216	393	808	3,582
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	227	156	77	42	502
Operating	159	190	64	197	610
Netback	779	870	252	569	2,470
Realized (Gain) Loss on Risk Management					(10)
Operating Margin					2,480

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

(2)Includes bitumen and heavy oil.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	52
	Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---
Three Months Ended September 30, 2024 ($ millions)	Total Oil Sands (1)		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	4,471		2,021	548	135	7,175
Royalties	(889)		—	—	—	(889)
Revenues	3,582		2,021	548	135	6,286
Expenses
Purchased Product	—		—	548	81	629
Transportation and Blending	502		2,021	—	56	2,579
Operating	610		—	—	11	621
Netback	2,470		—	—	(13)	2,457
Realized (Gain) Loss on Risk Management	(10)		—	—	—	(10)
Operating Margin	2,480		—	—	(13)	2,467

(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
Nine Months Ended September 30, 2025 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	4,499	4,500	1,102	2,485	12,586
Royalties	(862)	(1,077)	(53)	(287)	(2,279)
Revenues	3,637	3,423	1,049	2,198	10,307
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	862	414	224	112	1,612
Operating	558	510	257	702	2,027
Netback	2,217	2,499	568	1,384	6,668
Realized (Gain) Loss on Risk Management					10
Operating Margin					6,658		Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---
Nine Months Ended September 30, 2025 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	12,586		6,456	1,751	322	21,115
Royalties	(2,279)		—	—	(2)	(2,281)
Revenues	10,307		6,456	1,751	320	18,834
Expenses
Purchased Product	—		—	1,751	244	1,995
Transportation and Blending	1,612		6,456	—	70	8,138
Operating	2,027		—	—	5	2,032
Netback	6,668		—	—	1	6,669
Realized (Gain) Loss on Risk Management	10		—	—	—	10
Operating Margin	6,658		—	—	1	6,659

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

(2)Includes bitumen and heavy oil.

(3)Other includes construction, transportation and blending.

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

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	53
	Basis of Netback Calculation
---	---	---	---	---
Nine Months Ended September 30, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	4,383	4,782	1,194	2,853	13,212
Royalties	(893)	(1,146)	(59)	(296)	(2,394)
Revenues	3,490	3,636	1,135	2,557	10,818
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	656	417	235	141	1,449
Operating	519	546	191	619	1,875
Netback	2,315	2,673	709	1,797	7,494
Realized (Gain) Loss on Risk Management					23
Operating Margin					7,471		Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---
Nine Months Ended September 30, 2024 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	13,212		6,732	1,066	346	21,356
Royalties	(2,394)		—	—	(6)	(2,400)
Revenues	10,818		6,732	1,066	340	18,956
Expenses
Purchased Product	—		—	1,066	255	1,321
Transportation and Blending	1,449		6,732	—	84	8,265
Operating	1,875		—	—	21	1,896
Netback	7,494		—	—	(20)	7,474
Realized (Gain) Loss on Risk Management	23		—	—	—	23
Operating Margin	7,471		—	—	(20)	7,451

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

(2)Includes bitumen and heavy oil.

(3)Other includes construction, transportation and blending.

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

Conventional

	Basis of Netback Calculation	Adjustments
Three Months Ended September 30, 2025 ($ millions)	Conventional (1)	Third-party Sourced	Other (1) (2)	Conventional (3)
Gross Sales	242	161	26	429
Royalties	(12)	—	—	(12)
Revenues	230	161	26	417
Expenses
Purchased Product	—	161	—	161
Transportation and Blending	64	—	22	86
Operating	121	—	6	127
Netback	45	—	(2)	43
Realized (Gain) Loss on Risk Management	2	—	—	2
Operating Margin	43	—	(2)	41

(1)For the three months ended September 30, 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. – Q3 2025 Management's Discussion and Analysis	54
	Basis of Netback Calculation	Adjustments
---	---	---	---	---
Three Months Ended September 30, 2024 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	222	460	31	713
Royalties	(15)	—	—	(15)
Revenues	207	460	31	698
Expenses
Purchased Product	—	460	(1)	459
Transportation and Blending	56	—	24	80
Operating	139	—	8	147
Netback	12	—	—	12
Realized (Gain) Loss on Risk Management	—	—	—	—
Operating Margin	12	—	—	12

(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
Nine Months Ended September 30, 2025 ($ millions)	Conventional (1)	Third-party Sourced	Other (1) (2)	Conventional (3)
Gross Sales	885	951	86	1,922
Royalties	(45)	—	1	(44)
Revenues	840	951	87	1,878
Expenses
Purchased Product	—	951	—	951
Transportation and Blending	183	—	76	259
Operating	351	—	18	369
Netback	306	—	(7)	299
Realized (Gain) Loss on Risk Management	1	—	—	1
Operating Margin	305	—	(7)	298

(1)For the nine months ended September 30, 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 interim Consolidated Financial Statements.

	Basis of Netback Calculation	Adjustments
Nine Months Ended September 30, 2024 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	832	1,353	98	2,283
Royalties	(61)	—	—	(61)
Revenues	771	1,353	98	2,222
Expenses
Purchased Product	—	1,353	—	1,353
Transportation and Blending	166	—	75	241
Operating	408	—	24	432
Netback	197	—	(1)	196
Realized (Gain) Loss on Risk Management	(7)	—	—	(7)
Operating Margin	204	—	(1)	203

(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 interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	55

Offshore

	Basis of Netback Calculation					Adjustments
Three Months Ended September 30, 2025 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>Asia Pacific	Total Offshore	Equity<br><br>Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	119	245	85	330	449	(85)	21	385
Royalties	(1)	(13)	(21)	(34)	(35)	21	(1)	(15)
Revenues	118	232	64	296	414	(64)	20	370
Expenses
Purchased Product	—	—	—	—	—	—	6	6
Transportation and Blending	5	—	—	—	5	—	—	5
Operating	75	26	14	40	115	(12)	—	103
Netback	38	206	50	256	294	(52)	14	256
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					294	(52)	14	256	Basis of Netback Calculation	Adjustments
---	---	---	---	---	---	---	---	---
Three Months Ended September 30, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>Asia Pacific	Total Offshore	Equity<br><br>Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	71	300	82	382	453	(82)	—	371
Royalties	(1)	(24)	(9)	(33)	(34)	9	—	(25)
Revenues	70	276	73	349	419	(73)	—	346
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	2	—	—	—	2	—	—	2
Operating	59	30	16	46	105	(14)	1	92
Netback	9	246	57	303	312	(59)	(1)	252
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					312	(59)	(1)	252

(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
Nine Months Ended September 30, 2025 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>Asia Pacific	Total Offshore	Equity<br><br>Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	337	813	260	1,073	1,410	(260)	21	1,171
Royalties	(3)	(56)	(69)	(125)	(128)	69	(1)	(60)
Revenues	334	757	191	948	1,282	(191)	20	1,111
Expenses
Purchased Product	—	—	—	—	—	—	6	6
Transportation and Blending	14	—	—	—	14	—	—	14
Operating	184	79	44	123	307	(37)	3	273
Netback	136	678	147	825	961	(154)	11	818
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					961	(154)	11	818

(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.

Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	56
	Basis of Netback Calculation					Adjustments
---	---	---	---	---	---	---	---	---
Nine Months Ended September 30, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total<br>Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	264	935	229	1,164	1,428	(229)	—	1,199
Royalties	(2)	(72)	(28)	(100)	(102)	28	—	(74)
Revenues	262	863	201	1,064	1,326	(201)	—	1,125
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	9	—	—	—	9	—	—	9
Operating	222	84	44	128	350	(37)	6	319
Netback	31	779	157	936	967	(164)	(6)	797
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					967	(164)	(6)	797

(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.

Upstream Sales Volumes (1)

The following table provides the sales volumes used to calculate Netback:

	Three Months Ended September 30,		Nine Months Ended September 30,
(MBOE/d)	2025	2024	2025	2024
Oil Sands (2)
Foster Creek	206.2	191.7	201.5	190.4
Christina Lake	251.3	221.6	234.4	227.3
Sunrise	54.2	54.4	51.2	49.2
Lloydminster	120.2	126.6	124.2	128.4
Total Oil Sands	631.9	594.3	611.3	595.3
Conventional (3)	126.9	118.1	123.6	120.5
Offshore
Atlantic	13.6	7.2	12.4	8.6
Asia Pacific
China	35.2	40.5	38.1	42.6
Indonesia (4)	16.7	16.0	16.0	14.8
Total Asia Pacific	51.9	56.5	54.1	57.4
Total Offshore	65.5	63.7	66.5	66.0

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

(2)Includes bitumen and heavy crude oil sales.

(3)For the three and nine months ended September 30, 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. – Q3 2025 Management's Discussion and Analysis	57

Per-Unit Depreciation, Depletion and Amortization

Per-unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define per-unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties, and the associated decommissioning costs, divided by sales volumes.

PRIOR PERIOD REVISIONS

In December 2024, it was identified that certain transactions in the U.S. Refining segment were reported on a gross basis in revenues and purchased product rather than on a net basis. As a result, revenues and purchased product were overstated for the nine months ended September 30, 2024. The prior periods were revised to reflect the change. There was no impact on net earnings (loss), segment income (loss), cash flows or financial position.

The following tables reconcile the amounts previously reported in the Consolidated Statements of Comprehensive Income (Loss) and segmented disclosures to the corresponding revised amounts:

	U.S. Refining Segment			Consolidated
For the three months ended March 31, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,235	(334)	6,901	13,397	(334)	13,063
Purchased Product	6,132	(334)	5,798	6,133	(334)	5,799
Transportation and Blending	—	—	—	2,575	—	2,575
Purchased Product, Transportation <br> and Blending	6,132	(334)	5,798	8,708	(334)	8,374
	1,103	—	1,103	4,689	—	4,689	U.S. Refining Segment	Consolidated
---	---	---	---	---	---	---
For the three months ended <br>June 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,918	(303)	7,615	14,885	(303)	14,582
Purchased Product	7,124	(303)	6,821	7,184	(303)	6,881
Transportation and Blending	—	—	—	2,865	—	2,865
Purchased Product, Transportation <br> and Blending	7,124	(303)	6,821	10,049	(303)	9,746
	794	—	794	4,836	—	4,836	U.S. Refining Segment	Consolidated
---	---	---	---	---	---	---
For the three months ended <br>September 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,648	(430)	7,218	14,249	(430)	13,819
Purchased Product	7,284	(430)	6,854	7,556	(430)	7,126
Transportation and Blending	—	—	—	2,489	—	2,489
Purchased Product, Transportation <br> and Blending	7,284	(430)	6,854	10,045	(430)	9,615
	364	—	364	4,204	—	4,204	U.S. Refining Segment	Consolidated
---	---	---	---	---	---	---
For the nine months ended <br>September 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	22,801	(1,067)	21,734	42,531	(1,067)	41,464
Purchased Product	20,540	(1,067)	19,473	20,873	(1,067)	19,806
Transportation and Blending	—	—	—	7,929	—	7,929
Purchased Product, Transportation <br> and Blending	20,540	(1,067)	19,473	28,802	(1,067)	27,735
	2,261	—	2,261	13,729	—	13,729
Cenovus Energy Inc. – Q3 2025 Management's Discussion and Analysis	58
---	---

cve-20250930

Exhibit 99.3

Cenovus Energy Inc.

Interim Consolidated Financial Statements (unaudited)

For the Periods Ended September 30, 2025

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

For the periods ended September 30, 2025
TABLE OF CONTENTS
---		CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)	3
---	---
CONSOLIDATED BALANCE SHEETS (UNAUDITED)	4
CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)	5
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)	6
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)	7
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES	7
2.BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE	14
3. FINANCE COSTS, NET	15
4. FOREIGN EXCHANGE (GAIN) LOSS, NET	15
5. DIVESTITURE	15
6. INCOME TAXES	15
7. PER SHARE AMOUNTS	16
8. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES	17
9.EXPLORATION AND EVALUATION ASSETS, NET	17
10. PROPERTY, PLANT AND EQUIPMENT, NET	17
11. LEASES	18
12. DEBT AND CAPITAL STRUCTURE	18
13. DECOMMISSIONING LIABILITIES	21
14. OTHER LIABILITIES	21
15. SHARE CAPITAL AND WARRANTS	21
16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	23
17. STOCK-BASED COMPENSATION PLANS	23
18. RELATED PARTY TRANSACTIONS	24
19. FINANCIAL INSTRUMENTS	25
20. RISK MANAGEMENT	27
21. SUPPLEMENTARY CASH FLOW INFORMATION	28
22. COMMITMENTS AND CONTINGENCIES	30
23. PRIOR PERIOD REVISIONS	30
24. SUBSEQUENT EVENTS	31
Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	2
---	---
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
---

For the periods ended September 30,

($ millions, except per share amounts)

		Three Months Ended		Nine Months Ended
	Notes	2025	2024	2025	2024
Revenues (1)	1	13,195	13,819	38,813	41,464
Expenses	1
Purchased Product, Transportation and Blending (1)		8,545	9,615	25,956	27,735
Operating		1,594	1,736	4,971	5,214
(Gain) Loss on Risk Management	19	(2)	(20)	(79)	42
Depreciation, Depletion, Amortization and Exploration <br> Expense	10,11	1,323	1,262	3,829	3,702
(Income) Loss From Equity-Accounted Affiliates		(9)	(11)	(45)	(48)
General and Administrative		220	172	570	593
Finance Costs, Net	3	154	118	404	394
Integration, Transaction and Other Costs		44	41	123	113
Foreign Exchange (Gain) Loss, Net	4	157	(73)	(196)	81
(Gain) Loss on Divestiture of Assets	5	(106)	(17)	(109)	(121)
Re-measurement of Contingent Payments		—	—	—	30
Other (Income) Loss, Net		(22)	(28)	(54)	(158)
Earnings (Loss) Before Income Tax		1,297	1,024	3,443	3,887
Income Tax Expense (Recovery)	6	11	204	447	891
Net Earnings (Loss)		1,286	820	2,996	2,996
Other Comprehensive Income (Loss), Net of Tax	16
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other<br><br>Post-Employment Benefits		2	(7)	10	11
Change in the Fair Value of Equity Instruments at<br><br>FVOCI (2)	19	(19)	(1)	(23)	123
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		(1,009)	(174)	(1,681)	219
Total Other Comprehensive Income (Loss), Net of Tax		(1,026)	(182)	(1,694)	353
Comprehensive Income (Loss)		260	638	1,302	3,349
Net Earnings (Loss) Per Common Share ($)	7
Basic		0.72	0.44	1.65	1.60
Diluted		0.72	0.42	1.65	1.59

(1)Comparative periods reflect certain revisions. See Note 23.

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

See accompanying Notes to the interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	3
CONSOLIDATED BALANCE SHEETS (unaudited)
---

As at

($ millions)

		September 30,	December 31,
	Notes	2025	2024
Assets
Current Assets
Cash and Cash Equivalents		1,901	3,093
Accounts Receivable and Accrued Revenues	8	4,688	2,614
Income Tax Receivable		54	231
Inventories		3,126	4,496
Total Current Assets		9,769	10,434
Restricted Cash		256	241
Exploration and Evaluation Assets, Net	1,9	430	484
Property, Plant and Equipment, Net	1,10	35,972	38,568
Right-of-Use Assets, Net	1,11	1,914	1,950
Income Tax Receivable		25	25
Investments in Equity-Accounted Affiliates		321	399
Other Assets		447	451
Deferred Income Taxes		1,516	1,064
Goodwill	1	2,923	2,923
Total Assets		53,573	56,539
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		5,216	6,242
Income Tax Payable		93	396
Short-Term Borrowings	12	—	173
Long-Term Debt	12	—	192
Lease Liabilities	11	342	359
Total Current Liabilities		5,651	7,362
Long-Term Debt	12	7,156	7,342
Lease Liabilities	11	2,530	2,568
Decommissioning Liabilities	13	4,973	4,534
Other Liabilities	14	925	919
Deferred Income Taxes		3,949	4,045
Total Liabilities		25,184	26,770
Shareholders’ Equity		28,374	29,754
Non-Controlling Interest		15	15
Total Liabilities and Equity		53,573	56,539
Commitments and Contingencies	22

See accompanying Notes to the interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	4
CONSOLIDATED STATEMENTS OF EQUITY (unaudited)
---

($ millions)

	Shareholders’ Equity
	Common Shares	Treasury<br>Shares	Preferred Shares	Warrants	Paid in<br><br>Surplus	Retained<br><br>Earnings	AOCI (1)	Total
	(Note 15)	(Note 15)	(Note 15)	(Note 15)			(Note 16)
As at December 31, 2023	16,031	—	519	25	2,002	8,913	1,208	28,698
Net Earnings (Loss)	—	—	—	—	—	2,996	—	2,996
Other Comprehensive Income <br>(Loss), Net of Tax	—	—	—	—	—	—	353	353
Total Comprehensive Income (Loss)	—	—	—	—	—	2,996	353	3,349
Common Shares Issued Under<br>Stock Option Plans	67	—	—	—	(16)	—	—	51
Purchase of Common Shares Under<br><br>NCIB (2)	(439)	—	—	—	(898)	—	—	(1,337)
Warrants Exercised	38	—	—	(13)	—	—	—	25
Stock-Based Compensation<br>Expense	—	—	—	—	8	—	—	8
Base Dividends on Common Shares	—	—	—	—	—	(925)	—	(925)
Variable Dividends on Common<br>Shares	—	—	—	—	—	(251)	—	(251)
Dividends on Preferred Shares	—	—	—	—	—	(27)	—	(27)
As at September 30, 2024	15,697	—	519	12	1,096	10,706	1,561	29,591
As at December 31, 2024	15,659	(43)	356	12	944	10,513	2,313	29,754
Net Earnings (Loss)	—	—	—	—	—	2,996	—	2,996
Other Comprehensive Income<br>(Loss), Net of Tax	—	—	—	—	—	—	(1,694)	(1,694)
Total Comprehensive Income (Loss)	—	—	—	—	—	2,996	(1,694)	1,302
Common Shares Issued Under<br>Stock Option Plans	15	—	—	—	(3)	—	—	12
Purchase of Common Shares Under<br><br>NCIB (2)	(519)	—	—	—	(541)	(221)	—	(1,281)
Purchase of Common Shares Under<br>Employee Benefit Plan	—	(94)	—	—	—	—	—	(94)
Common Shares Issued Under<br>Employee Benefit Plan	—	82	—	—	(6)	—	—	76
Preferred Shares Redeemed	—	—	(243)	—	(107)	—	—	(350)
Warrants Exercised	7	—	—	(2)	—	—	—	5
Stock-Based Compensation<br>Expense	—	—	—	—	9	—	—	9
Base Dividends on Common Shares	—	—	—	—	—	(1,047)	—	(1,047)
Dividends on Preferred Shares	—	—	—	—	—	(12)	—	(12)
As at September 30, 2025	15,162	(55)	113	10	296	12,229	619	28,374

(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 interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	5
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
---

For the periods ended September 30,

($ millions)

		Three Months Ended		Nine Months Ended
	Notes	2025	2024	2025	2024
Operating Activities
Net Earnings (Loss)		1,286	820	2,996	2,996
Depreciation, Depletion and Amortization	10,11	1,322	1,218	3,820	3,646
Deferred Income Tax Expense (Recovery)	6	(327)	(46)	(520)	(124)
Unrealized (Gain) Loss on Risk Management	19	(19)	7	(65)	31
Unrealized Foreign Exchange (Gain) Loss	4	153	(108)	(248)	101
Realized Foreign Exchange (Gain) Loss on Non-Operating Items		4	—	4	—
(Gain) Loss on Divestiture of Assets	5	(106)	(17)	(109)	(121)
Re-measurement of Contingent Payments		—	—	—	30
Unwinding of Discount on Decommissioning Liabilities	13	63	56	179	169
(Income) Loss From Equity-Accounted Affiliates		(9)	(11)	(45)	(48)
Distributions Received From Equity-Accounted Affiliates		27	15	110	133
Stock-Based Compensation, Net of Payments		75	(13)	94	(143)
Other		(3)	39	(19)	(107)
Settlement of Decommissioning Liabilities	13	(94)	(74)	(198)	(170)
Net Change in Non-Cash Working Capital	21	(241)	588	(179)	813
Cash From (Used in) Operating Activities		2,131	2,474	5,820	7,206
Investing Activities
Acquisitions, Net of Cash Acquired		(7)	(4)	(236)	(19)
Capital Investment	1	(1,154)	(1,346)	(3,547)	(3,537)
Proceeds From Divestitures	5	—	22	13	47
Net Change in Investments and Other		4	1	(9)	(63)
Net Change in Non-Cash Working Capital	21	(159)	19	(260)	(41)
Cash From (Used in) Investing Activities		(1,316)	(1,308)	(4,039)	(3,613)
Net Cash Provided (Used) Before Financing Activities		815	1,166	1,781	3,593
Financing Activities	21
Net Issuance (Repayment) of Short-Term Borrowings		86	(35)	152	(74)
Repayment of Long-Term Debt	12	(183)	—	(195)	—
Principal Repayment of Leases	11	(89)	(74)	(266)	(219)
Net Proceeds (Repayment) on Repurchase Agreements		(45)	—	183	—
Common Shares Issued Under Stock Option Plans		5	1	12	51
Purchase of Common Shares Under NCIB	15	(918)	(732)	(1,281)	(1,337)
Purchase of Common Shares Under Employee Benefit Plan	15	(21)	—	(94)	—
Redemption of Preferred Shares	15	—	—	(350)	—
Proceeds From Exercise of Warrants		2	8	5	25
Dividends Paid	7	(356)	(338)	(1,057)	(1,203)
Other		—	(5)	—	(7)
Cash From (Used in) Financing Activities		(1,519)	(1,175)	(2,891)	(2,764)
Effect of Foreign Exchange on Cash and Cash Equivalents		42	(41)	(82)	48
Increase (Decrease) in Cash and Cash Equivalents		(662)	(50)	(1,192)	877
Cash and Cash Equivalents, Beginning of Period		2,563	3,154	3,093	2,227
Cash and Cash Equivalents, End of Period		1,901	3,104	1,901	3,104

See accompanying Notes to the interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	6

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 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 and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1 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 interim Consolidated Financial Statements is found in Note 2.

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin.

The Company operates through the following reportable segments:

Upstream Segments

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

Downstream Segments

Corporate and Eliminations

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	7

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

A) Results of Operations – Segment and Operational Information

	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2025	2024	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales	5,177	5,456	212	225	385	371	5,774	6,052
Intersegment Sales	1,571	1,719	217	488	—	—	1,788	2,207
	6,748	7,175	429	713	385	371	7,562	8,259
Royalties	(831)	(889)	(12)	(15)	(15)	(25)	(858)	(929)
Revenues	5,917	6,286	417	698	370	346	6,704	7,330
Expenses
Purchased Product	507	629	161	459	6	—	674	1,088
Transportation and Blending	2,452	2,579	86	80	5	2	2,543	2,661
Operating	655	621	127	147	103	92	885	860
Realized (Gain) Loss on Risk<br> Management	10	(10)	2	—	—	—	12	(10)
Operating Margin	2,293	2,467	41	12	256	252	2,590	2,731
Unrealized (Gain) Loss on Risk<br><br>Management	(12)	(1)	(6)	2	—	—	(18)	1
Depreciation, Depletion and<br> Amortization	867	784	125	109	106	134	1,098	1,027
Exploration Expense	1	2	—	—	—	42	1	44
(Income) Loss From Equity-<br> Accounted Affiliates	—	—	—	—	(9)	(11)	(9)	(11)
Segment Income (Loss)	1,437	1,682	(78)	(99)	159	87	1,518	1,670	Downstream
---	---	---	---	---	---	---
	Canadian Refining		U.S. Refining		Total
For the three months ended September 30,	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales (1)	1,198	1,482	7,081	7,214	8,279	8,696
Intersegment Sales	155	98	1	4	156	102
	1,353	1,580	7,082	7,218	8,435	8,798
Royalties	—	—	—	—	—	—
Revenues (1)	1,353	1,580	7,082	7,218	8,435	8,798
Expenses
Purchased Product (1)	1,102	1,353	6,219	6,854	7,321	8,207
Transportation and Blending	—	—	—	—	—	—
Operating	140	167	611	751	751	918
Realized (Gain) Loss on Risk Management	—	—	(1)	(4)	(1)	(4)
Operating Margin	111	60	253	(383)	364	(323)
Unrealized (Gain) Loss on Risk Management	—	—	3	5	3	5
Depreciation, Depletion and Amortization	40	49	160	115	200	164
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	71	11	90	(503)	161	(492)

(1)Comparative period reflects certain revisions. See Note 23.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	8

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025


For the three months ended September 30,	2025	2024	2025	2024
Gross Sales
External Sales (1)		—	—	14,053	14,748
Intersegment Sales		(1,944)	(2,309)	—	—
		(1,944)	(2,309)	14,053	14,748
Royalties		—	—	(858)	(929)
Revenues (1)		(1,944)	(2,309)	13,195	13,819
Expenses
Purchased Product (1)		(1,855)	(2,169)	6,140	7,126
Transportation and Blending		(138)	(172)	2,405	2,489
Purchased Product, Transportation and Blending (1)		(1,993)	(2,341)	8,545	9,615
Operating		(42)	(42)	1,594	1,736
Realized (Gain) Loss on Risk Management		6	(13)	17	(27)
Unrealized (Gain) Loss on Risk Management		(4)	1	(19)	7
Depreciation, Depletion and Amortization		24	27	1,322	1,218
Exploration Expense		—	—	1	44
(Income) Loss From Equity-Accounted Affiliates		—	—	(9)	(11)
Segment Income (Loss)		65	59	1,744	1,237
General and Administrative		220	172	220	172
Finance Costs, Net		154	118	154	118
Integration, Transaction and Other Costs		44	41	44	41
Foreign Exchange (Gain) Loss, Net		157	(73)	157	(73)
(Gain) Loss on Divestiture of Assets		(106)	(17)	(106)	(17)
Other (Income) Loss, Net		(22)	(28)	(22)	(28)
		447	213	447	213
Earnings (Loss) Before Income Tax				1,297	1,024
Income Tax Expense (Recovery)				11	204
Net Earnings (Loss)				1,286	820

(1)Comparative period reflects certain revisions. See Note 23.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	9

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

	Upstream
For the nine months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2025	2024	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales	15,874	16,525	936	866	1,171	1,199	17,981	18,590
Intersegment Sales	5,241	4,831	986	1,417	—	—	6,227	6,248
	21,115	21,356	1,922	2,283	1,171	1,199	24,208	24,838
Royalties	(2,281)	(2,400)	(44)	(61)	(60)	(74)	(2,385)	(2,535)
Revenues	18,834	18,956	1,878	2,222	1,111	1,125	21,823	22,303
Expenses
Purchased Product	1,995	1,321	951	1,353	6	—	2,952	2,674
Transportation and Blending	8,138	8,265	259	241	14	9	8,411	8,515
Operating	2,032	1,896	369	432	273	319	2,674	2,647
Realized (Gain) Loss on Risk<br> Management	10	23	1	(7)	—	—	11	16
Operating Margin	6,659	7,451	298	203	818	797	7,775	8,451
Unrealized (Gain) Loss on Risk<br><br>Management	(3)	(13)	(7)	10	—	—	(10)	(3)
Depreciation, Depletion and<br> Amortization	2,450	2,330	362	330	329	421	3,141	3,081
Exploration Expense	7	6	—	—	2	50	9	56
(Income) Loss From Equity-<br> Accounted Affiliates	(38)	(14)	1	1	(24)	(34)	(61)	(47)
Segment Income (Loss)	4,243	5,142	(58)	(138)	511	360	4,696	5,364	Downstream
---	---	---	---	---	---	---
	Canadian Refining		U.S. Refining		Total
For the nine months ended September 30,	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales (1)	3,259	3,682	19,958	21,727	23,217	25,409
Intersegment Sales	664	365	2	7	666	372
	3,923	4,047	19,960	21,734	23,883	25,781
Royalties	—	—	—	—	—	—
Revenues (1)	3,923	4,047	19,960	21,734	23,883	25,781
Expenses
Purchased Product (1)	3,218	3,415	18,063	19,473	21,281	22,888
Transportation and Blending	—	—	—	—	—	—
Operating	419	759	2,133	2,045	2,552	2,804
Realized (Gain) Loss on Risk Management	—	—	(6)	5	(6)	5
Operating Margin	286	(127)	(230)	211	56	84
Unrealized (Gain) Loss on Risk Management	—	—	(5)	3	(5)	3
Depreciation, Depletion and Amortization	139	147	467	338	606	485
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	147	(274)	(692)	(130)	(545)	(404)

(1)Comparative period reflects certain revisions. See Note 23.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	10

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

	Corporate and Eliminations		Consolidated
For the nine months ended September 30,	2025	2024	2025	2024
Gross Sales
External Sales (1)	—	—	41,198	43,999
Intersegment Sales	(6,893)	(6,620)	—	—
	(6,893)	(6,620)	41,198	43,999
Royalties	—	—	(2,385)	(2,535)
Revenues (1)	(6,893)	(6,620)	38,813	41,464
Expenses
Purchased Product (1)	(6,133)	(5,756)	18,100	19,806
Transportation and Blending	(555)	(586)	7,856	7,929
Purchased Product, Transportation and Blending (1)	(6,688)	(6,342)	25,956	27,735
Operating	(255)	(237)	4,971	5,214
Realized (Gain) Loss on Risk Management	(19)	(10)	(14)	11
Unrealized (Gain) Loss on Risk Management	(50)	31	(65)	31
Depreciation, Depletion and Amortization	73	80	3,820	3,646
Exploration Expense	—	—	9	56
(Income) Loss From Equity-Accounted Affiliates	16	(1)	(45)	(48)
Segment Income (Loss)	30	(141)	4,181	4,819
General and Administrative	570	593	570	593
Finance Costs, Net	404	394	404	394
Integration, Transaction and Other Costs	123	113	123	113
Foreign Exchange (Gain) Loss, Net	(196)	81	(196)	81
(Gain) Loss on Divestiture of Assets	(109)	(121)	(109)	(121)
Re-measurement of Contingent Payments	—	30	—	30
Other (Income) Loss, Net	(54)	(158)	(54)	(158)
	738	932	738	932
Earnings (Loss) Before Income Tax			3,443	3,887
Income Tax Expense (Recovery)			447	891
Net Earnings (Loss)			2,996	2,996

(1)Comparative period reflects certain revisions. See Note 23.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	11

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

B) External Sales by Product

	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2025	2024	2025	2024	2025	2024	2025	2024
Crude Oil	4,954	5,269	47	33	125	71	5,126	5,373
Natural Gas and Other	80	83	142	107	234	221	456	411
NGLs (1)	143	104	23	85	26	79	192	268
External Sales	5,177	5,456	212	225	385	371	5,774	6,052	Downstream
---	---	---	---	---	---	---
	Canadian Refining		U.S. Refining		Total
For the three months ended September 30,	2025	2024	2025	2024	2025	2024
Gasoline	70	128	3,393	3,513	3,463	3,641
Distillates (2)	366	395	2,792	2,604	3,158	2,999
Synthetic Crude Oil	408	588	—	—	408	588
Asphalt	197	208	321	322	518	530
Other Products and Services (3)	157	163	575	775	732	938
External Sales	1,198	1,482	7,081	7,214	8,279	8,696
	Upstream
---	---	---	---	---	---	---	---	---
For the nine months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2025	2024	2025	2024	2025	2024	2025	2024
Crude Oil	14,718	15,963	156	157	343	263	15,217	16,383
Natural Gas and Other	244	263	609	453	663	686	1,516	1,402
NGLs (1)	912	299	171	256	165	250	1,248	805
External Sales	15,874	16,525	936	866	1,171	1,199	17,981	18,590	Downstream
---	---	---	---	---	---	---
	Canadian Refining		U.S. Refining		Total
For the nine months ended September 30,	2025	2024	2025	2024	2025	2024
Gasoline	181	363	9,706	10,613	9,887	10,976
Distillates (2)	1,068	1,143	7,599	8,149	8,667	9,292
Synthetic Crude Oil	1,214	1,323	—	—	1,214	1,323
Asphalt	397	433	756	753	1,153	1,186
Other Products and Services (3)	399	420	1,897	2,212	2,296	2,632
External Sales	3,259	3,682	19,958	21,727	23,217	25,409

(1)Third-party condensate sales are included within NGLs.

(2)Includes diesel and jet fuel.

(3)Comparative period reflects certain revisions. See Note 23.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	12

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

C) Geographical Information

	Revenues (1)
	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2025	2024	2025	2024
Canada	5,787	6,937	17,359	20,235
United States (2)	7,176	6,606	20,697	20,366
China	232	276	757	863
Consolidated	13,195	13,819	38,813	41,464

(1)Revenues from external customers by country are classified based on the jurisdiction in which the selling entities are located.

(2)Comparative periods reflect certain revisions. See Note 23.

	Non-Current Assets (1)
	September 30,	December 31,
As at	2025	2024
Canada	37,889	37,006
United States	2,538	5,902
China	1,006	1,249
Indonesia	230	295
Consolidated	41,663	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.

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
	September 30,	December 31,	September 30,	December 31,	September 30,	December 31,
As at	2025	2024	2025	2024	2025	2024
Oil Sands	403	461	24,873	24,646	946	1,018
Conventional	20	15	2,213	2,230	47	57
Offshore	7	8	3,950	3,365	187	95
Canadian Refining	—	—	2,457	2,511	54	39
U.S. Refining	—	—	2,259	5,538	290	342
Corporate and Eliminations	—	—	220	278	390	399
Consolidated	430	484	35,972	38,568	1,914	1,950	Goodwill	Total Assets
---	---	---	---	---
	September 30,	December 31,	September 30,	December 31,
As at	2025	2024	2025	2024
Oil Sands	2,923	2,923	31,994	31,668
Conventional	—	—	2,551	2,610
Offshore	—	—	4,633	4,089
Canadian Refining	—	—	2,934	2,901
U.S. Refining	—	—	6,600	9,517
Corporate and Eliminations	—	—	4,861	5,754
Consolidated	2,923	2,923	53,573	56,539
Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	13
---	---

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

E) Capital Expenditures (1)

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2025	2024	2025	2024
Capital Investment
Oil Sands	675	681	2,082	1,941
Conventional	107	106	302	300
Offshore
Atlantic	194	341	674	765
Asia Pacific	23	14	54	44
Total Upstream	999	1,142	3,112	3,050
Canadian Refining	33	44	83	145
U.S. Refining	120	153	343	320
Total Downstream	153	197	426	465
Corporate and Eliminations	2	7	9	22
	1,154	1,346	3,547	3,537
Acquisitions
Oil Sands	7	1	235	7
Conventional	—	3	33	12
	7	4	268	19
Total Capital Expenditures	1,161	1,350	3,815	3,556

(1)Includes expenditures on PP&E, E&E assets and capitalized interest.

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these interim Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These interim 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”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting”. These interim Consolidated Financial Statements were prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2024, except for income taxes. Income taxes on earnings or loss in the interim period are accrued using the income tax rate that would be applicable to the expected annual earnings or loss.

Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements were condensed. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2024, which were prepared in accordance with IFRS Accounting Standards.

These interim Consolidated Financial Statements were approved by the Board of Directors effective October 30, 2025.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	14

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

3. FINANCE COSTS, NET
	Three Months Ended		Nine Months Ended
---	---	---	---	---
For the periods ended September 30,	2025	2024	2025	2024
Interest Expense – Short-Term Borrowings and Long-Term Debt	75	76	231	229
Interest Expense – Lease Liabilities (Note 11)	43	40	126	119
Unwinding of Discount on Decommissioning Liabilities (Note 13)	63	56	179	169
Other	24	9	40	30
Capitalized Interest	(23)	(12)	(61)	(30)
Finance Costs	182	169	515	517
Interest Income	(28)	(51)	(111)	(123)
	154	118	404	394
4. FOREIGN EXCHANGE (GAIN) LOSS, NET
---			Three Months Ended		Nine Months Ended
---	---	---	---	---
For the periods ended September 30,	2025	2024	2025	2024
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt	99	(71)	(184)	104
Other	54	(37)	(64)	(3)
Unrealized Foreign Exchange (Gain) Loss	153	(108)	(248)	101
Realized Foreign Exchange (Gain) Loss	4	35	52	(20)
	157	(73)	(196)	81
5. DIVESTITURE
---

On September 30, 2025, the Company divested its entire 50 percent interest in WRB, which was held in the U.S. Refining segment. Proceeds of US$1.3 billion (C$1.8 billion), net of preliminary closing adjustments, were included in accounts receivable and accrued revenues as at September 30, 2025 (see Note 8). The proceeds were received on October 1, 2025.

The before-tax gain of $106 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 16) that was recycled upon divestiture. An associated deferred tax recovery of $315 million was recorded on the divestiture of WRB.

| 6. INCOME TAXES | | --- || | Three Months Ended | | Nine Months Ended | | | --- | --- | --- | --- | --- | | For the periods ended September 30, | 2025 | 2024 | 2025 | 2024 | | Current Tax | | | | | | Canada | 288 | 184 | 791 | 830 | | United States | — | — | — | 2 | | Asia Pacific | 42 | 57 | 144 | 157 | | Other International | 8 | 9 | 32 | 26 | | Total Current Tax Expense (Recovery) | 338 | 250 | 967 | 1,015 | | Deferred Tax Expense (Recovery) | (327) | (46) | (520) | (124) | | | 11 | 204 | 447 | 891 |

For the nine months ended September 30, 2025, the Company recorded a deferred tax recovery, of which $315 million was related to the divestiture of the Company’s 50 percent interest in WRB. See Note 5.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	15

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

7. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Common Share – Basic and Diluted

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2025	2024	2025	2024
Net Earnings (Loss)	1,286	820	2,996	2,996
Effect of Cumulative Dividends on Preferred Shares	(2)	(9)	(12)	(27)
Net Earnings (Loss) – Basic	1,284	811	2,984	2,969
Effect of Stock-Based Compensation	—	(31)	(1)	6
Net Earnings (Loss) – Diluted	1,284	780	2,983	2,975
Basic – Weighted Average Number of Shares (thousands)	1,788,901	1,848,035	1,806,851	1,858,364
Dilutive Effect of Warrants	2,251	3,729	2,416	5,039
Dilutive Effect of Stock-Based Compensation	1,628	11,548	1,819	9,221
Diluted – Weighted Average Number of Shares (thousands)	1,792,780	1,863,312	1,811,086	1,872,624
Net Earnings (Loss) Per Common Share – Basic ($)	0.72	0.44	1.65	1.60
Net Earnings (Loss) Per Common Share – Diluted (1) ($)	0.72	0.42	1.65	1.59

(1)For the three and nine months ended September 30, 2025, 25.1 million and 24.6 million, respectively (2024 — 3.0 million and 11.5 million, respectively) common shares 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 nine months ended September 30,	Per Share	Amount	Per Share	Amount
Base Dividends	0.580	1,047	0.500	925
Variable Dividends	—	—	0.135	251
Total Common Share Dividends Declared and Paid	0.580	1,047	0.635	1,176

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

On October 30, 2025, the Company’s Board of Directors declared a fourth quarter base dividend of $0.200 per common share, payable on December 31, 2025, to common shareholders of record as at December 15, 2025.

C) Preferred Share Dividends

For the nine months ended September 30,	2025	2024
Series 1 First Preferred Shares	5	5
Series 2 First Preferred Shares	1	2
Series 3 First Preferred Shares	—	9
Series 5 First Preferred Shares	2	7
Series 7 First Preferred Shares	4	4
Total Preferred Share Dividends Declared	12	27

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

For the nine months ended September 30, 2025, the Company paid preferred share dividends of $10 million (2024 – $27 million).

On October 30, 2025, the Company’s Board of Directors declared fourth quarter preferred share dividends of $2 million payable on December 31, 2025, to preferred shareholders of record as at December 15, 2025.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	16

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

| 8. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES | | --- || | September 30, | December 31, | | --- | --- | --- | | As at | 2025 | 2024 | | Trade and Accruals | 2,496 | 2,378 | | Divestiture Proceeds Receivable (Note 5) | 1,816 | — | | Prepaids and Deposits | 259 | 187 | | Joint Operations Receivables | 34 | 40 | | Other | 83 | 9 | | | 4,688 | 2,614 | | 9. EXPLORATION AND EVALUATION ASSETS, NET | | --- || | Total | | --- | --- | | As at December 31, 2024 | 484 | | Additions | 59 | | Transfer to PP&E (Note 10) | (112) | | Exchange Rate Movements and Other | (1) | | As at September 30, 2025 | 430 | | 10. 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, 2024 | 52,090 | 280 | 14,325 | 1,975 | 68,670 | | Acquisitions | 268 | — | — | — | 268 | | Additions | 3,053 | 4 | 413 | 18 | 3,488 | | Transfer from E&E (Note 9) | 112 | — | — | — | 112 | | Change in Decommissioning Liabilities | 412 | — | — | — | 412 | | Divestitures (Note 5) | (5) | — | (7,243) | (6) | (7,254) | | Exchange Rate Movements and Other | (450) | (9) | (416) | (23) | (898) | | As at September 30, 2025 | 55,480 | 275 | 7,079 | 1,964 | 64,798 | | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | | | | | | | As at December 31, 2024 | 21,849 | 141 | 6,675 | 1,437 | 30,102 | | Depreciation, Depletion and Amortization | 2,993 | 9 | 507 | 61 | 3,570 | | Divestitures (Note 5) | (1) | — | (4,195) | — | (4,196) | | Exchange Rate Movements and Other | (397) | (8) | (239) | (6) | (650) | | As at September 30, 2025 | 24,444 | 142 | 2,748 | 1,492 | 28,826 | | CARRYING VALUE | | | | | | | As at December 31, 2024 | 30,241 | 139 | 7,650 | 538 | 38,568 | | As at September 30, 2025 | 31,036 | 133 | 4,331 | 472 | 35,972 |

(1)Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	17

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

11. 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, 2024	592	2,392	178	125	3,287
Additions	4	144	—	16	164
Divestitures (Note 5)	(1)	(175)	(23)	(9)	(208)
Exchange Rate Movements and Other	2	(30)	(4)	(2)	(34)
As at September 30, 2025	597	2,331	151	130	3,209
ACCUMULATED DEPRECIATION
As at December 31, 2024	193	999	94	51	1,337
Depreciation	27	190	7	26	250
Divestitures (Note 5)	(1)	(144)	(8)	(9)	(162)
Exchange Rate Movements and Other	—	(123)	(3)	(4)	(130)
As at September 30, 2025	219	922	90	64	1,295
CARRYING VALUE
As at December 31, 2024	399	1,393	84	74	1,950
As at September 30, 2025	378	1,409	61	66	1,914

(1)Includes a pipeline, storage tanks, railcars, vessels, barges, a natural gas processing plant and caverns.

(2)Includes assets in the commercial fuels business, fleet vehicles, camps and other equipment.

B) Lease Liabilities

	Total
As at December 31, 2024	2,927
Additions	162
Interest Expense (Note 3)	126
Lease Payments	(392)
Divestitures (Note 5)	(39)
Exchange Rate Movements and Other	88
As at September 30, 2025	2,872
Less: Current Portion	342
Long-Term Portion	2,530
12. DEBT AND CAPITAL STRUCTURE
---

A) Short-Term Borrowings

		September 30,	December 31,
As at	Notes	2025	2024
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	—	173
Total Debt Principal		—	173

i) Uncommitted Demand Facilities

As at September 30, 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 September 30, 2025, there were outstanding letters of credit aggregating to $338 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	18

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

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 5). 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

	September 30,	December 31,
As at	2025	2024
Committed Credit Facility	—	—
U.S. Dollar Denominated Unsecured Notes (1)	5,107	5,470
Canadian Dollar Unsecured Notes	2,000	2,000
Total Debt Principal	7,107	7,470
Debt Premiums (Discounts), Net, and Transaction Costs	49	64
Long-Term Debt	7,156	7,534
Less: Current Portion	—	192
Long-Term Portion	7,156	7,342

(1)Total U.S. dollar denominated unsecured notes as at September 30, 2025, was US$3.7 billion (December 31, 2024 — US$3.8 billion).

The committed credit facility may include Canadian overnight repo rate average loans, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

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

As at September 30, 2025, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is below this limit.

C) 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 depreciation, depletion and amortization (“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 West Texas Intermediate (“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.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	19

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

Net Debt to Adjusted EBITDA

	September 30,	December 31,
As at	2025	2024
Short-Term Borrowings	—	173
Current Portion of Long-Term Debt	—	192
Long-Term Portion of Long-Term Debt	7,156	7,342
Total Debt	7,156	7,707
Less: Cash and Cash Equivalents	(1,901)	(3,093)
Net Debt	5,255	4,614
Net Earnings (Loss)	3,142	3,142
Add (Deduct):
Finance Costs, Net	524	514
Income Tax Expense (Recovery)	485	929
Depreciation, Depletion and Amortization	5,045	4,871
Exploration and Evaluation Asset Write-downs	(3)	37
(Income) Loss From Equity-Accounted Affiliates	(63)	(66)
Unrealized (Gain) Loss on Risk Management	(84)	12
Foreign Exchange (Gain) Loss, Net	185	462
(Gain) Loss on Divestiture of Assets	(107)	(119)
Re-measurement of Contingent Payments	—	30
Other (Income) Loss, Net	49	(55)
Adjusted EBITDA (1)	9,173	9,757
Net Debt to Adjusted EBITDA (times)	0.6	0.5

(1)Calculated on a trailing twelve-month basis.

Net Debt to Adjusted Funds Flow

	September 30,	December 31,
As at	2025	2024
Net Debt	5,255	4,614
Cash From (Used in) Operating Activities	7,849	9,235
(Add) Deduct:
Settlement of Decommissioning Liabilities	(262)	(234)
Net Change in Non-Cash Working Capital	313	1,305
Adjusted Funds Flow (1)	7,798	8,164
Net Debt to Adjusted Funds Flow (times)	0.7	0.6

(1)Calculated on a trailing twelve-month basis.

Net Debt to Capitalization

	September 30,	December 31,
As at	2025	2024
Net Debt	5,255	4,614
Shareholders’ Equity	28,374	29,754
Capitalization	33,629	34,368
Net Debt to Capitalization (percent)	16	13
Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	20
---	---

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

| 13. DECOMMISSIONING LIABILITIES | | --- || | Total | | --- | --- | | As at December 31, 2024 | 4,534 | | Liabilities Incurred | 261 | | Liabilities Acquired | 82 | | Liabilities Settled | (198) | | Liabilities Divested (Note 5) | (27) | | Change in Estimated Future Cash Flows | 151 | | Unwinding of Discount on Decommissioning Liabilities (Note 3) | 179 | | Exchange Rate Movements | (9) | | As at September 30, 2025 | 4,973 |

As at September 30, 2025, the undiscounted amount of estimated future cash flows required to settle the obligation was discounted using a credit-adjusted risk-free rate of 5.2 percent (December 31, 2024 – 5.2 percent) and assumes an inflation rate of two percent (December 31, 2024 – two percent).

| 14. OTHER LIABILITIES | | --- || | September 30, | December 31, | | --- | --- | --- | | As at | 2025 | 2024 | | Renewable Volume Obligation, Net (1) | 336 | 284 | | Pension and Other Post-Employment Benefit Plan | 264 | 269 | | Employee Long-Term Incentives | 117 | 96 | | Provisions for Onerous and Unfavourable Contracts | 60 | 66 | | Provision for West White Rose Expansion Project | — | 54 | | Other | 148 | 150 | | | 925 | 919 |

(1)The gross amounts of the renewable volume obligation and renewable identification numbers asset were $1.1 billion and $804 million, respectively (December 31, 2024 – $652 million and $368 million, respectively).

15. 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

	September 30, 2025		December 31, 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 Stock Option Plans	1,090	15	5,049	68
Purchase of Common Shares Under NCIB	(60,537)	(519)	(55,861)	(479)
Issued Upon Exercise of Warrants	738	7	3,982	39
Outstanding, End of Period	1,766,329	15,162	1,825,038	15,659

As at September 30, 2025, there were 24.9 million common shares available for future issuance under the stock option plan.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	21

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

C) Normal Course Issuer Bid

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

For the nine months ended September 30, 2025, the Company purchased and cancelled 60.5 million common shares through the NCIB. The shares were purchased at a volume weighted average price of $20.75 per common share for a total of $1.3 billion. Paid in surplus representing the retained earnings prior to the split with Encana Corporation, now known as Ovintiv Inc., was reduced in full by $541 million. Retained earnings was then reduced by $221 million. The cumulative reduction to shareholder’s equity was $762 million, of which $737 million represents the excess of the purchase price of the common shares over their average carrying value and $25 million relates to share buyback tax.

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.

	September 30, 2025		December 31, 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	—	—
Purchased Under Employee Benefit Plan	4,600	94	2,000	43
Distributed Under Employee Benefit Plan	(3,822)	(82)	—	—
Outstanding, End of Period	2,778	55	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

	September 30, 2025		December 31, 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 Period	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 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.

As at September 30, 2025	Dividend Reset Date	Dividend Rate (percent)	Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	10,740
Series 2 First Preferred Shares (1)	Quarterly	4.39	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, and 4.37 percent from June 30, 2025 to September 29, 2025.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	22

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

F) Issued and Outstanding – Warrants

	September 30, 2025		December 31, 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	(738)	(2)	(3,982)	(13)
Outstanding, End of Period	2,905	10	3,643	12

The exercise price of the warrants is $6.54 per share. The warrants expire on January 1, 2026.

| 16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | | --- || | Pension and Other Post-Employment Benefits | Private Equity Investments | Foreign Currency Translation Adjustment | Total | | --- | --- | --- | --- | --- | | As at December 31, 2023 | 55 | 85 | 1,068 | 1,208 | | Other Comprehensive Income (Loss), Before Tax | 14 | 139 | 219 | 372 | | Income Tax (Expense) Recovery | (3) | (16) | — | (19) | | As at September 30, 2024 | 66 | 208 | 1,287 | 1,561 | | As at December 31, 2024 | 69 | 156 | 2,088 | 2,313 | | Other Comprehensive Income (Loss), Before Tax | 13 | (26) | (420) | (433) | | Reclassification on Divestiture (Note 5) | — | — | (1,261) | (1,261) | | Income Tax (Expense) Recovery | (3) | 3 | — | — | | As at September 30, 2025 | 79 | 133 | 407 | 619 | | 17. 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. As at September 30, 2025, no Cenovus replacement stock options were outstanding.

The following tables summarize information related to the Company’s stock-based compensation plans:

	Units<br><br>Outstanding	Units<br><br>Exercisable
As at September 30, 2025	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	11,171	5,190
Performance Share Units	7,542	—
Restricted Share Units	10,052	—
Deferred Share Units	2,006	2,006

The weighted average exercise price of NSRs outstanding as at September 30, 2025, was $19.22.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	23

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

	Units<br><br>Granted	Units<br><br>Vested and<br><br>Exercised/<br><br>Paid Out
For the nine months ended September 30, 2025	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	4,384	1,080
Cenovus Replacement Stock Options	—	329
Performance Share Units	3,357	2,303
Restricted Share Units	4,353	1,955
Deferred Share Units	358	169
	Weighted Average Exercise Price	Units<br><br>Exercised
---	---	---
For the nine months ended September 30, 2025	($/unit)	(thousands)
Stock Options With Associated Net Settlement Rights Exercised for Net Cash Payment	12.14	752
Stock Options With Associated Net Settlement Rights Exercised and Net Settled for Common Shares (1)	9.48	328
Cenovus Replacement Stock Options Exercised and Net Settled for Cash	3.54	317
Cenovus Replacement Stock Options Exercised and Net Settled for Common Shares (2)	3.54	12

(1)NSRs were net settled for 328 thousand common shares.

(2)Cenovus replacement stock options were net settled for 10 thousand common shares.

The following table summarizes the stock-based compensation expense (recovery) recorded for all plans:

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2025	2024	2025	2024
Stock Options With Associated Net Settlement Rights	2	2	8	9
Cenovus Replacement Stock Options	—	(2)	(1)	1
Performance Share Units	24	(4)	39	57
Restricted Share Units	40	(2)	61	50
Deferred Share Units	11	(6)	10	6
Stock-Based Compensation Expense (Recovery)	77	(12)	117	123

PSUs and RSUs granted under the Performance Share Unit Plan and Restricted Share Unit Plan for Local Employees in the Asia Pacific region may only be settled in cash.

18. RELATED PARTY TRANSACTIONS

Husky Midstream Limited Partnership

The following table summarizes revenues and associated expenses related to HMLP:

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2025	2024	2025	2024
Revenues from Construction and Management Services	50	47	116	116
Transportation Expenses	66	67	203	207
Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	24
---	---

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

19. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, long-term debt, certain portions of other assets and certain portions of other liabilities. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of restricted cash, 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 September 30, 2025, the carrying value of Cenovus’s long-term debt was $7.2 billion and the fair value was $6.7 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:

	Total
As at December 31, 2024	219
Acquisitions	2
Transfer to Investments in Equity-Accounted Affiliates	(5)
Changes in Fair Value	(26)
As at September 30, 2025	190

B) Fair Value of Risk Management Assets and Liabilities

Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable and accrued liabilities (for short-term positions), other assets and other liabilities (for long-term positions). Changes in fair value are recorded in (gain) loss on risk management.

The Company’s risk management assets and liabilities consist of condensate and refined product futures; crude oil and natural gas futures and swaps; and renewable power, power and foreign exchange contracts. The Company may also enter into forwards and options to manage commodity, foreign exchange and interest rate exposures.

Crude oil, natural gas, condensate, refined products and power contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity, extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable market data and foreign exchange forward curves (Level 2).

The fair value of renewable power contracts is calculated using internal valuation models that incorporate broker pricing for relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair value of renewable power contracts are calculated by Cenovus’s internal valuation team, which consists of individuals who are knowledgeable and have experience in fair value techniques.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	25

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

Summary of Risk Management Positions

	September 30, 2025			December 31, 2024
	Risk Management			Risk Management
As at	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Condensate, Natural Gas, and Refined Products	9	1	8	9	10	(1)
Power Contracts	3	—	3	6	—	6
Renewable Power Contracts	61	4	57	5	—	5
Foreign Exchange Rate Contracts	—	4	(4)	—	3	(3)
	73	9	64	20	13	7

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

	September 30,	December 31,
As at	2025	2024
Level 2 – Prices Sourced From Observable Data or Market Corroboration	7	2
Level 3 – Prices Sourced From Partially Unobservable Data	57	5
	64	7

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

	Total
As at December 31, 2024	7
Change in Fair Value of Contracts in Place, Beginning of Year	57
Change in Fair Value of Contracts Entered Into During the Period	14
Fair Value of Contracts Realized During the Period	(14)
As at September 30, 2025	64

C) Earnings Impact of (Gains) Losses From Risk Management Positions

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2025	2024	2025	2024
Realized (Gain) Loss	17	(27)	(14)	11
Unrealized (Gain) Loss	(19)	7	(65)	31
(Gain) Loss on Risk Management	(2)	(20)	(79)	42

Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	26

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

20. 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.

As at September 30, 2025, the fair value of risk management positions was a net asset of $64 million. As at September 30, 2025, there were foreign exchange contracts with a notional value of US$550 million (December 31, 2024 – US$250 million). As at September 30, 2025, and December 31, 2024, there were no outstanding interest rate contracts or cross currency interest rate swap contracts.

Net Fair Value of Risk Management Positions

As at September 30, 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	6.4 MMbbls	October 2025 - December 2026	US$63.00/bbl	10
WTI Fixed – Buy	0.2 MMbbls	October 2025 - December 2026	US$61.15/bbl	—
Power Contracts				3
Renewable Power Contracts				57
Other Financial Positions (4)				(2)
Foreign Exchange Rate Contracts				(4)
Total Fair Value				64

(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 15 months.

(4) Includes risk management positions related to Western Canadian Select (“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

Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at September 30, 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	(6)	6
WCS (Hardisty) Differential Price	± US$2.50/bbl Applied to WCS Differential Hedges Tied to Production	—	—
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	—	—
Natural Gas Commodity Price	± US$0.50/Mcf (2) Applied to Natural Gas Hedges Tied to Production	1	(1)
Natural Gas Basis Price	± US$0.25/Mcf Applied to Natural Gas Basis Hedges	—	—
Power Commodity Price	± C$10.00/MWh (3) Applied to Power Hedges	42	(42)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	45	(52)

(1)Excluding WCS at Hardisty.

(2)One thousand cubic feet (“Mcf”).

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

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	27

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

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 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.

As at September 30, 2025, approximately 73 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 on these accounts was 0.3 percent as at September 30, 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 12, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and a 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.

Undiscounted cash outflows relating to financial liabilities are:

As at September 30, 2025	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	5,216	—	—	—	5,216
Lease Liabilities (1)	490	860	643	2,444	4,437
Long-Term Debt (1)	316	3,066	688	6,902	10,972

(1)Principal and interest, including current portion, if applicable.

21. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital

	September 30,	December 31,
As at	2025	2024
Total Current Assets	9,769	10,434
Total Current Liabilities	5,651	7,362
Working Capital	4,118	3,072

B) Changes in Non-Cash Working Capital

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2025 (1)	2024	2025 (1)	2024
Accounts Receivable and Accrued Revenues	(177)	904	(542)	326
Income Tax Receivable	6	14	172	191
Inventories	(19)	480	421	99
Accounts Payable and Accrued Liabilities	(188)	(896)	(186)	60
Income Tax Payable	(22)	105	(304)	96
Total Change in Non-Cash Working Capital	(400)	607	(439)	772
Net Change in Non-Cash Working Capital – Operating Activities	(241)	588	(179)	813
Net Change in Non-Cash Working Capital – Investing Activities	(159)	19	(260)	(41)
Total Change in Non-Cash Working Capital	(400)	607	(439)	772

(1)Excludes the impact of the divestiture of WRB, including proceeds recorded in accounts receivable and accrued revenues (see Note 5). Proceeds from divestitures are recorded using the direct method for investing activities.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	28

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

C) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable	Repurchase Agreements Payable	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	—	—	(74)	—	—
Principal Repayment of Leases	—	—	—	—	(219)
Dividends Paid	(1,203)	—	—	—	—
Non-Cash Changes:
Finance and Transaction Costs	—	—	—	(13)	—
Lease Additions	—	—	—	—	104
Base Dividends Declared on Common Shares	925	—	—	—	—
Variable Dividends Declared on Common Shares	251	—	—	—	—
Dividends Declared on Preferred Shares	27	—	—	—	—
Exchange Rate Movements and Other	—	—	(4)	104	97
As at September 30, 2024	9	—	101	7,199	2,640
As at December 31, 2024	—	—	173	7,534	2,927
Acquisition	—	—	—	12	—
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	152	—	—
Repayment of Long-Term Debt	—	—	—	(195)	—
Principal Repayment of Leases	—	—	—	—	(266)
Proceeds on Repurchase Agreements	—	403	—	—	—
Repayment of Repurchase Agreements	—	(220)	—	—	—
Dividends Paid	(1,057)	—	—	—	—
Non-Cash Changes:
Divestiture of Short-Term Borrowings	—	—	(313)	—	—
Finance and Transaction Costs	—	—	—	(15)	—
Lease Additions	—	—	—	—	162
Lease Divestitures	—	—	—	—	(39)
Base Dividends Declared on Common Shares	1,047	—	—	—	—
Dividends Declared on Preferred Shares	12	—	—	—	—
Exchange Rate Movements and Other	—	(7)	(12)	(180)	88
As at September 30, 2025	2	176	—	7,156	2,872
Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	29
---	---

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

22. 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 September 30, 2025	Remainder of Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	523	2,030	2,047	2,070	2,017	15,684	24,371
Real Estate	16	64	61	59	62	532	794
Obligation to Fund HCML	25	101	95	55	43	102	421
Other Long-Term Commitments	427	184	184	148	117	595	1,655
Total Commitments	991	2,379	2,387	2,332	2,239	16,913	27,241

(1)Includes transportation commitments that are subject to regulatory approval or were approved but are not yet in service of $1.5 billion. Terms are up to 15 years on commencement.

(2)As at September 30, 2025, includes $1.7 billion related to transportation and storage commitments with HMLP.

There were outstanding letters of credit aggregating to $338 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 interim 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.

23. PRIOR PERIOD REVISIONS

In December 2024, it was identified that certain transactions in the U.S. Refining segment were reported on a gross basis in revenues and purchased product rather than on a net basis. As a result, revenues and purchased product were overstated for the three and nine months ended September 30, 2024. The prior periods were revised to reflect the change. There was no impact on net earnings (loss), segment income (loss), cash flows or financial position.

The following tables reconcile the amounts previously reported in the Consolidated Statements of Comprehensive Income (Loss) and segmented disclosures to the corresponding revised amounts:

	U.S. Refining Segment			Consolidated
For the three months ended <br>September 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,648	(430)	7,218	14,249	(430)	13,819
Purchased Product	7,284	(430)	6,854	7,556	(430)	7,126
Transportation and Blending	—	—	—	2,489	—	2,489
Purchased Product, Transportation <br> and Blending	7,284	(430)	6,854	10,045	(430)	9,615
	364	—	364	4,204	—	4,204
Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	30
---	---

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2025

	U.S. Refining Segment			Consolidated
For the nine months ended <br>September 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	22,801	(1,067)	21,734	42,531	(1,067)	41,464
Purchased Product	20,540	(1,067)	19,473	20,873	(1,067)	19,806
Transportation and Blending	—	—	—	7,929	—	7,929
Purchased Product, Transportation <br> and Blending	20,540	(1,067)	19,473	28,802	(1,067)	27,735
	2,261	—	2,261	13,729	—	13,729
24. SUBSEQUENT EVENTS
---

A) MEG Energy Corp. Acquisition

On August 21, 2025, Cenovus entered into a definitive agreement to acquire all of the issued and outstanding shares of MEG Energy Corp. (“MEG”) through a plan of arrangement (the “MEG Acquisition”). Cenovus obtained fully committed financing of a $2.7 billion three-year term loan and a $2.5 billion bridge facility to fund the cash consideration portion of the MEG Acquisition. No amounts were outstanding on the term loan and bridge facility as at September 30, 2025.

From October 8, 2025, to October 15, 2025, the Company acquired an aggregate of 25.0 million common shares of MEG for $752 million.

On October 26, 2025, Cenovus entered into a second amending agreement (“Amended Agreement”). Under the terms of the Amended Agreement, Cenovus will acquire all the issued and outstanding common shares of MEG in exchange for cash consideration of $3.8 billion and 159.6 million Cenovus common shares.

The MEG Acquisition is subject to shareholder, court and other customary approvals.

B) Asset Disposition

On October 26, 2025, Cenovus entered into an agreement to dispose of certain Lloydminster thermal assets in the Oil Sands segment for total proceeds of up to $150 million, comprised of $75 million cash paid on closing and up to $75 million in variable consideration. The disposition is expected to close in the fourth quarter of 2025, subject to closing conditions.

Cenovus Energy Inc. – Q3 2025 Interim Consolidated Financial Statements	31

Document

Exhibit 99.4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Jonathan M. McKenzie, President & Chief Executive Officer of Cenovus Energy Inc., certify the following:

1.Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Cenovus Energy Inc. (the “issuer”) for the interim period ended September 30, 2025.

2.No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3.Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4.Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)designed ICFR, or caused it 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 the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework.

5.2 ICFR - material weakness relating to design: N/A

5.3 Limitation on scope of design: N/A

Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2025 and ended on September 30, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: October 31, 2025

/s/ Jonathan M. McKenzie

Jonathan M. McKenzie

President & Chief Executive Officer

Document

Exhibit 99.5

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer of Cenovus Energy Inc., certify the following:

5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

5.2 ICFR - material weakness relating to design: N/A

5.3 Limitation on scope of design: N/A

Date: October 31, 2025

/s/ Karamjit S. Sandhar

Karamjit S. Sandhar

Executive Vice-President & Chief Financial Officer