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6-K 1 form6-kq22025.htm 6-K Document

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 July 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: July 31, 2025

CENOVUS ENERGY INC.

(Registrant)

By:

/s/ Christine D. Lee

Name:

Christine D. Lee

Title:

Assistant Corporate Secretary

Form 6-K Exhibit Index


Exhibit No.

99.1						News Release dated July 31, 2025

99.2						Management’s Discussion and Analysis dated July 30, 2025 for the period ended June 30, 2025

99.3						Interim Consolidated Financial Statements (unaudited) for the period ended June 30, 2025

99.4						Form 52-109F2 Full Certificate, dated July 31, 2025, of Jonathan M. McKenzie, President & Chief Executive Officer

99.5						Form 52-109F2 Full Certificate, dated July 31, 2025, of Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer

EX-99.1 2 q22025newsrelease.htm EX-99.1 Document


						Exhibit 99.1

News release

Cenovus announces second-quarter 2025 results

Calgary, Alberta (July 31, 2025) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) today announced its second-quarter 2025 financial and operating results. The company generated approximately $2.4 billion in cash from operating activities, $1.5 billion of adjusted funds flow and $355 million of free funds flow. Total upstream production was 765,900 barrels of oil equivalent per day (BOE/d)1, reflecting planned turnarounds at the Foster Creek and Sunrise oil sands assets, maintenance at offshore facilities and short-term production impacts from wildfire activity at Christina Lake. Downstream crude throughput was 665,800 barrels per day (bbls/d), representing an overall utilization rate of 92% and including the successful completion of a turnaround at the Toledo Refinery 11 days ahead of schedule.

Highlights

•Achieved first oil at Narrows Lake in July, with production expected to ramp up to peak incremental rates of 20,000 bbls/d - 30,000 bbls/d by the end of the year.

•Delivered major milestones on the West White Rose project, with the concrete gravity structure (CGS) installed on the seabed in June and the topsides placed atop the CGS in mid-July. Hookup and commissioning work has commenced, with drilling expected to begin by year end.

•Advanced the Foster Creek optimization project, with four new boilers brought online in July, which will add approximately 80,000 bbls/d of steam capacity to the facility.

•Completed major turnarounds at Toledo, Sunrise and Foster Creek in the quarter, with exceptional execution, resulting in production at all assets resuming ahead of schedule.

•Returned $819 million to shareholders, including $301 million through common share purchases, $368 million through common and preferred share dividends and $150 million through the redemption of Cenovus’s Series 7 preferred shares on June 30, 2025.

“Operating performance this quarter was exceptional, with turnaround execution exceeding our targets, major project milestones achieved on time and on budget, and our staff safely and efficiently restoring Christina Lake production following disruption from a wildfire,” said Jon McKenzie, Cenovus President & Chief Executive Officer. “Through the hard work and determination of our people, we have arrived at an inflection point, nearing completion of numerous growth projects and successfully concluding significant maintenance events. As investment in these initiatives is completed, we expect to generate increasing free funds flow.”

Financial summary


($ millions, except per share amounts)	2025 Q2	2025 Q1	2024 Q2
Cash from (used in) operating activities	2,374	1,315	2,807
Adjusted funds flow2	1,519	2,212	2,361
Per share (diluted)2	0.84	1.21	1.26
Capital investment	1,164	1,229	1,155
Free funds flow2	355	983	1,206
Excess free funds flow2	(306)	373	735
Net earnings (loss)	851	859	1,000
Per share (diluted)	0.45	0.47	0.53
Long-term debt, including current portion	7,241	7,524	7,275
Net debt	4,934	5,079	4,258

CENOVUS ENERGY NEWS RELEASE | 1

Production and throughput













(before royalties, net to Cenovus)	2025 Q2	2025 Q1	2024 Q2
Oil and NGLs (bbls/d)1	624,000	670,900	656,300
Conventional natural gas (MMcf/d)	851.4	887.9	867.2
Total upstream production (BOE/d)1	765,900	818,900	800,800
Total downstream crude throughput (bbls/d)	665,800	665,400	622,700

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.

Second-quarter results

Operating1

Cenovus’s total revenues were $12.3 billion in the second quarter, down from $13.3 billion in the first quarter of 2025. Upstream revenues were $6.8 billion, a decrease from $8.3 billion in the previous quarter, while Downstream revenues were $7.7 billion, in line with the previous quarter.

Total operating margin3 was $2.1 billion, compared with $2.8 billion in the previous quarter. Upstream operating margin4 was $2.1 billion, down from $3.0 billion in the first quarter due to lower benchmark oil prices, as well as lower production and sales volumes. The company had a Downstream operating margin4 shortfall of $71 million compared with a shortfall of $237 million in the previous quarter, benefiting from rising U.S. market crack spreads and a higher Canadian upgrading differential, as well as lower run-rate operating costs, excluding turnarounds, in both businesses. Operating margin in the U.S. Refining segment was a shortfall of $178 million, which included a $62 million inventory holding loss and $238 million of turnaround expenses.

Total Upstream production was 765,900 BOE/d in the second quarter, a decrease from 818,900 BOE/d in the first quarter. Christina Lake production was 217,900 bbls/d compared with 237,800 bbls/d in the prior quarter, as a wildfire near the facility temporarily impacted production in the second quarter. The field was shut in on May 29 and operations were restarted safely on June 3, with a return to full production about one week later. Foster Creek production was 186,100 bbls/d compared with 202,700 bbls/d in the first quarter, reflecting planned maintenance during the quarter that was successfully completed with production returning earlier than forecasted. Sunrise production was 50,300 bbls/d compared with 52,100 bbls/d in the first quarter due to planned maintenance at the facility.

Production from the Lloydminster thermal assets was 97,800 bbls/d, a decrease from 109,900 bbls/d in the prior quarter due to an unplanned outage at the Rush Lake facilities in west-central Saskatchewan. The company responded in early May to a steam release from a casing failure in an injection well and as a result, the Rush Lake facilities have been temporarily shut-in. The well has been brought under control, and the company is undertaking an investigation and developing a plan to safely restart production. Lloydminster conventional heavy oil output of 25,000 bbls/d increased from 21,800 bbls/d in the first quarter. Production in the Conventional segment was 119,800 BOE/d, down from 123,900 BOE/d in the previous quarter due in part to third-party outages.

In the Offshore segment, production was 66,300 BOE/d compared with 68,800 BOE/d in the first quarter. In Asia Pacific, production volumes were 53,800 BOE/d, lower than the 57,200 BOE/d in the previous quarter, primarily due to planned maintenance at the Liwan Gas Project. In the Atlantic region, production was 12,500 bbls/d, an increase from 11,600 bbls/d in the prior quarter, due to a full quarter of production from the White Rose field, offset in part by maintenance at the partner-operated Terra Nova field in June.

CENOVUS ENERGY NEWS RELEASE | 2

Total Downstream crude throughput in the second quarter was 665,800 bbls/d, up from 665,400 bbls/d in the first quarter. Crude throughput in Canadian Refining was 112,400 bbls/d, representing a utilization rate of 104%, compared with 111,900 bbls/d in the previous quarter.

In U.S. Refining, crude throughput was 553,400 bbls/d, representing a utilization rate of 90%, compared with 553,500 bbls/d in the first quarter, reflecting early completion of a planned turnaround at the Toledo Refinery. U.S. Refining revenues were $6.5 billion, slightly higher than $6.4 billion in the previous quarter. Adjusted market capture5 in U.S. Refining was 58%, compared with 62% in the first quarter, due primarily to a narrower heavy oil price differential.

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 second quarter increased to approximately $2.4 billion from $1.3 billion in the first quarter. Adjusted funds flow was $1.5 billion, compared with $2.2 billion in the prior quarter, and excess free funds flow (EFFF) was a shortfall of $306 million, compared with a surplus of $373 million in the first quarter. Net earnings in the second quarter declined slightly to $851 million from $859 million in the previous quarter. Second-quarter financial results were impacted by lower benchmark oil prices, lower Upstream production and higher planned maintenance costs relative to the first quarter.

Long-term debt, including the current portion, was $7.2 billion as at June 30, 2025. Net debt was $4.9 billion as at June 30, 2025, slightly reduced from the previous quarter, as free funds flow of $355 million and a $923 million release of non-cash working capital more than offset returns to shareholders of $819 million, including the redemption of Cenovus’s Series 7 preferred shares on June 30, 2025 for $150 million. Subsequent to the quarter on July 15, the company repaid its 5.38% unsecured notes with a principal of US$133 million in full. The company continues to steward toward net debt of $4.0 billion and returning 100% of EFFF to shareholders over time, in accordance with its financial framework.

Growth projects

In the Oil Sands segment, Narrows Lake achieved first oil in mid-July and will continue ramping up through the remainder of the year. The optimization project at Foster Creek is approximately 87% complete and four new boilers that will add approximately 80,000 bbls/d of steam capacity were brought online in July. The project is expected to produce first oil in early 2026. At Sunrise, one well pad was started up early in the quarter and the drilling program remains on track to increase production and fully utilize the asset’s steam capacity.

Significant progress has been made on the West White Rose project. The CGS was towed out and installed on the seabed ahead of schedule during the second quarter and the project’s topsides were safely lifted and set in place atop the CGS in mid-July. Hookup and commissioning have commenced, and the project is approximately 92% 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

Cenovus has revised its 2025 corporate guidance to reflect the company’s updated outlook for the remainder of the year. It is available on cenovus.com under Investors.

Changes to the company’s 2025 guidance include:

CENOVUS ENERGY NEWS RELEASE | 3

•Total upstream production of 805,000 BOE/d to 825,000 BOE/d, a decrease of 10,000 BOE/d at the midpoint. This includes the impacts of the temporary shut in of the Rush Lake facilities.

•Canadian downstream throughput of 105,000 bbls/d to 110,000 bbls/d, an increase of 5,000 bbls/d at the midpoint, reflecting strong year-to-date performance.

•Reducing the range of Canadian Refining per-unit operating expenses, excluding turnaround costs, to $11.00/bbl to $12.00/bbl, as a result of higher throughput rates and lower expected costs.

•Downstream turnaround expenses of $420 million to $450 million have been reduced by $45 million at the midpoint, primarily due to early completion of the Toledo turnaround.

The company has also updated its commodity price assumptions and guidance range for cash taxes. Cenovus continues to execute its capital program and there has been no change to the expected capital investment range of $4.6 billion to $5.0 billion.

Sustainability

Cenovus’s 2024 Corporate Social Responsibility report, highlighting the company’s performance in safety, Indigenous reconciliation, and acceptance and belonging, was released today and is now available on the company’s website.

Dividend declarations and share purchases

The Board of Directors has declared a quarterly base dividend of $0.20 per common share, payable on September 29, 2025, to shareholders of record as of September 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 October 1, 2025 to shareholders of record as of September 15, 2025, as follows:

Preferred shares dividend summary


Share series	Rate (%)	Amount ($/share)
Series 1	2.577	0.16106
Series 2	4.374	0.27562

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.

In the second quarter, the company returned $819 million to shareholders, composed of $301 million from its purchase of 17.2 million shares through its normal course issuer bid, $368 million through common and preferred share dividends, and $150 million through the redemption of Cenovus’s Series 7 preferred shares. Subsequent to the quarter, the company purchased 6.6 million common shares through July 28, 2025 for $129 million.

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)

CENOVUS ENERGY NEWS RELEASE | 4


(MBOE/d or Mbbls/d)	Q3	Q4	Annualized impact
Upstream
Oil Sands	5 - 7	-	7 - 9
Offshore	2 - 4	-	1 - 2
Conventional	-	-	-
Downstream
Canadian Refining	-	-	-
U.S. Refining	-	10 - 15	12 - 14

Potential turnaround expenses


($ millions)	Q3	Q4	Annualized impact
Downstream
Canadian Refining	-	-	-
U.S. Refining	55 - 70	45 - 60	420 - 450

Conference call today

Cenovus will host a conference call today, July 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 live conference call, you must complete the online registration form in advance of the conference call start time. Register ahead of time to receive a unique PIN to access the conference call via telephone. Once registered, participants can dial into the conference call from their telephone via the unique PIN or click on the "Call Me" option to receive an automated call directly on their telephone.

An audio webcast will also be available and archived for approximately 30 days.

Advisory

Basis of Presentation

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

CENOVUS ENERGY NEWS RELEASE | 5

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 June 30, 2025
Oil Sands
Bitumen (Mbbls/d)			552.1
Heavy crude oil (Mbbls/d)			25.0
Conventional natural gas (MMcf/d)			16.5
Total Oil Sands segment production (MBOE/d)			579.8
Conventional
Light crude oil (Mbbls/d)			4.5
Natural gas liquids (Mbbls/d)			20.4
Conventional natural gas (MMcf/d)			569.2
Total Conventional segment production (MBOE/d)			119.8
Offshore
Light crude oil (Mbbls/d)			12.5
Natural gas liquids (Mbbls/d)			9.5
Conventional natural gas (MMcf/d)			265.7
Total Offshore segment production (MBOE/d)			66.3
Total Upstream production (MBOE/d)			765.9

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: Net Debt target; returning Excess Free Funds Flow to shareholders; growth plans and projects; maximizing value; production guidance; timing of startup of the Foster Creek optimization project; ramping up production at Narrows Lake; investigating the Rush Lake incident and developing a plan to restart production; the Sunrise drilling program; the hookup and commissioning of, and timing of drilling at the West White Rose project; executing the capital program; 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 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.

CENOVUS ENERGY NEWS RELEASE | 6

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: 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 Management and Risk Factors” and “Advisory” in Cenovus’s MD&A for the periods ended December 31, 2024 and June 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 June 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.

CENOVUS ENERGY NEWS RELEASE | 7


	Upstream (6)			Downstream (6)			Total
($ millions)	Q2 2025	Q1 2025	Q2 2024	Q2 2025	Q1 2025	Q2 2024	Q2 2025	Q1 2025	Q2 2024
Revenues
Gross Sales	7,394	9,252	8,715	7,743	7,705	8,750	15,137	16,957	17,465
Less: Royalties	(621)	(906)	(859)	—	—	—	(621)	(906)	(859)
	6,773	8,346	7,856	7,743	7,705	8,750	14,516	16,051	16,606
Expenses
Purchased Product	1,111	1,167	815	6,878	7,082	7,796	7,989	8,249	8,611
Transportation and Blending	2,621	3,247	3,043	—	—	—	2,621	3,247	3,043
Operating	896	893	889	947	854	1,099	1,843	1,747	1,988
Realized (Gain) Loss on Risk Management	8	(9)	20	(11)	6	8	(3)	(3)	28
Operating Margin	2,137	3,048	3,089	(71)	(237)	(153)	2,066	2,811	2,936

6Found in Note 1 of the June 30, 2025, or the March 31, 2025, interim Consolidated Financial Statements. Revenues and purchased product for Q2 2024 Downstream operations were revised. See Note 21 of our June 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.


	Three Months Ended
($ millions)	June 30, 2025	March 31, 2025	June 30, 2024
Cash From (Used in) Operating Activities (7)	2,374	1,315	2,807
(Add) Deduct:
Settlement of Decommissioning Liabilities	(68)	(36)	(48)
Net Change in Non-Cash Working Capital	923	(861)	494
Adjusted Funds Flow	1,519	2,212	2,361
Capital Investment	1,164	1,229	1,155
Free Funds Flow	355	983	1,206
Add (Deduct):
Base Dividends Paid on Common Shares	(364)	(327)	(334)
Purchase of Common Shares under Employee Benefit Plan	(15)	(58)	—
Dividends Paid on Preferred Shares	(4)	(6)	(9)
Settlement of Decommissioning Liabilities	(68)	(36)	(48)
Principal Repayment of Leases	(94)	(83)	(75)
Acquisitions, Net of Cash Acquired	(129)	(100)	(5)
Proceeds From Divestitures	13	—	—

Excess Free Funds Flow	(306)	373	735

7 Found in the June 30, 2025, or the March 31, 2025, interim Consolidated Financial Statements.

Adjusted Market Capture

CENOVUS ENERGY NEWS RELEASE | 8

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.


($ millions)	Three months ended June 30, 2025	Three months ended March 31, 2025
Revenues (8)	6,455	6,423
Purchased Product (8)	5,838	6,006
Gross Margin	617	417
Inventory Holding (Gain) Loss	62	23
Adjusted Gross Margin	679	440
Total Processed Inputs (Mbbls/d)	594.2	581.0
Adjusted Gross Margin ($/bbl)	12.57	8.41
Operable Capacity (Mbbls/d)	612.3	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81
Group 3 3-2-1 Crack Spread Weighting	19	19
Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	21.64	13.68
Group 3 3-2-1 Crack Spread (US$/bbl)	23.07	16.48
RINs (US$/bbl)	6.12	4.76
US$ per C$1 - Average	0.723	0.697
Weighted Average Crack Spread, Net of RINs ($/bbl)	21.86	13.58
Adjusted Market Capture (percent)	58	62

8 Found in Note 1 of the June 30, 2025, or the March 31, 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.

Find Cenovus on Facebook, LinkedIn, YouTube and Instagram.

Cenovus contacts

CENOVUS ENERGY NEWS RELEASE | 9

Investors

Investor Relations general line

403-766-7711

Media

Media Relations general line

403-766-7751

CENOVUS ENERGY NEWS RELEASE | 10

EX-99.2 3 q22025managementsdiscussio.htm EX-99.2 Document

Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Periods Ended June 30, 2025

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS


For the periods ended June 30, 2025

TABLE OF CONTENTS


OVERVIEW OF CENOVUS						3
QUARTERLY RESULTS OVERVIEW						4

OPERATING AND FINANCIAL RESULTS						6
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS						11
OUTLOOK						14
REPORTABLE SEGMENTS						17
UPSTREAM						17
OIL SANDS						17
CONVENTIONAL						22
OFFSHORE						24
DOWNSTREAM						29
CANADIAN REFINING						29
U.S. REFINING						30
CORPORATE AND ELIMINATIONS						33


LIQUIDITY AND CAPITAL RESOURCES						34
RISK MANAGEMENT AND RISK FACTORS						38
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES						38
CONTROL ENVIRONMENT						39
ADVISORY						39
ABBREVIATIONS AND DEFINITIONS						42
SPECIFIED FINANCIAL MEASURES						43
PRIOR PERIOD REVISIONS						56

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 July 30, 2025, should be read in conjunction with our June 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 July 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 July 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. – Q2 2025 Management's Discussion and Analysis			2



OVERVIEW OF CENOVUS

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

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 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. – Q2 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 also includes the jointly-owned Wood River and Borger refineries held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.

Corporate and Eliminations

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



QUARTERLY RESULTS OVERVIEW

The second quarter of 2025 marks the achievement of a number of milestones on our growth projects and the safe execution of turnarounds at our Oil Sands and U.S. Refining assets. Financial results reflect the volatility in pricing through the second quarter. We continue to increase our total returns to common and preferred shareholders through share buybacks, dividends and the redemption of preferred shares.

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

•Maintained upstream production. Upstream production was 765.9 thousand barrels of oil equivalent per day, a decrease from 818.9 thousand barrels of oil equivalent per day in the first quarter of 2025. Production decreased due to the shut-in at Christina Lake and turnaround activities, as discussed above. Turnarounds were well executed with production resuming in June. We temporarily shut-in production at our Rush Lake facilities within our Lloydminster thermal assets as we respond to a casing failure at a steam injection well. The well is under control and we are undertaking an investigation of the incident and developing a plan to restart production.

•Progressed key Oil Sands growth projects. We completed commissioning of the Narrows Lake tie-back to Christina Lake and achieved first oil in July. As part of the Sunrise growth program, we brought one new well pad online. The optimization project at Foster Creek is progressing as planned and was approximately 87 percent complete as at June 30, 2025. In July, we brought four new boilers online that will generate steam at the facility, with related well pads on track for 2026. At our Lloydminster conventional heavy oil assets, we progressed our drilling program and production continued to ramp-up from new development wells coming online.

•Achieved Offshore milestones. In the quarter, we achieved major milestones on the West White Rose Project. The concrete gravity structure was towed out and installed on the seabed. The topsides arrived in Newfoundland and, in July, were set in place atop the concrete gravity structure. Hookup and commissioning work has commenced. The West White Rose project was approximately 92 percent complete as at June 30, 2025.

•Strong crude oil unit throughput in our Canadian Refining segment. Average crude oil unit throughput (“throughput”) was 112.4 thousand barrels per day, compared with 111.9 thousand barrels per day in the first quarter of 2025. We continue to run at, or above, capacity at the Lloydminster Upgrader (“Upgrader”) and the Lloydminster Refinery due to continuous improvement initiatives resulting in high reliability.

•U.S. Refining operations performed as expected. We safely completed the turnaround at the Toledo Refinery ahead of schedule. Turnarounds were also completed at both of our non-operated refineries early in the quarter. Despite turnaround activities, throughput from the U.S. Refining segment was 553.4 thousand barrels per day, consistent with the prior quarter, due to improved process unit reliability at our other operated assets and ongoing operational improvements to our business.

•Reported solid financial results. Adjusted Funds Flow was $1.5 billion down from $2.2 billion in the first quarter of 2025, mainly due to lower realized pricing and lower sales volumes in our upstream assets, partially offset by stronger refining margins in our downstream operations. Cash from operating activities was $2.4 billion, an increase from $1.3 billion in the first quarter of 2025, mainly due to changes in non-cash working capital.

•Redemption of preferred shares. On June 30, 2025, Cenovus exercised its right to redeem all 6.0 million of the Company’s series 7 preferred shares at a price of $25.00 per share, for a total of $150 million.


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•Distributed returns to shareholders. We returned $819 million to common and preferred shareholders, including the purchase of 17.2 million common shares for $301 million through our normal course issuer bid (“NCIB”), $368 million through common and preferred share base dividends, and $150 million through the redemption of preferred shares discussed above. On July 30, 2025, our Board of Directors declared a third quarter dividend of $0.200 per common share.

Summary of Quarterly Results


	Six Months Ended June 30,		2025		2024				2023
($ millions, except where indicated)	2025	2024	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3

Upstream Production Volumes (1) (MBOE/d)	792.2	800.9	765.9	818.9	816.0	771.3	800.8	800.9	808.6	797.0

Downstream Total Processed Inputs (2) (3) (Mbbls/d)	707.7	668.3	714.9	700.5	700.5	674.4	652.9	683.8	605.7	691.3

Crude Oil Unit Throughput (2) (Mbbls/d)	665.7	639.0	665.8	665.4	666.7	642.9	622.7	655.2	579.1	664.3

Downstream Production Volumes (1) (2) (Mbbls/d)	725.8	680.8	729.4	722.4	722.6	685.2	659.5	702.1	627.4	706.0

Revenues (4)	25,618	27,645	12,319	13,299	12,813	13,819	14,582	13,063	13,134	14,577

Operating Margin (5)	4,877	6,127	2,066	2,811	2,274	2,408	2,936	3,191	2,151	4,369
Operating Margin – Upstream (6)	5,185	5,720	2,137	3,048	2,670	2,731	3,089	2,631	2,455	3,447
Operating Margin – Downstream (6)	(308)	407	(71)	(237)	(396)	(323)	(153)	560	(304)	922

Cash From (Used In) Operating Activities	3,689	4,732	2,374	1,315	2,029	2,474	2,807	1,925	2,946	2,738

Adjusted Funds Flow (5)	3,731	4,603	1,519	2,212	1,601	1,960	2,361	2,242	2,062	3,447
Per Share – Basic (5) ($)	2.05	2.47	0.84	1.21	0.88	1.06	1.27	1.20	1.10	1.82
Per Share – Diluted (5) ($)	2.04	2.45	0.84	1.21	0.87	1.05	1.26	1.19	1.08	1.81

Capital Investment	2,393	2,191	1,164	1,229	1,478	1,346	1,155	1,036	1,170	1,025

Free Funds Flow (5)	1,338	2,412	355	983	123	614	1,206	1,206	892	2,422

Excess Free Funds Flow (5)	67	1,567	(306)	373	(416)	146	735	832	471	1,989

Net Earnings (Loss)	1,710	2,176	851	859	146	820	1,000	1,176	743	1,864
Per Share – Basic ($)	0.94	1.16	0.47	0.47	0.08	0.44	0.53	0.62	0.39	0.98
Per Share – Diluted ($)	0.92	1.15	0.45	0.47	0.07	0.42	0.53	0.62	0.32	0.97

Total Assets	55,820	56,000	55,820	56,380	56,539	54,680	56,000	54,994	53,915	54,427



Long-Term Debt, Including Current Portion	7,241	7,275	7,241	7,524	7,534	7,199	7,275	7,227	7,108	7,224

Net Debt	4,934	4,258	4,934	5,079	4,614	4,196	4,258	4,827	5,060	5,976

Cash Returns to Common and Preferred Shareholders	1,414	1,470	819	595	706	1,070	1,034	436	731	1,225
Common Shares – Base Dividends	691	596	364	327	330	329	334	262	261	264
Base Dividends Per Common Share ($)	0.380	0.320	0.200	0.180	0.180	0.180	0.180	0.140	0.140	0.140
Common Shares – Variable Dividends	—	251	—	—	—	—	251	—	—	—
Variable Dividends Per Common Share ($)	—	0.135	—	—	—	—	0.135	—	—	—
Purchase of Common Shares Under NCIB	363	605	301	62	108	732	440	165	350	361
Payment for Purchase of Warrants	—	—	—	—	—	—	—	—	111	600
Dividends Paid on Preferred Shares	10	18	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. – Q2 2025 Management's Discussion and Analysis			5



OPERATING AND FINANCIAL RESULTS

Selected Operating and Financial Results — Upstream


	Three Months Ended June 30,			Six Months Ended June 30,
		Percent Change			Percent Change
	2025		2024	2025		2024
Production Volumes by Segment (1) (MBOE/d)
Oil Sands	579.8	(5)	611.5	602.9	(2)	613.4
Conventional (2)	119.8	(3)	123.1	121.8	—	121.9
Offshore (3)	66.3	—	66.2	67.5	3	65.6
Total Production Volumes	765.9	(4)	800.8	792.2	(1)	800.9

Production Volumes by Product (1)
Bitumen (Mbbls/d)	552.1	(7)	591.7	577.1	(3)	593.5
Heavy Crude Oil (Mbbls/d)	25.0	38	18.1	23.4	30	18.0
Light Crude Oil (Mbbls/d)	17.0	26	13.5	16.9	30	13.0
NGLs (Mbbls/d)	29.9	(9)	33.0	29.9	(9)	32.8
Conventional Natural Gas (MMcf/d)	851.4	(2)	867.2	869.5	1	861.5
Total Production Volumes (MBOE/d)	765.9	(4)	800.8	792.2	(1)	800.9

Per-Unit Operating Expenses by Segment ($/BOE)
Oil Sands (4)	13.60	19	11.47	12.64	8	11.67
Conventional (2) (5)	9.95	(12)	11.25	10.44	(14)	12.14
Offshore (3) (5)	15.94	(29)	22.34	15.71	(22)	20.03

(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 six months ended June 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 $115 million and $242 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 six months ended June 30, 2025, were $81 million and $170 million, respectively (2024 – $142 million and $227 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 decreased in the three and six months ended June 30, 2025, compared with 2024, due to:

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

•Turnaround activities at Foster Creek and Sunrise.

•The temporary shut-in of production at our Rush Lake facilities as we respond to a casing failure at a steam injection well.

The decreases were partially offset by:

•Increased production from optimization activities and the ramp-up of well pads at Foster Creek and Sunrise.

•The safe restart of production at the White Rose field as the SeaRose floating production, storage and offloading unit (“FPSO”) resumed operations in our Atlantic region in the first quarter of 2025 and fully ramped up in the second quarter. There was no production at the White Rose field in 2024.

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

Per-Unit Operating Expenses

For the six months ended June 30, 2025, per-unit operating expenses increased in the Oil Sands segment compared with 2024, primarily due to turnaround activities, and higher waste fluid handling and trucking costs. Per-unit operating expenses decreased in the Conventional segment mainly due to lower processing and gathering costs, and lower repairs and maintenance costs. Per-unit operating expenses decreased in the Offshore segment compared with 2024, primarily due to lower repairs and maintenance, and vessels and air service costs as the SeaRose asset life extension (“ALE”) project was completed in the first quarter of 2025.


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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


	Three Months Ended June 30,			Six Months Ended June 30,
		Percent Change			Percent Change
	2025		2024	2025		2024
Crude Oil Unit Throughput by Segment (Mbbls/d)
Canadian Refining	112.4	109	53.8	112.2	42	79.0
U.S. Refining	553.4	(3)	568.9	553.5	(1)	560.0
Total Crude Oil Unit Throughput	665.8	7	622.7	665.7	4	639.0

Production Volumes by Product (1) (Mbbls/d)
Gasoline	277.1	—	278.3	280.9	—	280.1
Distillates (2)	221.9	—	221.5	223.1	3	217.2
Synthetic Crude Oil	55.3	167	20.7	53.8	59	33.9
Asphalt	41.0	2	40.2	41.6	1	41.0
Ethanol	5.0	14	4.4	4.6	(6)	4.9
Other	129.1	37	94.4	121.8	17	103.7
Total Production Volumes	729.4	11	659.5	725.8	7	680.8

Per-Unit Operating Expenses by Segment (3) ($/bbl)
Canadian Refining	10.70	(85)	70.44	10.75	(69)	34.36
U.S. Refining	14.92	18	12.66	14.31	18	12.17

Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3) ($/bbl)
Canadian Refining	10.63	(66)	30.92	10.72	(45)	19.53
U.S. Refining	10.52	(9)	11.58	11.32	—	11.30

(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 six months ended June 30, 2025, compared with 2024, due to strong throughput as our Canadian Refining assets ran at, or above capacity. In the second quarter of 2024, we executed the largest turnaround in the history of the Upgrader, which significantly reduced throughput and refined product production.

The increase above was partially offset by lower throughput in our U.S. Refining assets in the three and six months ended June 30, 2025, compared with 2024. The limited impact to throughput and total refined product production was due to the Toledo turnaround being well executed, combined with improved process unit reliability across our other operated refineries driven by ongoing operational improvements made to the U.S. Refining business.

In the six months ended June 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 six months ended June 30, 2025, per-unit operating expenses excluding turnaround costs were relatively consistent in the U.S. Refining segment compared with 2024, primarily due to lower repairs and maintenance, and project costs, mainly 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.

Selected Consolidated Financial Results

Revenues

Revenues decreased 16 percent to $12.3 billion and seven percent to $25.6 billion in the three and six months ended June 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. The quarter-over-quarter decrease was also due to lower sales volumes in our upstream and U.S. Refining assets due to turnaround activities in the second quarter of 2025. Year-over-year, the decrease was partially offset by higher sales volumes in our upstream assets.


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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 June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Gross Sales
External Sales (1)	12,940	15,441	27,145	29,251
Intersegment Sales	2,197	2,024	4,949	4,311
	15,137	17,465	32,094	33,562
Royalties	(621)	(859)	(1,527)	(1,606)
Revenues (1)	14,516	16,606	30,567	31,956
Expenses
Purchased Product (1)	7,989	8,611	16,238	16,267
Transportation and Blending	2,621	3,043	5,868	5,854
Operating Expenses	1,843	1,988	3,590	3,673
Realized (Gain) Loss on Risk Management	(3)	28	(6)	35
Operating Margin	2,066	2,936	4,877	6,127

(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 June 30, 2025 and 2024

Operating Margin decreased compared with the second quarter of 2024, primarily due to:

•Lower Realized Sales Prices and lower sales volumes impacting revenues in our Oil Sands and Offshore segments.

•Lower refined product prices and the narrowing of the WTI-WCS and upgrading differentials impacting our U.S. Refining and Canadian Refining segments, respectively.

•Higher operating expenses for turnaround activities at our Oil Sands and U.S. Refining assets.

The decreases were partially offset by:

•Lower operating expenses and higher sales volumes in our Canadian Refining segment due to the turnaround at the Upgrader in the second quarter of 2024, as discussed above.

•Lower operating expenses related to the SeaRose ALE project in our Atlantic operations, due to the completion of the project in the first quarter of 2025.


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Six Months Ended June 30, 2025 and 2024

Operating Margin decreased in the six months ended June 30, 2025, compared with 2024, primarily due to the reasons discussed above, partially offset by higher sales volumes at our Oil Sands and Atlantic operations.

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


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Cash From (Used in) Operating Activities	2,374	2,807	3,689	4,732
(Add) Deduct:
Settlement of Decommissioning Liabilities	(68)	(48)	(104)	(96)
Net Change in Non-Cash Working Capital	923	494	62	225
Adjusted Funds Flow	1,519	2,361	3,731	4,603

Cash from operating activities and Adjusted Funds Flow decreased in the three and six months ended June 30, 2025, compared with the same periods in 2024, primarily due to lower Operating Margin, as discussed above.

For the three months ended June 30, 2025, changes in non-cash working capital increased cash from operating activities by $923 million, primarily due to changes in accounts payable, inventories and income tax receivable, partially offset by changes in accounts receivable.

Net Earnings (Loss)

Net earnings in the three and six months ended June 30, 2025, was $851 million and $1.7 billion, respectively, compared with $1.0 billion and $2.2 billion, respectively, in 2024. The decrease in both periods was due to lower Operating Margin, as discussed above, partially offset by foreign exchange gains in 2025, compared with losses in 2024, and lower income tax expense.

Net Debt


As at ($ millions)	June 30, 2025	December 31, 2024
Short-Term Borrowings	256	173
Current Portion of Long-Term Debt	182	192
Long-Term Portion of Long-Term Debt	7,059	7,342
Total Debt	7,497	7,707
Cash and Cash Equivalents	(2,563)	(3,093)
Net Debt	4,934	4,614


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			9

Total debt decreased by $210 million from December 31, 2024, primarily due to an unrealized foreign exchange gain of $283 million on long-term debt, as the Canadian dollar strengthened relative to the U.S. dollar as at June 30, 2025. This was partially offset by higher short-term borrowings under the WRB uncommitted demand facilities. Net Debt increased by $320 million from December 31, 2024, mainly due to capital investment of $2.4 billion, base dividends of $691 million and preferred share redemptions of $350 million, partially offset by cash from operating activities of $3.7 billion. For further details, see the Liquidity and Capital Resources section of this MD&A.

Capital Investment (1)


	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2025	2024		2025	2024
Upstream
Oil Sands	644		613	1,407	1,260
Conventional	73		68	195	194
Offshore	270		295	511	454
Total Upstream	987		976	2,113	1,908
Downstream
Canadian Refining	28		70	50	101
U.S. Refining	146		100	223	167
Total Downstream	174		170	273	268
Corporate and Eliminations	3		9	7	15
Total Capital Investment	1,164		1,155	2,393	2,191

(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.

Capital investment in the first six months of 2025 was mainly related to:

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

•The progression of the West White Rose project.

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

•Reliability and sustaining activities in our refining segments.

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

Drilling Activity


	Net Stratigraphic Test Wells and Observation Wells		Net Production Wells (1)
Six Months Ended June 30,	2025	2024	2025	2024
Foster Creek	73	82	25	7
Christina Lake	65	58	13	9
Sunrise	21	40	2	—
Lloydminster Thermal	—	—	12	4
Lloydminster Conventional Heavy Oil	—	—	15	3


	159	180	67	23

(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.

Six Months Ended June 30, 2025 (1)

Six Months Ended June 30, 2024

(net wells)

Drilled

Completed

Tied-in

Drilled

Completed

Tied-in

Conventional

(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 six months of 2025 (2024 – commenced drilling one well in China).


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			10



COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

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

Selected Benchmark Prices and Exchange Rates (1)


	Six Months Ended June 30,
(Average US$/bbl, unless otherwise indicated)	2025	Percent Change	2024	Q2 2025	Q1 2025	Q2 2024
Dated Brent	71.74	(15)	84.09	67.82	75.66	84.94
WTI	67.58	(14)	78.77	63.74	71.42	80.57
Differential Dated Brent – WTI	4.16	(22)	5.32	4.08	4.24	4.37
WCS at Hardisty	56.11	(10)	62.30	53.47	58.75	66.96
Differential WTI – WCS at Hardisty	11.47	(30)	16.47	10.27	12.67	13.61
WCS at Hardisty (C$/bbl)	79.13	(7)	84.70	73.96	84.31	91.63
WCS at Nederland	64.37	(11)	72.29	61.00	67.74	74.69
Differential WTI – WCS at Nederland	3.21	(50)	6.48	2.74	3.68	5.88
Condensate (C5 at Edmonton)	66.67	(11)	74.96	63.46	69.88	77.14
Differential Condensate – WTI Premium/(Discount)	(0.91)	(76)	(3.81)	(0.28)	(1.54)	(3.43)
Differential Condensate – WCS at Hardisty Premium/(Discount)	10.56	(17)	12.66	9.99	11.13	10.18
Condensate (C$/bbl)	94.03	(8)	101.87	87.77	100.29	105.55
Synthetic at Edmonton	66.89	(12)	76.37	64.72	69.07	83.32
Differential Synthetic – WTI Premium/(Discount)	(0.69)	(71)	(2.40)	0.98	(2.35)	2.75
Synthetic at Edmonton (C$/bbl)	94.32	(9)	103.83	89.52	99.12	114.01
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	83.85	(11)	94.28	84.61	83.08	99.09
Chicago Ultra-low Sulphur Diesel (“ULSD”)	88.01	(14)	102.04	86.91	89.12	99.80
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)	17.66	(2)	18.10	21.64	13.68	18.76
Group 3 3-2-1 Crack Spread (2)	19.77	11	17.82	23.07	16.48	18.13
Renewable Identification Numbers (“RINs”)	5.44	54	3.53	6.12	4.76	3.39
Upgrading Differential (3) (C$/bbl)	15.08	(21)	18.97	15.46	14.69	22.28
Natural Gas Prices
AECO (4) (C$/Mcf)	1.93	5	1.84	1.69	2.17	1.18
NYMEX (5) (US$/Mcf)	3.55	71	2.07	3.44	3.65	1.89
Foreign Exchange Rates
US$ per C$1 – Average	0.710	(4)	0.736	0.723	0.697	0.731
US$ per C$1 – End of Period	0.733	—	0.731	0.733	0.696	0.731
RMB per C$1 – Average	5.148	(3)	5.311	5.226	5.069	5.293

(1)These benchmark prices are not our Realized Sales Prices and represent approximate values. For our Realized Sales Prices refer to the Netback tables in the upstream reportable segments section of this MD&A.

(2)The average 3-2-1 crack spread is an indicator of the adjusted refining margin and is valued on a last-in, first-out accounting basis.

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

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

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

Crude Oil and Condensate Benchmarks

In the second quarter of 2025, global crude oil benchmark prices, Brent and WTI, decreased compared with the second quarter of 2024 and the first quarter of 2025, due to uncertainty surrounding the U.S. economy, tariff policies and increasing global supply with the unwinding of OPEC+ voluntary production cuts that started in May 2025. Volatility in prices remained high during the quarter due to continued geopolitical uncertainty, new U.S. sanctions targeting Iran and Venezuela, low global and U.S. crude inventories, and the conflict between Israel and Iran.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			11

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices, and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties.

WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude, and the cost of transport. In the six months ended June 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 and stronger global demand for heavy crude.

WCS at Nederland is a heavy oil benchmark for sales of our product at the U.S. Gulf Coast (“USGC”). The WTI-WCS at Nederland differential is representative of the heavy oil quality differential and is influenced by global heavy oil refining capacity and global heavy oil supply. In the six months ended June 30, 2025, the WTI-WCS at Nederland differential narrowed compared with 2024, due to strong global demand for heavy crudes, declining output from Mexico and Venezuela, remaining impacts of production cuts from OPEC+ members, including Saudi Arabia, and strong pricing for fuel oil in which heavy grades yield more versus light grades.

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 six months ended June 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.

Crude Oil Benchmark Prices (1)

(1)Forward pricing as at June 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 six months ended June 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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			12

Refining Benchmarks

RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the 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 six months ended June 30, 2025, refined product crack spreads in Chicago declined slightly compared with the same period in 2024, as U.S. refineries continued operating at high utilization rates, especially in PADD 2 where some expected spring maintenance was deferred to later in the year. Group 3 crack spreads increased in the six months ended June 30, 2025, compared with the same period in 2024, largely as a function of tight regional gasoline inventories. Crack spreads increased in the second quarter of 2025, compared with the first quarter of 2025, consistent with seasonal trends as driving season increases demand. The average cost of RINs were higher in the six months ended June 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.

Refined Product Benchmarks (1)

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

Natural Gas Benchmarks

In the six months ended June 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 six months ended June 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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			13

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 six months ended June 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 six months ended June 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 June 30, 2025, the Bank of Canada’s policy interest rate was 2.75 percent. On July 30, 2025, the Bank of Canada held the policy interest rate at 2.75 percent.



OUTLOOK

Commodity Price Outlook

Global crude oil prices have trended lower in the first five months of 2025, with a modest rebound in June. 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. Price volatility remained heightened over the first half of 2025, with continued geopolitical risks.

The policies around tariffs, trade relations and global 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.

Recent U.S. tariff announcements, pauses, delays and modifications have introduced significant uncertainty in the market and raised the probability of a global recession. We expect heightened price volatility across all commodities to continue until there is a firm resolution on the duration and magnitude of the tariffs. In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession remain risks to the pace of demand growth. 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.

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

•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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			14

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.

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 completed commissioning of the Narrows Lake tie-back to Christina Lake and achieved first oil in July.

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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			15

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 environmental, social and governance (“ESG”) focus areas, and we continue to advance work to support progress against these targets.

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

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

2025 Corporate Guidance

Our 2025 guidance, as updated on July 30, 2025, is available on our website at cenovus.com.

Changes to our updated guidance include:

•A decrease at the midpoint of total upstream production due to the temporary shut-in of production at our Rush Lake facilities.

•An increase at the midpoint of total downstream throughput due to strong year-to-date performance.

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


	Capital Investment ($ millions)	Production (MBOE/d)	Crude Oil Unit Throughput (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	650 - 750		655 - 690

Corporate and Eliminations	Up to 50

We continue to execute our capital program and there have been no changes to our full year expected 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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			16



REPORTABLE SEGMENTS

UPSTREAM

Oil Sands

In the second quarter of 2025, we:

•Delivered safe and reliable operations, including the safe execution of turnarounds at Foster Creek and Sunrise. The turnarounds were well executed, and we returned to full production in June.

•Produced 579.8 thousand BOE per day (2024 – 611.5 thousand BOE per day). The decrease was due to the temporary shut-in of production at our Christina Lake asset in response to wildfire activity, planned downtime for turnaround activities discussed above and the temporary shut-in of production at our Rush Lake facilities within our Lloydminster thermal assets as we respond to a casing failure at a steam injection well.

•Generated Operating Margin of $1.8 billion, a decrease of $926 million compared with 2024, primarily due to lower Realized Sales Prices and lower sales volumes.

•Averaged a Netback of $35.57 per barrel (2024 – $52.10 per barrel).

•Invested capital of $644 million for sustaining activities and growth projects.

Major growth projects remain on track. We completed commissioning of the Narrows Lake tie-back to Christina Lake and achieved first oil in July. The Foster Creek optimization project was approximately 87 percent complete as at June 30, 2025. As part of the Sunrise growth program, we brought one new well pad online. We continued to progress the Lloydminster conventional heavy oil drilling program.

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Gross Sales
External Sales	4,793	6,056	10,697	11,069
Intersegment Sales	1,717	1,497	3,670	3,112
	6,510	7,553	14,367	14,181
Royalties	(589)	(814)	(1,450)	(1,511)
Revenues	5,921	6,739	12,917	12,670
Expenses
Purchased Product	856	403	1,488	692
Transportation and Blending	2,535	2,953	5,686	5,686
Operating	700	615	1,377	1,275
Realized (Gain) Loss on Risk Management	8	20	—	33
Operating Margin	1,822	2,748	4,366	4,984
Unrealized (Gain) Loss on Risk Management	16	1	9	(12)
Depreciation, Depletion and Amortization	749	772	1,583	1,546
Exploration Expense	2	1	6	4
(Income) Loss from Equity-Accounted Affiliates	(38)	(14)	(38)	(14)
Segment Income (Loss)	1,093	1,988	2,806	3,460


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			17

Operating Margin Variance

Three Months Ended June 30, 2025

Six Months Ended June 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.

Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
	2025	2024	2025	2024
Total Sales Volumes (1) (MBOE/d)	568.2	584.5	602.2	595.6

Crude Oil Production by Asset (Mbbls/d)
Foster Creek	186.1	195.0	194.3	195.5
Christina Lake	217.9	237.1	227.8	236.8
Sunrise	50.3	46.1	51.2	47.4
Lloydminster Thermal	97.8	113.5	103.8	113.8
Lloydminster Conventional Heavy Oil	25.0	18.1	23.4	18.0
Total Crude Oil Production (2) (Mbbls/d)	577.1	609.8	600.5	611.5
Natural Gas (1) (MMcf/d)	16.5	10.5	13.9	11.2
Total Production (MBOE/d)	579.8	611.5	602.9	613.4

(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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			18

Operating Results — Continued


	Three Months Ended June 30,		Six Months Ended June 30,
	2025	2024	2025	2024












Effective Royalty Rate (1) (percent)
Foster Creek	20.5	21.1	22.8	22.9
Christina Lake	23.9	25.9	25.5	25.5
Sunrise	6.3	7.3	6.5	5.8
Lloydminster (2)	13.2	11.2	12.2	9.2
Total Effective Royalty Rate	18.9	19.4	20.2	19.4

Netback (3) ($/bbl)
Realized Sales Price	70.78	88.76	76.16	80.62
Royalties	11.43	15.21	13.33	13.88
Transportation and Blending	10.18	9.98	10.01	8.74
Operating	13.60	11.47	12.64	11.67
Total Netback ($/bbl)	35.57	52.10	40.18	46.33





Per-Unit DD&A (4) ($/BOE)	14.21	13.68	14.00	13.51

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

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

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

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

Revenues

Gross sales decreased for the three months ended June 30, 2025, compared with 2024, due to lower Realized Sales Prices and lower sales volumes. Gross sales slightly increased for the six months ended June 30, 2025, compared with 2024, due to higher sales volumes, offset by lower Realized Sales Prices.

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 $70.78 per barrel and $76.16 per barrel, respectively, in the three and six months ended June 30, 2025, (2024 – $88.76 per barrel and $80.62 per barrel, respectively), mainly due to a lower WTI benchmark price and a narrower condensate-WCS differential, partially offset by a narrower WTI-WCS differential.

For the three and six months ended June 30, 2025, approximately 41 percent and 39 percent, respectively (2024 – approximately 34 percent and 28 percent, respectively) of our crude oil sales volumes were sold at destinations outside of Alberta. In the same periods, approximately 30 percent and 25 percent, respectively (2024 – approximately 20 percent for both periods) of our sales volumes were sold to our downstream operations.

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

Production Volumes

Oil Sands crude oil production decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to:

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

•Turnaround activities at Foster Creek and Sunrise.

•The temporary shut-in of production at our Rush Lake facilities.


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The decreases were partially offset by:

•Increased production from optimization activities and the ramp-up of well pads at Foster Creek and Sunrise.

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

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 six months ended June 30, 2025, Oil Sands royalties decreased compared with 2024, mainly due to lower realized pricing. For the three months ended June 30, 2025, the Oil Sands effective royalty rate decreased, primarily due to lower Alberta sliding scale oil sands royalty rates, partially offset by annual adjustments. For the six months ended June 30, 2025, the Oil Sands effective royalty rate increased, primarily due to annual adjustments, partially offset by lower Alberta sliding scale oil sands royalty rates.

Expenses

Transportation and Blending

In the three and six months ended June 30, 2025, blending expenses were $2.0 billion and $4.6 billion, respectively (2024 – $2.4 billion and $4.7 billion, respectively). The decrease for both periods was primarily due to lower condensate prices, partially offset by the use of higher priced condensate purchased in prior periods.

Transportation expenses were consistent for the three months ended June 30, 2025, compared with 2024, as the decrease in sales volumes was offset by an increase in per-unit transportation expenses. Per-unit transportation expenses increased in the three months ended June 30, 2025, compared with 2024, due to higher sales volumes on TMX, partially offset by lower sales volumes at U.S. destinations. Transportation expenses and per-unit transportation expenses increased in the six months ended June 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 June 30,		Six Months Ended June 30,
($/bbl)	2025	2024	2025	2024
Foster Creek	18.41	14.69	17.01	12.42
Christina Lake	6.07	7.16	6.10	6.23
Sunrise	15.28	18.71	16.66	18.62
Lloydminster (2)	3.28	4.55	3.35	4.22
Total Oil Sands	10.18	9.98	10.01	8.74

(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 six months ended June 30, 2025, compared with 2024, primarily due to the higher use of TMX and higher sales to U.S. destinations. The year-over-year increase was partially offset by lower rail transportation costs. In the three and six months ended June 30, 2025, 38 percent and 35 percent, respectively, of our total sales volumes were sold at West Coast destinations (2024 – 10 percent and five percent, respectively). In the three and six months ended June 30, 2025, 47 percent and 41 percent, respectively, of our total sales volumes were sold at U.S. destinations (2024 – 39 percent and 36 percent, respectively).

At Christina Lake, per-unit transportation expenses decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations. In the three and six months ended June 30, 2025, we shipped 16 and 15 percent, respectively, of our total sales volumes to U.S. destinations (2024 – 23 percent and 17 percent, respectively).

At Sunrise, per-unit transportation expenses decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations, partially offset by the higher use of TMX. In the three and six months ended June 30, 2025, 51 percent and 62 percent, respectively, of our total sales volumes were sold at West Coast destinations (2024 – 16 percent and nine percent, respectively). In the three and six months ended June 30, 2025, 38 percent and 33 percent, respectively, of our total sales volumes were sold at U.S. destinations (2024 – 78 percent and 85 percent, respectively).


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			20

At Lloydminster, per-unit transportation expenses decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations. In both the three and six months ended June 30, 2025, we shipped two percent of our total sales to U.S. destinations (2024 – six percent and five percent, respectively).

Operating

Primary drivers of our operating expenses in the first six months of 2025 were fuel, repairs and maintenance, and workforce. Total operating expenses increased in the three and six months ended June 30, 2025, compared with the same periods in 2024, due to higher costs from waste fluid handling and trucking, and turnaround activities combined with higher fuel costs as a result of higher AECO benchmark prices.

Per-Unit Operating Expenses (1)


	Three Months Ended June 30,			Six Months Ended June 30,
($/bbl)	2025	Percent Change	2024	2025	Percent Change	2024
Foster Creek
Fuel	2.90	49	1.95	2.63	1	2.60
Non-Fuel	9.44	16	8.11	8.34	6	7.84
Total	12.34	23	10.06	10.97	5	10.44
Christina Lake
Fuel	2.28	19	1.91	2.40	2	2.36
Non-Fuel	6.42	(2)	6.58	6.33	3	6.14
Total	8.70	2	8.49	8.73	3	8.50
Sunrise
Fuel	4.59	51	3.04	4.47	24	3.61
Non-Fuel	15.67	55	10.13	14.45	28	11.30
Total	20.26	54	13.17	18.92	27	14.91
Lloydminster (2)
Fuel	3.13	39	2.25	3.41	7	3.20
Non-Fuel	17.99	16	15.56	16.37	11	14.73
Total	21.12	19	17.81	19.78	10	17.93

Total Oil Sands
Fuel	2.87	37	2.10	2.86	5	2.72
Non-Fuel	10.73	15	9.37	9.78	9	8.95
Total	13.60	19	11.47	12.64	8	11.67

(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 and six months ended June 30, 2025, per-unit fuel expenses increased, as discussed above.

Foster Creek and Sunrise per-unit non-fuel costs increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to turnaround activities. In the three months ended June 30, 2025, per-unit non-fuel costs were further impacted by lower sales volumes. Sunrise per-unit non-fuel costs also increased in the three and six months ended June 30, 2025, due to higher GHG compliance costs.

Christina Lake per-unit non-fuel costs decreased in the three months ended June 30, 2025, compared with 2024, primarily due to lower GHG compliance costs, partially offset by lower sales volumes. Per-unit non-fuel costs increased in the six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes.

Lloydminster per-unit non-fuel costs increased in the three and six months ended June 30, 2025, compared with 2024, due to higher waste fluid handling and trucking costs, and lower sales volumes as we respond to a casing failure at a steam injection well at Rush Lake.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			21

Conventional

In the second quarter of 2025, we:

•Delivered safe and reliable operations.

•Produced 119.8 thousand BOE per day (2024 – 123.1 thousand BOE per day).

•Generated Operating Margin of $84 million, an increase of $42 million from 2024.

•Earned a Netback of $7.79 per BOE (2024 – $3.68 per BOE), primarily due to higher Realized Sales Prices and lower operating expenses.

•Invested capital of $73 million, primarily related to drilling, completion, tie-in and infrastructure projects.

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024

Gross Sales
External Sales	281	264	724	641
Intersegment Sales	268	427	769	929
	549	691	1,493	1,570
Royalties	(12)	(22)	(32)	(46)
Revenues	537	669	1,461	1,524
Expenses
Purchased Product	255	412	790	894
Transportation and Blending	83	83	173	161
Operating	115	132	242	285
Realized (Gain) Loss on Risk Management	—	—	(1)	(7)
Operating Margin	84	42	257	191
Unrealized (Gain) Loss on Risk Management	(1)	2	(1)	8
Depreciation, Depletion and Amortization	117	111	237	221

(Income) Loss From Equity-Accounted Affiliates	1	—	1	1
Segment Income (Loss)	(33)	(71)	20	(39)

Operating Margin Variance

Three Months Ended June 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. – Q2 2025 Management's Discussion and Analysis			22

Six Months Ended June 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


	Three Months Ended June 30,		Six Months Ended June 30,
	2025	2024	2025	2024
Total Sales Volumes (1) (MBOE/d)	119.8	123.1	121.8	121.9

Realized Sales Price (1) (2) ($/BOE)
Light Crude Oil ($/bbl)	77.83	98.12	83.86	92.96
NGLs ($/bbl)	47.56	56.29	56.22	56.86
Conventional Natural Gas ($/Mcf)	2.77	1.77	3.45	2.87

Production by Product (1)
Light Crude Oil (Mbbls/d)	4.5	5.1	4.8	5.2
NGLs (Mbbls/d)	20.4	21.4	20.5	21.7
Conventional Natural Gas (MMcf/d)	569.2	579.4	579.2	569.9
Total Production (MBOE/d)	119.8	123.1	121.8	121.9

Conventional Natural Gas Production (percentage of total)	79	78	79	78
Crude Oil and NGLs Production (percentage of total)	21	22	21	22

Effective Royalty Rate (1) (3) (percent)	7.4	12.4	8.3	11.0

Netback (1) (2) ($/BOE)
Realized Sales Price	24.19	22.20	29.16	27.50
Royalties	1.18	2.02	1.51	2.09
Transportation and Blending	5.27	5.25	5.38	4.97
Operating	9.95	11.25	10.44	12.14
Total Netback ($/BOE)	7.79	3.68	11.83	8.30





Per-Unit DD&A (4) ($/BOE)	10.38	9.88	10.37	9.89

(1)For the three and six months ended June 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 six months ended June 30, 2025, compared with 2024, due to lower commodity trading volumes sourced from third parties, partially offset by higher Realized Sales Prices. The quarter-over-quarter decrease was also due to lower sales volumes.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			23

Price

Our total Realized Sales Price increased for the three and six months ended June 30, 2025, compared with 2024, primarily due to higher natural gas benchmark prices. For the three and six months ended June 30, 2025, 33 percent and 30 percent, respectively, of our natural gas sales volumes were sold at U.S. destinations where NYMEX natural gas benchmark prices were higher (2024 – 29 percent and 28 percent, respectively). For the three and six months ended June 30, 2025, the AECO natural gas benchmark price was $1.69 per Mcf and $1.93 per Mcf, respectively (2024 – $1.18 per Mcf and $1.84 per Mcf, respectively), and the NYMEX natural gas benchmark price was US$3.44 per Mcf and US$3.55 per Mcf, respectively (2024 – US$1.89 per Mcf and US$2.07 per Mcf, respectively).

Production Volumes

For the three months ended June 30, 2025, production volumes decreased compared with 2024, primarily due to third-party pipeline outages and the divestiture of non-core assets in the third quarter of 2024, partially offset by strong base performance. For the six months ended June 30, 2025, production volumes were relatively consistent compared with 2024, as the decreases in the second quarter were offset by strong base production in the first quarter.

Royalties

Royalties and the effective royalty rate decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower production of natural gas liquids and light crude oil, which are subject to higher royalty rates.

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 months ended June 30, 2025, transportation expenses and per-unit transportation expenses were consistent compared with 2024. In the six months ended June 30, 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, primarily due to increased pipeline transportation rates.

Operating

Primary drivers of operating expenses in the first six 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 six months ended June 30, 2025, compared with 2024, mainly due to lower processing and gathering costs, and lower repairs and maintenance costs.

Offshore

In the second quarter of 2025, we:

•Delivered safe and reliable operations.

•Produced 66.3 thousand BOE per day of light crude oil, NGLs and natural gas (2024 – 66.2 thousand BOE per day).

•Generated Operating Margin of $231 million, a decrease of $68 million from 2024, primarily due to lower sales volumes.

•Averaged a Netback of $51.02 per BOE (2024 – $54.33 per BOE).

•Invested capital of $270 million, mainly related to the progression of the West White Rose project.

The West White Rose project reached major milestones in the second quarter of 2025. The concrete gravity structure was towed out and installed on the seabed. The topsides arrived in Newfoundland and, in July, were set in place atop the concrete gravity structure. Hookup and commissioning work has commenced. As at June 30, 2025, the project was approximately 92 percent complete and we remain on track to deliver first oil in the second quarter of 2026. Since our decision in 2022 to restart the project, we have invested approximately $2.1 billion.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			24

Financial Results


	Three Months Ended June 30,
	2025			2024
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	72	263	335	151	320	471
Intersegment Sales	—	—	—	—	—	—
	72	263	335	151	320	471
Royalties	—	(20)	(20)	1	(24)	(23)
Revenues	72	243	315	152	296	448
Expenses

Transportation and Blending	3	—	3	7	—	7
Operating	48	33	81	110	32	142
Operating Margin (1)	21	210	231	35	264	299
Depreciation, Depletion and Amortization			93			156
Exploration Expense			1			4
(Income) Loss from Equity-Accounted Affiliates			(7)			(13)
Segment Income (Loss)			144			152


	Six Months Ended June 30,
	2025			2024
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	218	568	786	193	635	828
Intersegment Sales	—	—	—	—	—	—
	218	568	786	193	635	828
Royalties	(2)	(43)	(45)	(1)	(48)	(49)
Revenues	216	525	741	192	587	779
Expenses

Transportation and Blending	9	—	9	7	—	7
Operating	112	58	170	167	60	227
Operating Margin (1)	95	467	562	18	527	545
Depreciation, Depletion and Amortization			223			287
Exploration Expense			2			8
(Income) Loss from Equity-Accounted Affiliates			(15)			(23)
Segment Income (Loss)			352			273

(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. – Q2 2025 Management's Discussion and Analysis			25

Operating Margin Variance

Three Months Ended June 30, 2025

Six Months Ended June 30, 2025

Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
	2025	2024	2025	2024
Sales Volumes
Atlantic (Mbbls/d)	7.9	14.8	11.8	9.4
Asia Pacific (MBOE/d)
China	37.9	43.5	39.8	43.6
Indonesia (1)	15.9	14.3	15.6	14.2
Total Asia Pacific	53.8	57.8	55.4	57.8
Total Sales Volumes (MBOE/d)	61.7	72.6	67.2	67.2

Production by Product
Atlantic – Light Crude Oil (Mbbls/d)	12.5	8.4	12.1	7.8
Asia Pacific (1)
NGLs (Mbbls/d)	9.5	11.6	9.4	11.1
Conventional Natural Gas (MMcf/d)	265.7	277.3	276.4	280.4
Total Asia Pacific (MBOE/d)	53.8	57.8	55.4	57.8
Total Production (MBOE/d)	66.3	66.2	67.5	65.6

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


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			26

Operating Results — Continued


	Three Months Ended June 30,		Six Months Ended June 30,
	2025	2024	2025	2024
























Effective Royalty Rate (1) (percent)
Atlantic	0.9	(0.6)	1.0	0.5
Asia Pacific (2)	11.9	9.5	12.3	8.6

Per-Unit DD&A (3) ($/BOE)	15.91	22.90	17.61	22.70

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

(2)Reflects Cenovus’s 40 percent equity interest in the HCML joint venture.

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

Netbacks (1)


	Three Months Ended June 30, 2025
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Realized Sales Price		100.23	76.49		59.06		75.01
Royalties		0.94	5.88		14.65		7.52
Transportation and Blending		4.14	—		—		0.53
Operating Expenses		61.44	8.72		10.56		15.94
Netback		33.71	61.89		33.85		51.02


	Three Months Ended June 30, 2024
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Realized Sales Price		112.74	80.95		60.43		83.38
Royalties		(0.72)	6.20		10.17		5.57
Transportation and Blending		5.60	—		—		1.14
Operating Expenses		79.03	7.24		9.68		22.34
Netback		28.83	67.51		40.58		54.33


	Six Months Ended June 30, 2025
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Realized Sales Price		101.82	78.85		61.77		78.92
Royalties		1.00	6.01		16.98		7.68
Transportation and Blending		4.21	—		—		0.74
Operating Expenses		50.84	7.30		10.61		15.71
Netback		45.77	65.54		34.18		54.79


	Six Months Ended June 30, 2024
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Realized Sales Price		113.02	80.08		56.77		79.75
Royalties		0.50	6.10		7.17		5.54
Transportation and Blending		3.97	—		—		0.55
Operating Expenses		95.82	6.76		10.76		20.03
Netback		12.73	67.22		38.84		53.63

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

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

Revenues

For the three and six months ended June 30, 2025, gross sales decreased compared with 2024, due to lower sales volumes in our China operations and lower Offshore Realized Sales Prices. The quarter-over-quarter decrease was also impacted by lower sales volumes in our Atlantic operations. The year-over-year decrease was partially offset by higher Atlantic sales volumes.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			27

Price

Our Atlantic Realized Sales Price decreased in the three and six months ended June 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 six months ended June 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. The quarter-over-quarter increase was partially offset by maintenance activities at the Terra Nova field. 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. 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 six months ended June 30, 2025, compared with 2024, primarily due to lower contracted sales volumes in China and the timing of annual maintenance. The decrease was partially offset by increased production in Indonesia due to higher buyer nominations.

Royalties

For the three and six months ended June 30, 2025, the Atlantic effective royalty rate increased compared with 2024, primarily due to a credit received in 2024.

Royalty rates in Asia Pacific are governed by production-sharing contracts, in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for Asia Pacific increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower cost recoveries resulting in higher royalty rates in Indonesia. The effective royalty rate was lower in 2024, due to credits received in the period.

Expenses

Transportation

Transportation expenses include the costs of transporting crude oil from the Terra Nova and SeaRose FPSOs to onshore terminals and storage costs. Transportation expenses for the three months ended June 30, 2025, decreased to $3 million (2024 – $7 million), primarily due to lower sales volumes. Transportation expenses for the six months ended June 30, 2025, increased to $9 million (2024 – $7 million), primarily due to higher sales volumes.

Operating

Primary drivers of our Atlantic operating expenses in the first six months of 2025 were repairs and maintenance, costs related to vessels and air services, and workforce. In the three and six months ended June 30, 2025, operating expenses and per-unit operating expenses decreased compared with 2024. The decrease for both periods was primarily due to lower repairs and maintenance, and vessels and air service costs as the SeaRose ALE project was completed in the first quarter of 2025.

Primary drivers of our China operating expenses in the first six months of 2025 were repairs and maintenance, insurance and workforce costs. Per-unit operating expenses increased in the three and six months ended June 30, 2025, compared with 2024, due to lower sales volumes.

Primary drivers of our Indonesia operating expenses in the first six months of 2025 were repairs and maintenance, and workforce costs. Indonesia per-unit operating expenses increased in the three months ended June 30, 2025, compared with 2024, due to higher repairs and maintenance costs, partially offset by higher sales volumes. Per-unit operating expenses decreased in the six months ended June 30, 2025, compared with 2024, due to higher sales volumes, partially offset by higher repairs and maintenance costs.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			28

DOWNSTREAM

Canadian Refining

In the second quarter of 2025, we:

•Delivered safe and reliable operations.

•Achieved strong crude oil throughput of 112.4 thousand barrels per day and crude unit utilization of 104 percent (2024 – 53.8 thousand barrels per day and 50 percent, respectively).

•Incurred per-unit operating expenses excluding turnaround costs of $10.63 per barrel (2024 – $30.92 per barrel).

•Recorded Operating Margin of $107 million, an increase of $362 million from the second quarter of 2024. The increase was primarily due to lower operating expenses and higher sales volumes, partially offset by lower refined product pricing, and higher heavy crude oil and bitumen feedstock costs due to the narrowing of the upgrading differential.

•Invested capital of $28 million, primarily focused on sustaining activities.

Financial and Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024



Revenues	1,288	1,135	2,570	2,467


Purchased Product	1,040	975	2,116	2,062
Gross Margin (1)	248	160	454	405
Expenses
Operating	141	415	279	592
Operating Margin	107	(255)	175	(187)
Depreciation, Depletion and Amortization	52	54	99	98
Segment Income (Loss)	55	(309)	76	(285)

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


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2025	2024	2025	2024


Gross Margin	248	160	454	405
Inventory Holding (Gain) Loss (1)	(12)	5	(9)	(18)
Adjusted Gross Margin (2)	236	165	445	387




Adjusted Refining Margin (3) ($/bbl)	19.64	26.23	18.50	22.34

(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 six months ended June 30, 2025, were $1.2 billion and $2.4 billion, respectively (2024 – $1.1 billion and $2.3 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 increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to higher sales volumes, partially offset by lower refined product pricing.

Adjusted Gross Margin increased in the three and six months ended June 30, 2025, compared with the same periods in 2024, primarily due to higher sales volumes, partially offset by higher heavy crude oil and bitumen feedstock costs as a result of the narrowing of the upgrading differential.

Adjusted Refining Margin decreased in the three and six months ended June 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. – Q2 2025 Management's Discussion and Analysis			29


	Three Months Ended June 30,		Six Months Ended June 30,
(Mbbls/d, except where indicated)	2025	2024	2025	2024












Operable Capacity	108.0	108.0	108.0	108.0

Total Processed Inputs	120.7	58.9	120.1	83.8

Crude Oil Unit Throughput	112.4	53.8	112.2	79.0

Crude Unit Utilization (percent)	104	50	104	73

Total Production	129.0	64.0	127.6	90.1
Synthetic Crude Oil	55.3	20.7	53.8	33.9
Asphalt	16.7	14.0	16.6	14.8
Diesel	15.1	5.2	15.3	9.0
Other	36.9	19.7	37.3	27.5
Ethanol	5.0	4.4	4.6	4.9

The Upgrader and Lloydminster Refinery source their crude oil feedstock from our Oil Sands segment. In the three and six months ended June 30, 2025, 16 percent and 15 percent, respectively, of our Oil Sands segment’s sales volumes were purchased by our Canadian Refining segment (2024 – seven percent and 10 percent, respectively).

Throughput and total production increased in the three and six months ended June 30, 2025, compared with 2024. In 2025, our assets ran at, or above, capacity due to ongoing improvement initiatives and high asset reliability. In the second quarter of 2024, we safely executed the largest turnaround in the history of the Upgrader, which significantly 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 June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2025	2024	2025	2024

Operating Expenses – Upgrading and Refining	117	377	234	524
Operating Expenses – Excluding Turnaround Costs	116	166	233	298
Operating Expenses – Turnaround Costs	1	211	1	226

Per-Unit Operating Expenses (1) ($/bbl)	10.70	70.44	10.75	34.36
Per-Unit Operating Expenses – Excluding Turnaround Costs	10.63	30.92	10.72	19.53
Per-Unit Operating Expenses – Turnaround Costs	0.07	39.52	0.03	14.83

(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 costs.

In the three and six months ended June 30, 2025, operating expenses decreased compared with the same periods in 2024, mainly due to the turnaround completed at the Upgrader and other project expenses incurred in the second quarter of 2024.

Operating expenses excluding turnaround costs decreased in the three and six months ended June 30, 2025, compared with 2024, due to lower project costs.

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

U.S. Refining

In the second quarter of 2025, we:

•Delivered safe and reliable operations.

•Safely executed the turnaround at the Toledo Refinery ahead of schedule. Turnarounds were also completed at the non-operated Wood River and Borger refineries.

•Achieved crude unit utilization of 90 percent (2024 – 93 percent) and throughput of 553.4 thousand barrels per day, compared with 568.9 thousand barrels per day in the second quarter of 2024.

•Incurred per-unit operating expenses excluding turnaround costs of $10.52 per barrel (2024 – $11.58 per barrel).

•Recorded an Operating Margin shortfall of $178 million, a decrease of $280 million from the second quarter of 2024, primarily due to the narrowing of the WTI-WCS differential combined with higher operating expenses from turnaround activities.

•Invested capital of $146 million, primarily focused on reliability and sustaining activities.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			30

Financial and Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024



Revenues (1)	6,455	7,615	12,878	14,516


Purchased Product (1)	5,838	6,821	11,844	12,619
Gross Margin (2)	617	794	1,034	1,897
Expenses

Operating	806	684	1,522	1,294
Realized (Gain) Loss on Risk Management	(11)	8	(5)	9
Operating Margin	(178)	102	(483)	594
Unrealized (Gain) Loss on Risk Management	—	(10)	(8)	(2)
Depreciation, Depletion and Amortization	149	112	307	223
Segment Income (Loss)	(327)	—	(782)	373

(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 June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2025	2024	2025	2024



Gross Margin	617	794	1,034	1,897
Inventory Holding (Gain) Loss (1)	62	(83)	85	(277)
Adjusted Gross Margin (2)	679	711	1,119	1,620


Adjusted Refining Margin (2) ($/bbl)	12.57	13.15	10.53	15.23



Adjusted Market Capture (2) (percent)	58	63	59	77

(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 six months ended June 30, 2025, compared with 2024, primarily due to lower benchmark gasoline and diesel prices.

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 June 30, 2025, the Chicago 3-2-1 crack spread increased 15 percent and the Group 3 3-2-1 crack spread increased 27 percent, compared with 2024. During this period, the average cost of RINs increased by 81 percent. Quarter-over-quarter, Adjusted Gross Margin decreased due to the narrowing of the WTI-WCS differential by 25 percent, partially offset by the increase in the weighted average crack spread, net of RINs.

In the first half of 2025, the Chicago 3-2-1 crack spread decreased two percent and the Group 3 3-2-1 crack spread increased 11 percent compared with 2024, which was more than offset by a 54 percent increase in the average cost of RINs. Year-over-year, Adjusted Gross Margin decreased due to the narrowing of the WTI-WCS differential by 30 percent and the lower weighted average crack spread, net of RINs.

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 decreased in the three and six months ended June 30, 2025, compared with the same periods in 2024, due to the decrease in Adjusted Gross Margin. While the turnaround at the Toledo Refinery in the quarter impacted the Adjusted Refining Margin and Adjusted Market Capture, this was offset by ongoing operational improvements in our U.S. Refining business.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			31


	Three Months Ended June 30,		Six Months Ended June 30,
(Mbbls/d, except where indicated)	2025	2024	2025	2024
















Operable Capacity	612.3	612.3	612.3	612.3

Total Processed Inputs	594.2	594.0	587.6	584.5

Crude Oil Unit Throughput	553.4	568.9	553.5	560.0
Heavy Crude Oil	214.2	219.4	220.2	222.1
Light/Medium Crude Oil	339.2	349.5	333.3	337.9

Crude Unit Utilization (percent)	90	93	90	91

Total Refined Product Production	600.4	595.5	598.2	590.7
Gasoline	277.1	278.3	280.9	280.1
Distillates (1)	206.8	216.3	207.8	208.2
Asphalt	24.3	26.2	25.0	26.2
Other	92.2	74.7	84.5	76.2

(1)Includes diesel and jet fuel.

In the second quarter of 2025, we completed turnarounds at the Toledo Refinery and at the non-operated Wood River and Borger refineries.

Throughput decreased slightly in the three and six months ended June 30, 2025, compared with the same periods in 2024. Total refined product production increased slightly in the three and six months ended June 30, 2025, compared with the same periods in 2024.

The limited impact to throughput and total refined product production in the three and six months ended June 30, 2025, is due to the Toledo turnaround being well executed, combined with improved process unit reliability across our other operated refineries driven by ongoing operational improvements made to the U.S. Refining business.

Operating Expenses


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2025	2024	2025	2024
Operating Expenses	806	684	1,522	1,294
Operating Expenses – Excluding Turnaround Costs	568	626	1,204	1,202
Operating Expenses – Turnaround Costs	238	58	318	92

Per-Unit Operating Expenses (1) ($/bbl)	14.92	12.66	14.31	12.17
Per-Unit Operating Expenses – Excluding Turnaround Costs	10.52	11.58	11.32	11.30
Per-Unit Operating Expenses – Turnaround Costs	4.40	1.08	2.99	0.87

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

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

In the three and six months ended June 30, 2025, operating expenses increased compared with the same periods in 2024. This was mainly due to $238 million of turnaround costs recognized in the quarter, as discussed above, partially offset by a decrease in repairs and maintenance costs.

Overall, controllable operating expenses excluding turnaround costs decreased in the three and six months ended June 30, 2025, compared with 2024, due to ongoing business improvement initiatives and improved reliability.

Operating expenses excluding turnaround costs and related per-unit metrics for the three months ended June 30, 2025, decreased primarily due to lower controllable operating expenses, including lower repairs and maintenance, and project costs, 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.

Operating expenses excluding turnaround costs and related per-unit metrics for the six months ended June 30, 2025, were relatively consistent, as the decrease in controllable operating expenses, as discussed above, was mainly offset by higher electricity costs and foreign exchange impacts.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			32

CORPORATE AND ELIMINATIONS

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Realized (Gain) Loss on Risk Management	(20)	—	(25)	3
Unrealized (Gain) Loss on Risk Management	(84)	—	(46)	30

General and Administrative	153	175	350	421
Finance Costs, Net	114	141	250	276
Integration, Transaction and Other Costs	77	39	79	72
Foreign Exchange (Gain) Loss, Net	(353)	55	(353)	154


Other (Income) Loss, Net	(26)	(40)	(32)	(130)

General and Administrative

Primary drivers of our general and administrative expenses for the three and six months ended June 30, 2025, were workforce and information technology related costs. For the three and six months ended June 30, 2025, general and administrative expenses decreased compared with 2024, primarily due to lower long-term incentive costs.

Finance Costs, Net

Net finance costs were lower in the three and six months ended June 30, 2025, compared with the same periods in 2024, due to higher interest income. 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 six months ended June 30, 2025, was 4.53 percent and 4.54 percent, respectively (2024 – 4.49 and 4.48 percent, respectively).

Foreign Exchange (Gain) Loss, Net


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Unrealized Foreign Exchange (Gain) Loss	(420)	85	(401)	209
Realized Foreign Exchange (Gain) Loss	67	(30)	48	(55)
	(353)	55	(353)	154

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

Income Taxes


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Current Tax
Canada	224	300	503	646
United States	—	(9)	—	2
Asia Pacific	57	56	102	100
Other International	11	8	24	17
Total Current Tax Expense (Recovery)	292	355	629	765
Deferred Tax Expense (Recovery)	(127)	(46)	(193)	(78)
	165	309	436	687

For the six months ended June 30, 2025, we recorded a current tax expense related to operations in all jurisdictions in which we operate, except the U.S. The decrease in current tax expense is due to lower earnings compared with the same period in 2024.

The effective tax rate in the first six months of 2025 was 20.3 percent, a decrease from the same period in the prior year (2024 – 24.0 percent). Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to, different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax basis and other legislation.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			33

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.


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Cash From (Used In)
Operating Activities	2,374	2,807	3,689	4,732
Investing Activities	(1,375)	(1,170)	(2,723)	(2,305)
Net Cash Provided (Used) Before Financing Activities	999	1,637	966	2,427
Financing Activities	(1,078)	(912)	(1,372)	(1,589)
Effect of Foreign Exchange on Cash and Cash Equivalents	(126)	29	(124)	89
Increase (Decrease) in Cash and Cash Equivalents	(205)	754	(530)	927

			June 30,	December 31,
As at ($ millions)			2025	2024
Cash and Cash Equivalents			2,563	3,093
Total Debt			7,497	7,707

Cash From (Used in) Operating Activities

In the three and six months ended June 30, 2025, cash from operating activities decreased compared with the same periods in 2024, primarily due to lower Operating Margin. For the three months ended June 30, 2025, changes in non-cash working capital increased cash from operating activities by $923 million, primarily due to changes in accounts payable, inventories and income tax receivable, partially offset by changes in accounts receivable.

Cash From (Used in) Investing Activities

Cash used in investing activities increased in the three and six months ended June 30, 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 months ended June 30, 2025, compared with 2024, primarily related to a repayment of short-term borrowings in the second quarter of 2025, compared with an issuance in the second quarter of 2024, and preferred share redemptions of $150 million in the second quarter of 2025. These increases were partially offset by fewer purchases under the Company’s NCIB and variable dividends of $251 million paid in 2024, with no variable dividend declared in 2025.

Cash used in financing activities decreased in the six months ended June 30, 2025, compared with 2024, due to the variable dividends, as discussed above, and fewer common shares purchased under the Company’s NCIB. This was partially offset by preferred share redemptions of $350 million in the six months ended June 30, 2025.

Working Capital

Working capital as at June 30, 2025, was $2.3 billion (December 31, 2024 – $3.1 billion). The decrease was primarily driven by lower inventories and cash and cash equivalents, partially offset by higher accounts receivable.

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


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			34

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.

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


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Excess Free Funds Flow (1)	(306)	735	67	1,567
Target Return (2)	(306)	368	67	784

Shareholder Returns by way of:
Purchase of Common Shares Under NCIB	301	440	363	605
Variable Dividends Paid	—	251	—	251
Preferred Share Redemption	150	—	350	—
Total	451	691	713	856

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

(2)The target return for the three and six months ended June 30, 2025, was 100 percent of Excess Free Funds Flow. The target return for the three and six months ended June 30, 2024, was 50 percent of Excess Free Funds Flow.

Short-Term Borrowings

There were no direct borrowings on our uncommitted demand facilities as at June 30, 2025, or December 31, 2024. As at June 30, 2025, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$188 million (C$256 million) (December 31, 2024 – US$120 million (C$173 million)).

Long-Term Debt, Including Current Portion

Long-term debt, including the current portion, as at June 30, 2025, was $7.2 billion (December 31, 2024 – $7.5 billion). We hold U.S. dollar denominated unsecured notes of US$3.8 billion (C$5.2 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).

As at June 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.

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

Available Sources of Liquidity

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

($ millions)

Maturity

Amount Available

Cash and Cash Equivalents

n/a

2,563

Committed Credit Facility (1)

Revolving Credit Facility – Tranche A

June 26, 2028

3,300

Revolving Credit Facility – Tranche B

June 26, 2027

2,200

Uncommitted Demand Facilities

Cenovus Energy Inc. (2)

n/a

1,068

WRB (3)

n/a

(1)No amounts were drawn on the committed credit facility as at June 30, 2025 (December 31, 2024 – $nil).

(2)Represents amounts available for cash draws. Our uncommitted demand facilities include $1.7 billion, of which $1.4 billion may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at June 30, 2025, there were outstanding letters of credit aggregating to $363 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).

(3)Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at June 30, 2025, US$188 million (C$256 million) of this capacity was drawn (December 31, 2024 – US$120 million (C$173 million)).


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			35

Base Shelf Prospectus

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

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, Total Debt, the Net Debt to Adjusted EBITDA ratio, the Net Debt to Adjusted Funds Flow ratio and the Net Debt to Capitalization ratio. Refer to Note 10 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.


As at	June 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)	14	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 June 30, 2025, increased compared with December 31, 2024, as a result of lower Operating Margin and higher Net Debt. See the Operating and Financial Results section of this MD&A for more information on changes in Operating Margin and Net Debt.

Our Net Debt to Capitalization ratio as at June 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 June 30, 2025, there were approximately 1,805.9 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 six months ended June 30, 2025, the Trust purchased 3.6 million common shares for a total of $73 million and distributed 3.8 million common shares for a total of $82 million under the employee benefit plan. As at June 30, 2025, there were 1.8 million common shares held by the Trust (December 31, 2024 – 2.0 million common shares). Refer to Note 13 of the interim Consolidated Financial Statements for further details.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			36

As at June 30, 2025, there were approximately 3.2 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 13 of the interim Consolidated Financial Statements for further details.

Refer to Note 15 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 July 28, 2025	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	1,799,751	n/a
Cenovus Warrants	3,210	n/a
Series 1 First Preferred Shares	10,740	n/a
Series 2 First Preferred Shares	1,260	n/a
Stock Options	11,622	5,595
Other Stock-Based Compensation Plans	19,731	2,046

Common Share Dividends

In the three months ended June 30, 2025, we declared and paid base dividends of $364 million or $0.200 per common share (2024 – $334 million or $0.180 per common share). In the six months ended June 30, 2025, we declared and paid base dividends of $691 million or $0.380 per common share (2024 – $596 million or $0.320 per common share).

On July 30, 2025, the Board declared a third quarter base dividend of $0.200 per common share. The dividend is payable on September 29, 2025, to common shareholders of record as at September 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 June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Series 1 First Preferred Shares	1	1	3	3
Series 2 First Preferred Shares	1	1	1	1
Series 3 First Preferred Shares	—	3	—	6
Series 5 First Preferred Shares	—	3	2	5
Series 7 First Preferred Shares	2	1	4	3
Total Preferred Share Dividends Declared and Paid	4	9	10	18

On July 30, 2025, the Board declared a third quarter dividend on the series 1 and 2 preferred shares for a total of $2 million, payable on October 1, 2025, to preferred shareholders of record as at September 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 June 30,		Six Months Ended June 30,
	2025	2024	2025	2024
Common Shares Purchased and Cancelled Under NCIB (millions of common shares)	17.2	15.4	20.2	22.8
Weighted Average Price per Common Share ($)	17.12	27.88	17.64	26.07
Purchase of Common Shares Under NCIB ($ millions)	301	440	363	605

From July 1, 2025, to July 28, 2025, the Company purchased an additional 6.6 million common shares for $129 million. As at July 28, 2025, the Company can further purchase up to 99.6 million common shares under the NCIB.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			37

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 20 of the interim Consolidated Financial Statements.

Our total commitments were $26.3 billion as at June 30, 2025 (December 31, 2024 – $27.3 billion), of which $23.3 billion are for various transportation and storage commitments. Transportation commitments include $34 million that are subject to regulatory approval or were approved but are not yet in service. Terms are up to 7 years on commencement.

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

As at June 30, 2025, outstanding letters of credit issued as security for performance under certain contracts totaled $363 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.

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 June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Revenues from Construction and Management Services	37	38	66	69
Transportation Expenses	69	71	137	140



RISK MANAGEMENT AND RISK FACTORS

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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			38



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 June 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 June 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.



ADVISORY

Oil and Gas Information

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

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”, “estimate”, “expect”, “F”, “focus”, “grow”, “improve”, “invest”, “may”, “maximize”, “meet”, “mitigate”, “on track”, “objective”, “ongoing”, “opportunities”, “optimize”, “plan”, “position”, “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; 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 completion of the West White Rose project; progressing growth projects, including the Narrows Lake tie-back to Christina Lake, the Foster Creek optimization, Lloydminster drilling program and Sunrise growth projects; our ESG 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;


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			39

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; 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 ESG 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 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; 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 ESG 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


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			40

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 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 ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.

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

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


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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
equivalent per day

WCS

Western Canadian Select

MMcf/d

million cubic feet per day

DD&A

depreciation, depletion and
amortization

WTI

West Texas Intermediate

ESG

environmental, social and
governance

GHG

greenhouse gas

FPSO

floating production, storage and
offloading unit

NCIB

normal course issuer bid

AECO

Alberta Energy Company

NYMEX

New York Mercantile Exchange

OPEC

Organization of Petroleum
Exporting Countries

OPEC+

OPEC and a group of 11
non-OPEC members

USGC

U.S. Gulf Coast


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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 June 30,
	2025	2024	2025	2024	2025	2024
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales (2)	5,409	6,791	7,531	8,650	12,940	15,441
Intersegment Sales	1,985	1,924	212	100	2,197	2,024
	7,394	8,715	7,743	8,750	15,137	17,465
Royalties	(621)	(859)	—	—	(621)	(859)
Revenues (2)	6,773	7,856	7,743	8,750	14,516	16,606
Expenses
Purchased Product (2)	1,111	815	6,878	7,796	7,989	8,611
Transportation and Blending	2,621	3,043	—	—	2,621	3,043
Operating	896	889	947	1,099	1,843	1,988
Realized (Gain) Loss on Risk Management	8	20	(11)	8	(3)	28
Operating Margin	2,137	3,089	(71)	(153)	2,066	2,936

(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.


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	Six Months Ended June 30,
	2025	2024		2025	2024	2025	2024
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales (2)	12,207	12,538		14,938	16,713	27,145	29,251
Intersegment Sales	4,439	4,041		510	270	4,949	4,311
	16,646	16,579		15,448	16,983	32,094	33,562
Royalties	(1,527)	(1,606)		—	—	(1,527)	(1,606)
Revenues (2)	15,119	14,973		15,448	16,983	30,567	31,956
Expenses
Purchased Product (2)	2,278	1,586		13,960	14,681	16,238	16,267
Transportation and Blending	5,868	5,854		—	—	5,868	5,854
Operating	1,789	1,787		1,801	1,886	3,590	3,673
Realized (Gain) Loss on Risk Management	(1)	26		(5)	9	(6)	35
Operating Margin	5,185	5,720		(308)	407	4,877	6,127

(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 June 30, 2025			Six Months Ended June 30, 2025
($ millions)	Atlantic	Asia Pacific	Offshore (1)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	72	263	335	218	568	786
Royalties	—	(20)	(20)	(2)	(43)	(45)
Revenues	72	243	315	216	525	741
Expenses
Transportation and Blending	3	—	3	9	—	9
Operating	48	33	81	112	58	170
Operating Margin	21	210	231	95	467	562


	Three Months Ended June 30, 2024			Six Months Ended June 30, 2024
($ millions)	Atlantic	Asia Pacific	Offshore (1)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	151	320	471	193	635	828
Royalties	1	(24)	(23)	(1)	(48)	(49)
Revenues	152	296	448	192	587	779
Expenses
Transportation and Blending	7	—	7	7	—	7
Operating	110	32	142	167	60	227
Operating Margin	35	264	299	18	527	545

(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.


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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 June 30,		Six Months Ended June 30,
($ millions)	2025	2024	2025	2024
Cash From (Used in) Operating Activities	2,374	2,807	3,689	4,732
(Add) Deduct:
Settlement of Decommissioning Liabilities	(68)	(48)	(104)	(96)
Net Change in Non-Cash Working Capital	923	494	62	225
Adjusted Funds Flow	1,519	2,361	3,731	4,603
Capital Investment	1,164	1,155	2,393	2,191
Free Funds Flow	355	1,206	1,338	2,412
Add (Deduct):
Base Dividends Paid on Common Shares	(364)	(334)	(691)	(596)
Dividends Paid on Preferred Shares	(4)	(9)	(10)	(18)
Purchase of Common Shares Under Employee Benefit Plan	(15)	—	(73)	—
Settlement of Decommissioning Liabilities	(68)	(48)	(104)	(96)
Principal Repayment of Leases	(94)	(75)	(177)	(145)
Acquisitions, Net of Cash Acquired	(129)	(5)	(229)	(15)
Proceeds From Divestitures	13	—	13	25

Excess Free Funds Flow	(306)	735	67	1,567

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.


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Canadian Refining


	Three Months Ended June 30, 2025
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,211	77	1,288
Purchased Product	983	57	1,040
Gross Margin	228	20	248
Add (Deduct):
Inventory Holding (Gain) Loss	(12)	—	(12)
Adjusted Gross Margin	216	20	236

Total Processed Inputs (Mbbls/d)	120.7


Adjusted Refining Margin ($/bbl)	19.64

(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 June 30, 2024
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,065	70	1,135
Purchased Product	930	45	975
Gross Margin	135	25	160
Add (Deduct):
Inventory Holding (Gain) Loss	5	—	5
Adjusted Gross Margin	140	25	165

Total Processed Inputs (Mbbls/d)	58.9


Adjusted Refining Margin ($/bbl)	26.23

(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.


	Six Months Ended June 30, 2025

($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	2,432	138	2,570
Purchased Product	2,020	96	2,116
Gross Margin	412	42	454
Add (Deduct):
Inventory Holding (Gain) Loss	(9)	—	(9)
Adjusted Gross Margin	403	42	445

Total Processed Inputs (Mbbls/d)	120.1


Adjusted Refining Margin ($/bbl)	18.50

(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. – Q2 2025 Management's Discussion and Analysis			46


	Six Months Ended June 30, 2024

($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	2,314	153	2,467
Purchased Product	1,954	108	2,062
Gross Margin	360	45	405
Add (Deduct):
Inventory Holding (Gain) Loss	(19)	1	(18)
Adjusted Gross Margin	341	46	387

Total Processed Inputs (Mbbls/d)	83.8

Adjusted Refining Margin ($/bbl)	22.34

(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 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.


	Three Months Ended September 30, 2024
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining
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.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			47


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

U.S. Refining


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2025	2024	2025	2024
Revenues (1)	6,455	7,615	12,878	14,516
Purchased Product (1)	5,838	6,821	11,844	12,619
Gross Margin	617	794	1,034	1,897
Add (Deduct):
Inventory Holding (Gain) Loss	62	(83)	85	(277)
Adjusted Gross Margin	679	711	1,119	1,620

Total Processed Inputs (Mbbls/d)	594.2	594.0	587.6	584.5


Adjusted Refining Margin ($/bbl)	12.57	13.15	10.53	15.23

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$/bbl)	21.64	18.76	17.66	18.10
Group 3 3-2-1 Crack Spread (US$/bbl)	23.07	18.13	19.77	17.82
RINs (US$/bbl)	6.12	3.39	5.44	3.53
US$ per C$1 – Average	0.723	0.731	0.710	0.736

Weighted Average Crack Spread, Net of RINs ($/bbl)	21.86	20.86	17.79	19.72


Adjusted Market Capture (percent)	58	63	59	77

(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. – Q2 2025 Management's Discussion and Analysis			48


	Three Months Ended		Twelve Months Ended
($ millions, except where indicated)	December 31, 2024	September 30, 2024		December 31, 2024
Revenues (1)	6,574	7,218		28,308
Purchased Product (1)	6,296	6,854		25,769
Gross Margin	278	364		2,539
Add (Deduct):
Inventory Holding (Gain) Loss	45	209		(23)
Adjusted Gross Margin	323	573		2,516

Total Processed Inputs (Mbbls/d)	588.4	568.0		581.4


Adjusted Refining Margin ($/bbl)	5.98	10.97		11.83

Operable Capacity (Mbbls/d)	612.3	612.3		612.3

Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81		81
Group 3 3-2-1 Crack Spread Weighting	19	19		19

Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	12.12	18.62		16.74
Group 3 3-2-1 Crack Spread (US$/bbl)	12.66	18.95		16.81
RINs (US$/bbl)	4.02	3.89		3.74
US$ per C$1 – Average	0.715	0.733		0.730

Weighted Average Crack Spread, Net of RINs ($/bbl)	11.47	20.18		17.82


Adjusted Market Capture (percent)	52	54		67

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

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. – Q2 2025 Management's Discussion and Analysis			49

Oil Sands


	Basis of Netback Calculation
Three Months Ended June 30, 2025 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,275	1,265	317	789	3,646
Royalties	(200)	(274)	(16)	(99)	(589)
Revenues	1,075	991	301	690	3,057
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	301	117	70	38	526
Operating	202	168	92	239	701
Netback	572	706	139	413	1,830
Realized (Gain) Loss on Risk Management					8
Operating Margin					1,822


	Basis of Netback Calculation	Adjustments
Three Months Ended June 30, 2025 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	3,646		1,989	769	106	6,510
Royalties	(589)		—	—	—	(589)
Revenues	3,057		1,989	769	106	5,921
Expenses
Purchased Product	—		—	769	87	856
Transportation and Blending	526		1,989	—	20	2,535
Operating	701		—	—	(1)	700
Netback	1,830		—	—	—	1,830
Realized (Gain) Loss on Risk Management	8		—	—	—	8
Operating Margin	1,822		—	—	—	1,822

(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 June 30, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,533	1,686	438	1,064	4,721
Royalties	(271)	(401)	(25)	(111)	(808)
Revenues	1,262	1,285	413	953	3,913
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	248	142	87	54	531
Operating	169	168	62	211	610
Netback	845	975	264	688	2,772
Realized (Gain) Loss on Risk Management					20
Operating Margin					2,752

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

(2)Includes bitumen and heavy oil.


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			50


	Basis of Netback Calculation	Adjustments
Three Months Ended June 30, 2024 ($ millions)	Total Oil Sands (1)		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	4,721		2,406	305	121	7,553
Royalties	(808)		—	—	(6)	(814)
Revenues	3,913		2,406	305	115	6,739
Expenses
Purchased Product	—		—	305	98	403
Transportation and Blending	531		2,406	—	16	2,953
Operating	610		—	—	5	615
Netback	2,772		—	—	(4)	2,768
Realized (Gain) Loss on Risk Management	20		—	—	—	20
Operating Margin	2,752		—	—	(4)	2,748

(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
Six Months Ended June 30, 2025 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	2,992	2,884	706	1,699	8,281
Royalties	(542)	(672)	(36)	(198)	(1,448)
Revenues	2,450	2,212	670	1,501	6,833
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	613	249	150	77	1,089
Operating	395	357	170	452	1,374
Netback	1,442	1,606	350	972	4,370
Realized (Gain) Loss on Risk Management					—
Operating Margin					4,370


	Basis of Netback Calculation	Adjustments
Six Months Ended June 30, 2025 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	8,281		4,564	1,322	200	14,367
Royalties	(1,448)		—	—	(2)	(1,450)
Revenues	6,833		4,564	1,322	198	12,917
Expenses
Purchased Product	—		—	1,322	166	1,488
Transportation and Blending	1,089		4,564	—	33	5,686
Operating	1,374		—	—	3	1,377
Netback	4,370		—	—	(4)	4,366
Realized (Gain) Loss on Risk Management	—		—	—	—	—
Operating Margin	4,370		—	—	(4)	4,366

(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. – Q2 2025 Management's Discussion and Analysis			51


	Basis of Netback Calculation
Six Months Ended June 30, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	2,889	3,160	778	1,914	8,741
Royalties	(564)	(740)	(36)	(165)	(1,505)
Revenues	2,325	2,420	742	1,749	7,236
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	429	261	158	99	947
Operating	360	356	127	422	1,265
Netback	1,536	1,803	457	1,228	5,024
Realized (Gain) Loss on Risk Management					33
Operating Margin					4,991


	Basis of Netback Calculation	Adjustments
Six Months Ended June 30, 2024 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	8,741		4,711	518	211	14,181
Royalties	(1,505)		—	—	(6)	(1,511)
Revenues	7,236		4,711	518	205	12,670
Expenses
Purchased Product	—		—	518	174	692
Transportation and Blending	947		4,711	—	28	5,686
Operating	1,265		—	—	10	1,275
Netback	5,024		—	—	(7)	5,017
Realized (Gain) Loss on Risk Management	33		—	—	—	33
Operating Margin	4,991		—	—	(7)	4,984

(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 June 30, 2025 ($ millions)	Conventional (1)	Third-party Sourced	Other (1) (2)	Conventional (3)
Gross Sales	264	256	29	549
Royalties	(13)	—	1	(12)
Revenues	251	256	30	537
Expenses
Purchased Product	—	256	(1)	255
Transportation and Blending	58	—	25	83
Operating	108	—	7	115
Netback	85	—	(1)	84
Realized (Gain) Loss on Risk Management	—	—	—	—
Operating Margin	85	—	(1)	84

(1)For the three months ended June 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. – Q2 2025 Management's Discussion and Analysis			52


	Basis of Netback Calculation	Adjustments
Three Months Ended June 30, 2024 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	248	411	32	691
Royalties	(22)	—	—	(22)
Revenues	226	411	32	669
Expenses
Purchased Product	—	411	1	412
Transportation and Blending	59	—	24	83
Operating	126	—	6	132
Netback	41	—	1	42
Realized (Gain) Loss on Risk Management	—	—	—	—
Operating Margin	41	—	1	42

(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
Six Months Ended June 30, 2025 ($ millions)	Conventional (1)	Third-party Sourced	Other (1) (2)	Conventional (3)
Gross Sales	643	790	60	1,493
Royalties	(33)	—	1	(32)
Revenues	610	790	61	1,461
Expenses
Purchased Product	—	790	—	790
Transportation and Blending	119	—	54	173
Operating	230	—	12	242
Netback	261	—	(5)	256
Realized (Gain) Loss on Risk Management	(1)	—	—	(1)
Operating Margin	262	—	(5)	257

(1)For the six months ended June 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
Six Months Ended June 30, 2024 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	610	893	67	1,570
Royalties	(46)	—	—	(46)
Revenues	564	893	67	1,524
Expenses
Purchased Product	—	893	1	894
Transportation and Blending	110	—	51	161
Operating	269	—	16	285
Netback	185	—	(1)	184
Realized (Gain) Loss on Risk Management	(7)	—	—	(7)
Operating Margin	192	—	(1)	191

(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. – Q2 2025 Management's Discussion and Analysis			53

Offshore


	Basis of Netback Calculation					Adjustments
Three Months Ended June 30, 2025 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	72	263	86	349	421	(86)	—	335
Royalties	—	(20)	(21)	(41)	(41)	21	—	(20)
Revenues	72	243	65	308	380	(65)	—	315
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	3	—	—	—	3	—	—	3
Operating	45	30	15	45	90	(12)	3	81
Netback	24	213	50	263	287	(53)	(3)	231
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					287	(53)	(3)	231


	Basis of Netback Calculation					Adjustments
Three Months Ended June 30, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	151	320	79	399	550	(79)	—	471
Royalties	1	(24)	(14)	(38)	(37)	14	—	(23)
Revenues	152	296	65	361	513	(65)	—	448
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	7	—	—	—	7	—	—	7
Operating	106	29	13	42	148	(11)	5	142
Netback	39	267	52	319	358	(54)	(5)	299
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					358	(54)	(5)	299

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

(2)Primarily related to Offshore project expenses.

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


	Basis of Netback Calculation
Six Months Ended June 30, 2025 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	218	568	175	743	961	(175)	—	786
Royalties	(2)	(43)	(48)	(91)	(93)	48	—	(45)
Revenues	216	525	127	652	868	(127)	—	741
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	9	—	—	—	9	—	—	9
Operating	109	53	30	83	192	(25)	3	170
Netback	98	472	97	569	667	(102)	(3)	562
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					667	(102)	(3)	562

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

(2)Primarily related to Offshore project expenses.

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


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			54


	Basis of Netback Calculation
Six Months Ended June 30, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	193	635	147	782	975	(147)	—	828
Royalties	(1)	(48)	(19)	(67)	(68)	19	—	(49)
Revenues	192	587	128	715	907	(128)	—	779
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	7	—	—	—	7	—	—	7
Operating	163	54	28	82	245	(23)	5	227
Netback	22	533	100	633	655	(105)	(5)	545
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					655	(105)	(5)	545

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

(2)Primarily related to Offshore project expenses.

(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 June 30,		Six Months Ended June 30,
(MBOE/d)	2025	2024	2025	2024
Oil Sands (2)
Foster Creek	179.8	185.4	199.1	189.7
Christina Lake	212.2	218.1	225.8	230.1
Sunrise	49.8	51.0	49.6	46.6
Lloydminster	124.5	130.0	126.3	129.2
Total Oil Sands	566.3	584.5	600.8	595.6

Conventional (3)	119.8	123.1	121.8	121.9

Offshore
Atlantic	7.9	14.8	11.8	9.4
Asia Pacific
China	37.9	43.5	39.8	43.6
Indonesia (4)	15.9	14.3	15.6	14.2
Total Asia Pacific	53.8	57.8	55.4	57.8
Total Offshore	61.7	72.6	67.2	67.2

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

(2)Includes bitumen and heavy crude oil sales.

(3)For the three and six months ended June 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. – Q2 2025 Management's Discussion and Analysis			55

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 June 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,918	(303)	7,615	14,885	(303)	14,582
Purchased Product	7,124	(303)	6,821	7,184	(303)	6,881
Transportation and Blending	—	—	—	2,865	—	2,865
Purchased Product, Transportation and Blending	7,124	(303)	6,821	10,049	(303)	9,746
	794	—	794	4,836	—	4,836


	U.S. Refining Segment			Consolidated
For the six months ended June 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	15,153	(637)	14,516	28,282	(637)	27,645
Purchased Product	13,256	(637)	12,619	13,317	(637)	12,680
Transportation and Blending	—	—	—	5,440	—	5,440
Purchased Product, Transportation and Blending	13,256	(637)	12,619	18,757	(637)	18,120
	1,897	—	1,897	9,525	—	9,525


	U.S. Refining Segment			Consolidated
For the three months ended September 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,648	(430)	7,218	14,249	(430)	13,819
Purchased Product	7,284	(430)	6,854	7,556	(430)	7,126
Transportation and Blending	—	—	—	2,489	—	2,489
Purchased Product, Transportation and Blending	7,284	(430)	6,854	10,045	(430)	9,615
	364	—	364	4,204	—	4,204


Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis			56

EX-99.3 4 q22025interimconsolidatedf.htm EX-99.3 Document

Exhibit 99.3

Cenovus Energy Inc.

Interim Consolidated Financial Statements (unaudited)

For the Periods Ended June 30, 2025

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


For the periods ended June 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. INCOME TAXES						15
6. PER SHARE AMOUNTS						16

7. EXPLORATION AND EVALUATION ASSETS, NET						17
8. PROPERTY, PLANT AND EQUIPMENT, NET						17
9. LEASES						18



10. DEBT AND CAPITAL STRUCTURE						18


11. DECOMMISSIONING LIABILITIES						21
12. OTHER LIABILITIES						21
13. SHARE CAPITAL AND WARRANTS						21
14. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)						23
15. STOCK-BASED COMPENSATION PLANS						23
16. RELATED PARTY TRANSACTIONS						24
17. FINANCIAL INSTRUMENTS						25
18. RISK MANAGEMENT						27
19. SUPPLEMENTARY CASH FLOW INFORMATION						28
20. COMMITMENTS AND CONTINGENCIES						29
21. PRIOR PERIOD REVISIONS						30


Cenovus Energy Inc. – Q2 2025 Interim Consolidated Financial Statements			2



CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)

For the periods ended June 30,

($ millions, except per share amounts)


		Three Months Ended		Six Months Ended
	Notes	2025	2024	2025	2024




Revenues (1)	1	12,319	14,582	25,618	27,645
Expenses	1
Purchased Product, Transportation and Blending (1)		8,541	9,746	17,411	18,120
Operating		1,748	1,923	3,377	3,478
(Gain) Loss on Risk Management	17	(92)	21	(77)	62
Depreciation, Depletion, Amortization and Exploration Expense	8,9	1,187	1,238	2,506	2,440
(Income) Loss From Equity-Accounted Affiliates		(43)	(28)	(36)	(37)
General and Administrative		153	175	350	421
Finance Costs, Net	3	114	141	250	276
Integration, Transaction and Other Costs		77	39	79	72
Foreign Exchange (Gain) Loss, Net	4	(353)	55	(353)	154
(Gain) Loss on Divestiture of Assets		(3)	1	(3)	(104)
Re-measurement of Contingent Payments		—	2	—	30
Other (Income) Loss, Net		(26)	(40)	(32)	(130)
Earnings (Loss) Before Income Tax		1,016	1,309	2,146	2,863
Income Tax Expense (Recovery)	5	165	309	436	687
Net Earnings (Loss)		851	1,000	1,710	2,176

Other Comprehensive Income (Loss), Net of Tax	14
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits		6	4	8	18
Change in the Fair Value of Equity Instruments at FVOCI (2)	17	(2)	124	(4)	124
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		(662)	125	(672)	393
Total Other Comprehensive Income (Loss), Net of Tax		(658)	253	(668)	535
Comprehensive Income (Loss)		193	1,253	1,042	2,711

Net Earnings (Loss) Per Common Share ($)	6
Basic		0.47	0.53	0.94	1.16
Diluted		0.45	0.53	0.92	1.15

(1)Comparative periods reflect certain revisions. See Note 21.

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

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


Cenovus Energy Inc. – Q2 2025 Interim Consolidated Financial Statements			3


CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)


		June 30,	December 31,
	Notes	2025	2024

Assets
Current Assets
Cash and Cash Equivalents		2,563	3,093

Accounts Receivable and Accrued Revenues		2,916	2,614
Income Tax Receivable		60	231
Inventories		3,917	4,496

Total Current Assets		9,456	10,434
Restricted Cash		248	241
Exploration and Evaluation Assets, Net	1,7	526	484
Property, Plant and Equipment, Net	1,8	38,568	38,568
Right-of-Use Assets, Net	1,9	2,044	1,950
Income Tax Receivable		25	25
Investments in Equity-Accounted Affiliates		338	399
Other Assets		477	451
Deferred Income Taxes		1,215	1,064
Goodwill	1	2,923	2,923
Total Assets		55,820	56,539

Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		6,218	6,242
Income Tax Payable		115	396
Short-Term Borrowings	10	256	173
Long-Term Debt	10	182	192
Lease Liabilities	9	371	359


Total Current Liabilities		7,142	7,362
Long-Term Debt	10	7,059	7,342
Lease Liabilities	9	2,618	2,568

Decommissioning Liabilities	11	4,710	4,534
Other Liabilities	12	873	919
Deferred Income Taxes		4,001	4,045
Total Liabilities		26,403	26,770
Shareholders’ Equity		29,402	29,754
Non-Controlling Interest		15	15
Total Liabilities and Equity		55,820	56,539

Commitments and Contingencies	20

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


Cenovus Energy Inc. – Q2 2025 Interim Consolidated Financial Statements			4


CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

($ millions)


	Shareholders’ Equity
	Common Shares	Treasury Shares	Preferred Shares	Warrants	Paid in Surplus	Retained Earnings	AOCI (1)	Total
	(Note 13)	(Note 13)	(Note 13)	(Note 13)			(Note 14)

As at December 31, 2023	16,031	—	519	25	2,002	8,913	1,208	28,698
Net Earnings (Loss)	—	—	—	—	—	2,176	—	2,176
Other Comprehensive Income (Loss), Net of Tax	—	—	—	—	—	—	535	535
Total Comprehensive Income (Loss)	—	—	—	—	—	2,176	535	2,711

Common Shares Issued Under Stock Option Plans	66	—	—	—	(16)	—	—	50
Purchase of Common Shares Under NCIB (2)	(195)	—	—	—	(410)	—	—	(605)


Warrants Exercised	26	—	—	(9)	—	—	—	17

Stock-Based Compensation Expense	—	—	—	—	6	—	—	6
Base Dividends on Common Shares	—	—	—	—	—	(596)	—	(596)
Variable Dividends on Common Shares	—		—	—	—	(251)	—	(251)
Dividends on Preferred Shares	—	—	—	—	—	(18)	—	(18)

As at June 30, 2024	15,928	—	519	16	1,582	10,224	1,743	30,012

As at December 31, 2024	15,659	(43)	356	12	944	10,513	2,313	29,754
Net Earnings (Loss)	—	—	—	—	—	1,710	—	1,710
Other Comprehensive Income (Loss), Net of Tax	—	—	—	—	—	—	(668)	(668)
Total Comprehensive Income (Loss)	—	—	—	—	—	1,710	(668)	1,042

Common Shares Issued Under Stock Option Plans	9	—	—	—	(2)	—	—	7

Purchase of Common Shares Under NCIB (2)	(173)	—	—	—	(190)	—	—	(363)
Purchase of Common Shares Under Employee Benefit Plan	—	(73)	—	—	—	—	—	(73)
Common Shares Issued Under Employee Benefit Plan	—	82	—	—	(6)	—	—	76
Preferred Shares Redeemed	—	—	(243)	—	(107)	—	—	(350)

Warrants Exercised	4	—	—	(1)	—	—	—	3

Stock-Based Compensation Expense	—	—	—	—	7	—	—	7
Base Dividends on Common Shares	—	—	—	—	—	(691)	—	(691)

Dividends on Preferred Shares	—	—	—	—	—	(10)	—	(10)

As at June 30, 2025	15,499	(34)	113	11	646	11,522	1,645	29,402

(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. – Q2 2025 Interim Consolidated Financial Statements			5


CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the periods ended June 30,

($ millions)


		Three Months Ended		Six Months Ended
	Notes	2025	2024	2025	2024

Operating Activities
Net Earnings (Loss)		851	1,000	1,710	2,176
Depreciation, Depletion and Amortization	8,9	1,184	1,233	2,498	2,428



Deferred Income Tax Expense (Recovery)	5	(127)	(46)	(193)	(78)
Unrealized (Gain) Loss on Risk Management	17	(69)	(7)	(46)	24
Unrealized Foreign Exchange (Gain) Loss	4	(420)	85	(401)	209


(Gain) Loss on Divestiture of Assets		(3)	1	(3)	(104)
Re-measurement of Contingent Payments		—	2	—	30
Unwinding of Discount on Decommissioning Liabilities	11	58	56	116	113
(Income) Loss From Equity-Accounted Affiliates		(43)	(28)	(36)	(37)
Distributions Received From Equity-Accounted Affiliates		58	87	83	118
Stock-Based Compensation, Net of Payments		12	24	19	(130)
Other		18	(46)	(16)	(146)
Settlement of Decommissioning Liabilities	11	(68)	(48)	(104)	(96)
Net Change in Non-Cash Working Capital	19	923	494	62	225
Cash From (Used in) Operating Activities		2,374	2,807	3,689	4,732

Investing Activities
Acquisitions, Net of Cash Acquired		(129)	(5)	(229)	(15)
Capital Investment	1	(1,164)	(1,155)	(2,393)	(2,191)
Proceeds From Divestitures		13	—	13	25



Net Change in Investments and Other		(17)	(51)	(13)	(64)
Net Change in Non-Cash Working Capital	19	(78)	41	(101)	(60)
Cash From (Used in) Investing Activities		(1,375)	(1,170)	(2,723)	(2,305)

Net Cash Provided (Used) Before Financing Activities		999	1,637	966	2,427

Financing Activities	19
Net Issuance (Repayment) of Short-Term Borrowings		(84)	136	66	(39)

Repayment of Long-Term Debt		—	—	(12)	—

Principal Repayment of Leases	9	(94)	(75)	(177)	(145)
Net Proceeds (Repayment) on Repurchase Agreements		(72)	—	228	—
Common Shares Issued Under Stock Option Plans		4	46	7	50
Purchase of Common Shares Under NCIB	13	(301)	(440)	(363)	(605)
Purchase of Common Shares Under Employee Benefit Plan	13	(15)	—	(73)	—
Redemption of Preferred Shares	13	(150)	—	(350)	—

Proceeds From Exercise of Warrants		2	15	3	17
Dividends Paid	6	(368)	(594)	(701)	(865)




Other		—	—	—	(2)
Cash From (Used in) Financing Activities		(1,078)	(912)	(1,372)	(1,589)

Effect of Foreign Exchange on Cash and Cash Equivalents		(126)	29	(124)	89
Increase (Decrease) in Cash and Cash Equivalents		(205)	754	(530)	927
Cash and Cash Equivalents, Beginning of Period		2,768	2,400	3,093	2,227
Cash and Cash Equivalents, End of Period		2,563	3,154	2,563	3,154

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


Cenovus Energy Inc. – Q2 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 June 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. – Q2 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 June 30, 2025

A) Results of Operations – Segment and Operational Information


	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2025	2024	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales	4,793	6,056	281	264	335	471	5,409	6,791
Intersegment Sales	1,717	1,497	268	427	—	—	1,985	1,924
	6,510	7,553	549	691	335	471	7,394	8,715
Royalties	(589)	(814)	(12)	(22)	(20)	(23)	(621)	(859)
Revenues	5,921	6,739	537	669	315	448	6,773	7,856
Expenses
Purchased Product	856	403	255	412	—	—	1,111	815
Transportation and Blending	2,535	2,953	83	83	3	7	2,621	3,043
Operating	700	615	115	132	81	142	896	889
Realized (Gain) Loss on Risk Management	8	20	—	—	—	—	8	20
Operating Margin	1,822	2,748	84	42	231	299	2,137	3,089
Unrealized (Gain) Loss on Risk Management	16	1	(1)	2	—	—	15	3
Depreciation, Depletion and Amortization	749	772	117	111	93	156	959	1,039
Exploration Expense	2	1	—	—	1	4	3	5
(Income) Loss From Equity- Accounted Affiliates	(38)	(14)	1	—	(7)	(13)	(44)	(27)
Segment Income (Loss)	1,093	1,988	(33)	(71)	144	152	1,204	2,069


	Downstream
	Canadian Refining		U.S. Refining		Total
For the three months ended June 30,	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales (1)	1,076	1,037	6,455	7,613	7,531	8,650
Intersegment Sales	212	98	—	2	212	100
	1,288	1,135	6,455	7,615	7,743	8,750
Royalties	—	—	—	—	—	—
Revenues (1)	1,288	1,135	6,455	7,615	7,743	8,750
Expenses
Purchased Product (1)	1,040	975	5,838	6,821	6,878	7,796
Transportation and Blending	—	—	—	—	—	—
Operating	141	415	806	684	947	1,099
Realized (Gain) Loss on Risk Management	—	—	(11)	8	(11)	8
Operating Margin	107	(255)	(178)	102	(71)	(153)
Unrealized (Gain) Loss on Risk Management	—	—	—	(10)	—	(10)
Depreciation, Depletion and Amortization	52	54	149	112	201	166
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	55	(309)	(327)	—	(272)	(309)

(1)Comparative period reflects certain revisions. See Note 21.


Cenovus Energy Inc. – Q2 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 June 30, 2025


	Corporate and Eliminations		Consolidated
For the three months ended June 30,		2025		2024	2025	2024
Gross Sales
External Sales (1)				—	—	12,940	15,441
Intersegment Sales				(2,197)	(2,024)	—	—
				(2,197)	(2,024)	12,940	15,441
Royalties				—	—	(621)	(859)
Revenues (1)				(2,197)	(2,024)	12,319	14,582
Expenses
Purchased Product (1)				(1,908)	(1,730)	6,081	6,881
Transportation and Blending				(161)	(178)	2,460	2,865
Purchased Product, Transportation and Blending (1)				(2,069)	(1,908)	8,541	9,746
Operating				(95)	(65)	1,748	1,923
Realized (Gain) Loss on Risk Management				(20)	—	(23)	28
Unrealized (Gain) Loss on Risk Management				(84)	—	(69)	(7)
Depreciation, Depletion and Amortization				24	28	1,184	1,233
Exploration Expense				—	—	3	5

(Income) Loss From Equity-Accounted Affiliates				1	(1)	(43)	(28)
Segment Income (Loss)				46	(78)	978	1,682
General and Administrative				153	175	153	175
Finance Costs, Net				114	141	114	141
Integration, Transaction and Other Costs				77	39	77	39
Foreign Exchange (Gain) Loss, Net				(353)	55	(353)	55
(Gain) Loss on Divestiture of Assets				(3)	1	(3)	1
Re-measurement of Contingent Payments				—	2	—	2

Other (Income) Loss, Net				(26)	(40)	(26)	(40)
				(38)	373	(38)	373
Earnings (Loss) Before Income Tax						1,016	1,309
Income Tax Expense (Recovery)						165	309
Net Earnings (Loss)						851	1,000

(1)Comparative period reflects certain revisions. See Note 21.


Cenovus Energy Inc. – Q2 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 June 30, 2025


	Upstream
For the six months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2025	2024	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales	10,697	11,069	724	641	786	828	12,207	12,538
Intersegment Sales	3,670	3,112	769	929	—	—	4,439	4,041
	14,367	14,181	1,493	1,570	786	828	16,646	16,579
Royalties	(1,450)	(1,511)	(32)	(46)	(45)	(49)	(1,527)	(1,606)
Revenues	12,917	12,670	1,461	1,524	741	779	15,119	14,973
Expenses
Purchased Product	1,488	692	790	894	—	—	2,278	1,586
Transportation and Blending	5,686	5,686	173	161	9	7	5,868	5,854
Operating	1,377	1,275	242	285	170	227	1,789	1,787
Realized (Gain) Loss on Risk Management	—	33	(1)	(7)	—	—	(1)	26
Operating Margin	4,366	4,984	257	191	562	545	5,185	5,720
Unrealized (Gain) Loss on Risk Management	9	(12)	(1)	8	—	—	8	(4)
Depreciation, Depletion and Amortization	1,583	1,546	237	221	223	287	2,043	2,054
Exploration Expense	6	4	—	—	2	8	8	12
(Income) Loss From Equity- Accounted Affiliates	(38)	(14)	1	1	(15)	(23)	(52)	(36)
Segment Income (Loss)	2,806	3,460	20	(39)	352	273	3,178	3,694


	Downstream
	Canadian Refining		U.S. Refining		Total
For the six months ended June 30,	2025	2024	2025	2024	2025	2024
Gross Sales
External Sales (1)	2,061	2,200	12,877	14,513	14,938	16,713
Intersegment Sales	509	267	1	3	510	270
	2,570	2,467	12,878	14,516	15,448	16,983
Royalties	—	—	—	—	—	—
Revenues (1)	2,570	2,467	12,878	14,516	15,448	16,983
Expenses
Purchased Product (1)	2,116	2,062	11,844	12,619	13,960	14,681
Transportation and Blending	—	—	—	—	—	—
Operating	279	592	1,522	1,294	1,801	1,886
Realized (Gain) Loss on Risk Management	—	—	(5)	9	(5)	9
Operating Margin	175	(187)	(483)	594	(308)	407
Unrealized (Gain) Loss on Risk Management	—	—	(8)	(2)	(8)	(2)
Depreciation, Depletion and Amortization	99	98	307	223	406	321
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	76	(285)	(782)	373	(706)	88

(1)Comparative period reflects certain revisions. See Note 21.


Cenovus Energy Inc. – Q2 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 June 30, 2025


	Corporate and Eliminations		Consolidated
For the six months ended June 30,	2025	2024	2025	2024
Gross Sales
External Sales (1)	—	—	27,145	29,251
Intersegment Sales	(4,949)	(4,311)	—	—
	(4,949)	(4,311)	27,145	29,251
Royalties	—	—	(1,527)	(1,606)
Revenues (1)	(4,949)	(4,311)	25,618	27,645
Expenses
Purchased Product (1)	(4,278)	(3,587)	11,960	12,680
Transportation and Blending	(417)	(414)	5,451	5,440
Purchased Product, Transportation and Blending (1)	(4,695)	(4,001)	17,411	18,120
Operating	(213)	(195)	3,377	3,478
Realized (Gain) Loss on Risk Management	(25)	3	(31)	38
Unrealized (Gain) Loss on Risk Management	(46)	30	(46)	24
Depreciation, Depletion and Amortization	49	53	2,498	2,428
Exploration Expense	—	—	8	12

(Income) Loss From Equity-Accounted Affiliates	16	(1)	(36)	(37)
Segment Income (Loss)	(35)	(200)	2,437	3,582
General and Administrative	350	421	350	421
Finance Costs, Net	250	276	250	276
Integration, Transaction and Other Costs	79	72	79	72
Foreign Exchange (Gain) Loss, Net	(353)	154	(353)	154
(Gain) Loss on Divestiture of Assets	(3)	(104)	(3)	(104)
Re-measurement of Contingent Payments	—	30	—	30
Other (Income) Loss, Net	(32)	(130)	(32)	(130)
	291	719	291	719
Earnings (Loss) Before Income Tax			2,146	2,863
Income Tax Expense (Recovery)			436	687
Net Earnings (Loss)			1,710	2,176

(1)Comparative period reflects certain revisions. See Note 21.


Cenovus Energy Inc. – Q2 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 June 30, 2025

B) External Sales by Product


	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2025	2024	2025	2024	2025	2024	2025	2024
Crude Oil	4,341	5,819	71	69	72	151	4,484	6,039
Natural Gas and Other	86	100	163	110	201	232	450	442
NGLs (1)	366	137	47	85	62	88	475	310
External Sales	4,793	6,056	281	264	335	471	5,409	6,791


	Downstream
	Canadian Refining		U.S. Refining		Total
For the three months ended June 30,	2025	2024	2025	2024	2025	2024
Gasoline	62	132	3,199	3,782	3,261	3,914
Distillates (2)	346	356	2,322	2,814	2,668	3,170
Synthetic Crude Oil	402	270	—	—	402	270
Asphalt	130	152	241	285	371	437
Other Products and Services (3)	136	127	693	732	829	859
External Sales	1,076	1,037	6,455	7,613	7,531	8,650


	Upstream
For the six months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2025	2024	2025	2024	2025	2024	2025	2024
Crude Oil	9,764	10,694	109	124	218	192	10,091	11,010
Natural Gas and Other	164	180	467	346	429	465	1,060	991
NGLs (1)	769	195	148	171	139	171	1,056	537
External Sales	10,697	11,069	724	641	786	828	12,207	12,538


	Downstream
	Canadian Refining		U.S. Refining		Total
For the six months ended June 30,	2025	2024	2025	2024	2025	2024
Gasoline	111	235	6,313	7,100	6,424	7,335
Distillates (2)	702	748	4,807	5,545	5,509	6,293
Synthetic Crude Oil	806	735	—	—	806	735
Asphalt	200	225	435	431	635	656
Other Products and Services (3)	242	257	1,322	1,437	1,564	1,694
External Sales	2,061	2,200	12,877	14,513	14,938	16,713

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

(2)Includes diesel and jet fuel.

(3)Comparative period reflects certain revisions. See Note 21.


Cenovus Energy Inc. – Q2 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 June 30, 2025

C) Geographical Information


	Revenues (1)
	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Canada	5,388	8,094	11,572	13,298
United States (2)	6,688	6,192	13,521	13,760
China	243	296	525	587
Consolidated	12,319	14,582	25,618	27,645

(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 21.


	Non-Current Assets (1)
	June 30,	December 31,
As at	2025	2024
Canada	37,685	37,006
United States	5,548	5,902
China	1,046	1,249
Indonesia	246	295
Consolidated	44,525	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
	June 30,	December 31,	June 30,	December 31,	June 30,	December 31,
As at	2025	2024	2025	2024	2025	2024
Oil Sands	499	461	24,843	24,646	990	1,018
Conventional	20	15	2,226	2,230	50	57
Offshore	7	8	3,580	3,365	243	95
Canadian Refining	—	—	2,462	2,511	51	39
U.S. Refining	—	—	5,213	5,538	320	342
Corporate and Eliminations	—	—	244	278	390	399
Consolidated	526	484	38,568	38,568	2,044	1,950


	Goodwill		Total Assets
	June 30,	December 31,	June 30,	December 31,
As at	2025	2024	2025	2024
Oil Sands	2,923	2,923	31,705	31,668
Conventional	—	—	2,556	2,610
Offshore	—	—	4,387	4,089
Canadian Refining	—	—	2,912	2,901
U.S. Refining	—	—	8,859	9,517
Corporate and Eliminations	—	—	5,401	5,754
Consolidated	2,923	2,923	55,820	56,539


Cenovus Energy Inc. – Q2 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 June 30, 2025

E) Capital Expenditures (1)


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Capital Investment
Oil Sands	644	613	1,407	1,260
Conventional	73	68	195	194
Offshore
Atlantic	253	266	480	424
Asia Pacific	17	29	31	30
Total Upstream	987	976	2,113	1,908

Canadian Refining	28	70	50	101
U.S. Refining	146	100	223	167
Total Downstream	174	170	273	268

Corporate and Eliminations	3	9	7	15
	1,164	1,155	2,393	2,191
Acquisitions
Oil Sands	136	4	228	6
Conventional	33	1	33	9




	169	5	261	15

Total Capital Expenditures	1,333	1,160	2,654	2,206

(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 July 30, 2025.


Cenovus Energy Inc. – Q2 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 June 30, 2025



3. FINANCE COSTS, NET


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Interest Expense – Short-Term Borrowings and Long-Term Debt	77	77	156	153

Interest Expense – Lease Liabilities (Note 9)	40	40	83	79
Unwinding of Discount on Decommissioning Liabilities (Note 11)	58	56	116	113
Other	10	15	16	21

Capitalized Interest	(21)	(10)	(38)	(18)
Finance Costs	164	178	333	348
Interest Income	(50)	(37)	(83)	(72)
	114	141	250	276



4. FOREIGN EXCHANGE (GAIN) LOSS, NET



	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt	(278)	52	(283)	175
Other	(142)	33	(118)	34
Unrealized Foreign Exchange (Gain) Loss	(420)	85	(401)	209
Realized Foreign Exchange (Gain) Loss	67	(30)	48	(55)
	(353)	55	(353)	154



5. INCOME TAXES



	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Current Tax
Canada	224	300	503	646
United States	—	(9)	—	2
Asia Pacific	57	56	102	100
Other International	11	8	24	17
Total Current Tax Expense (Recovery)	292	355	629	765
Deferred Tax Expense (Recovery)	(127)	(46)	(193)	(78)
	165	309	436	687


Cenovus Energy Inc. – Q2 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 June 30, 2025



6. PER SHARE AMOUNTS

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


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Net Earnings (Loss)	851	1,000	1,710	2,176
Effect of Cumulative Dividends on Preferred Shares	(4)	(9)	(10)	(18)
Net Earnings (Loss) – Basic	847	991	1,700	2,158
Effect of Stock-Based Compensation	(26)	2	(20)	—
Net Earnings (Loss) – Diluted	821	993	1,680	2,158

Basic – Weighted Average Number of Shares (thousands)	1,810,639	1,859,377	1,815,975	1,863,585
Dilutive Effect of Warrants	2,205	4,696	2,391	5,426


Dilutive Effect of Stock-Based Compensation	6,534	10,162	8,077	6,336
Diluted – Weighted Average Number of Shares (thousands)	1,819,378	1,874,235	1,826,443	1,875,347

Net Earnings (Loss) Per Common Share – Basic ($)	0.47	0.53	0.94	1.16
Net Earnings (Loss) Per Common Share – Diluted (1) ($)	0.45	0.53	0.92	1.15

(1)For both the three and six months ended June 30, 2025, 8.9 million (2024 — 10.4 million and 20.4 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 six months ended June 30,	Per Share	Amount	Per Share	Amount
Base Dividends	0.380	691	0.320	596
Variable Dividends	—	—	0.135	251
Total Common Share Dividends Declared and Paid	0.380	691	0.455	847

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

On July 30, 2025, the Company’s Board of Directors declared a third quarter base dividend of $0.200 per common share, payable on September 29, 2025, to common shareholders of record as at September 15, 2025.

C) Preferred Share Dividends


For the six months ended June 30,	2025	2024
Series 1 First Preferred Shares	3	3
Series 2 First Preferred Shares	1	1
Series 3 First Preferred Shares	—	6
Series 5 First Preferred Shares	2	5
Series 7 First Preferred Shares	4	3
Total Preferred Share Dividends Declared	10	18

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

For the six months ended June 30, 2025, the Company paid preferred share dividends of $10 million (2024 – $18 million).

On July 30, 2025, the Company’s Board of Directors declared third quarter preferred share dividends of $2 million payable on October 1, 2025, to preferred shareholders of record as at September 15, 2025.


Cenovus Energy Inc. – Q2 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 June 30, 2025



7. EXPLORATION AND EVALUATION ASSETS, NET


			Total
As at December 31, 2024			484

Additions			43





Exchange Rate Movements and Other			(1)
As at June 30, 2025			526



8. 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	261	—	—	—	261
Additions	2,070	2	268	10	2,350

Change in Decommissioning Liabilities	98	—	—	—	98
Divestitures	(5)	—	—	(6)	(11)
Exchange Rate Movements and Other	(172)	(9)	(623)	(8)	(812)

As at June 30, 2025	54,342	273	13,970	1,971	70,556

ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2024	21,849	141	6,675	1,437	30,102
Depreciation, Depletion and Amortization	1,945	7	343	42	2,337


Divestitures	(1)	—	—	—	(1)
Exchange Rate Movements and Other	(100)	(9)	(339)	(2)	(450)

As at June 30, 2025	23,693	139	6,679	1,477	31,988

CARRYING VALUE
As at December 31, 2024	30,241	139	7,650	538	38,568
As at June 30, 2025	30,649	134	7,291	494	38,568

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


Cenovus Energy Inc. – Q2 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 June 30, 2025



9. 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	182	—	13	199





Exchange Rate Movements and Other	1	(41)	(8)	1	(47)

As at June 30, 2025	597	2,533	170	139	3,439

ACCUMULATED DEPRECIATION
As at December 31, 2024	193	999	94	51	1,337
Depreciation	19	119	4	19	161


Exchange Rate Movements and Other	(1)	(96)	(5)	(1)	(103)

As at June 30, 2025	211	1,022	93	69	1,395

CARRYING VALUE
As at December 31, 2024	399	1,393	84	74	1,950
As at June 30, 2025	386	1,511	77	70	2,044

(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			197
Interest Expense (Note 3)			83
Lease Payments			(260)
Exchange Rate Movements and Other			42
As at June 30, 2025			2,989
Less: Current Portion			371
Long-Term Portion			2,618



10. DEBT AND CAPITAL STRUCTURE

A) Short-Term Borrowings


		June 30,	December 31,
As at	Notes	2025	2024
Uncommitted Demand Facilities	i	—	—

WRB Uncommitted Demand Facilities	ii	256	173
Total Debt Principal		256	173

i) Uncommitted Demand Facilities

As at June 30, 2025, the Company had uncommitted demand facilities of $1.7 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 June 30, 2025, there were outstanding letters of credit aggregating to $363 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).


Cenovus Energy Inc. – Q2 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 June 30, 2025

ii) WRB Uncommitted Demand Facilities

WRB has uncommitted demand facilities of US$450 million (December 31, 2024 – US$450 million) that may be used to cover short-term working capital requirements, of which Cenovus’s proportionate share is 50 percent. As at June 30, 2025, US$376 million was drawn on these facilities, of which Cenovus’s proportionate share was US$188 million (C$256 million). As at December 31, 2024, Cenovus's proportionate share of drawings was US$120 million (C$173 million).

B) Long-Term Debt


	June 30,	December 31,
As at	2025	2024
Committed Credit Facility	—	—
U.S. Dollar Denominated Unsecured Notes (1)	5,187	5,470
Canadian Dollar Unsecured Notes	2,000	2,000
Total Debt Principal	7,187	7,470
Debt Premiums (Discounts), Net, and Transaction Costs	54	64
Long-Term Debt	7,241	7,534
Less: Current Portion	182	192
Long-Term Portion	7,059	7,342

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

As at June 30, 2025, the Company had in place a committed credit facility that consists of a $2.2 billion tranche maturing on June 26, 2027, and a $3.3 billion tranche maturing on June 26, 2028. As at June 30, 2025, no amount was drawn on the credit facility (December 31, 2024 – $nil).

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

As at June 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.

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

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. – Q2 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 June 30, 2025

Net Debt to Adjusted EBITDA


	June 30,	December 31,
As at	2025	2024
Short-Term Borrowings	256	173
Current Portion of Long-Term Debt	182	192
Long-Term Portion of Long-Term Debt	7,059	7,342
Total Debt	7,497	7,707
Less: Cash and Cash Equivalents	(2,563)	(3,093)
Net Debt	4,934	4,614

Net Earnings (Loss)	2,676	3,142
Add (Deduct):
Finance Costs, Net	488	514

Income Tax Expense (Recovery)	678	929
Depreciation, Depletion and Amortization	4,941	4,871
Exploration and Evaluation Asset Write-downs	37	37
(Income) Loss From Equity-Accounted Affiliates	(65)	(66)
Unrealized (Gain) Loss on Risk Management	(58)	12
Foreign Exchange (Gain) Loss, Net	(45)	462
(Gain) Loss on Divestiture of Assets	(18)	(119)
Re-measurement of Contingent Payments	—	30

Other (Income) Loss, Net	43	(55)
Adjusted EBITDA (1)	8,677	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


	June 30,	December 31,
As at	2025	2024
Net Debt	4,934	4,614

Cash From (Used in) Operating Activities	8,192	9,235
(Add) Deduct:
Settlement of Decommissioning Liabilities	(242)	(234)
Net Change in Non-Cash Working Capital	1,142	1,305
Adjusted Funds Flow (1)	7,292	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


	June 30,	December 31,
As at	2025	2024
Net Debt	4,934	4,614
Shareholders’ Equity	29,402	29,754
Capitalization	34,336	34,368

Net Debt to Capitalization (percent)	14	13


Cenovus Energy Inc. – Q2 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 June 30, 2025



11. DECOMMISSIONING LIABILITIES


			Total
As at December 31, 2024			4,534
Liabilities Incurred			12
Liabilities Acquired			82
Liabilities Settled			(104)


Change in Estimated Future Cash Flows			86

Unwinding of Discount on Decommissioning Liabilities (Note 3)			116
Exchange Rate Movements			(16)
As at June 30, 2025			4,710

As at June 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).



12. OTHER LIABILITIES


	June 30,	December 31,
As at	2025	2024
Renewable Volume Obligation, Net (1)	322	284
Pension and Other Post-Employment Benefit Plan	262	269
Employee Long-Term Incentives	75	96
Provisions for Onerous and Unfavourable Contracts	62	66
Provision for West White Rose Expansion Project	11	54



Other	141	150
	873	919

(1)The gross amounts of the renewable volume obligation and renewable identification numbers asset were $940 million and $618 million, respectively (December 31, 2024 – $652 million and $368 million, respectively).



13. 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


	June 30, 2025		December 31, 2024
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	1,825,038	15,659	1,871,868	16,031
Issued Under Stock Option Plans	653	9	5,049	68
Purchase of Common Shares Under NCIB	(20,177)	(173)	(55,861)	(479)
Issued Upon Exercise of Warrants	428	4	3,982	39
Outstanding, End of Period	1,805,942	15,499	1,825,038	15,659

As at June 30, 2025, there were 24.8 million common shares available for future issuance under the stock option plan.


Cenovus Energy Inc. – Q2 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 June 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 six months ended June 30, 2025, the Company purchased and cancelled 20.2 million common shares through the NCIB. The shares were purchased at a volume weighted average price of $17.64 per common share for a total of $356 million. Paid in surplus was reduced by $190 million, of which $183 million represents the excess of the purchase price of the common shares over their average carrying value and $7 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.


	June 30, 2025		December 31, 2024
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	2,000	43	—	—
Purchased Under Employee Benefit Plan	3,600	73	2,000	43
Distributed Under Employee Benefit Plan	(3,821)	(82)	—	—

Outstanding, End of Period	1,779	34	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


	June 30, 2025		December 31, 2024
	Number of Preferred Shares (thousands)	Amount	Number of Preferred Shares (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 June 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

4.37

1,260

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


Cenovus Energy Inc. – Q2 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 June 30, 2025

F) Issued and Outstanding – Warrants


	June 30, 2025		December 31, 2024
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	3,643	12	7,625	25

Exercised	(428)	(1)	(3,982)	(13)

Outstanding, End of Period	3,215	11	3,643	12

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



14. 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	24	140	393	557

Income Tax (Expense) Recovery	(6)	(16)	—	(22)
As at June 30, 2024	73	209	1,461	1,743

As at December 31, 2024	69	156	2,088	2,313
Other Comprehensive Income (Loss), Before Tax	10	(4)	(672)	(666)

Income Tax (Expense) Recovery	(2)	—	—	(2)
As at June 30, 2025	77	152	1,416	1,645



15. 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 June 30, 2025, no Cenovus replacement stock options were outstanding.

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


	Units Outstanding	Units Exercisable
As at June 30, 2025	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	11,624	5,564

Performance Share Units	7,589	—
Restricted Share Units	10,134	—
Deferred Share Units	2,046	2,046

The weighted average exercise price of NSRs outstanding as at June 30, 2025, was $18.96.


Cenovus Energy Inc. – Q2 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 June 30, 2025


	Units Granted	Units Vested and Exercised/ Paid Out
For the six months ended June 30, 2025	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	4,361	644
Cenovus Replacement Stock Options	—	329
Performance Share Units	3,344	2,270
Restricted Share Units	4,343	1,936
Deferred Share Units	345	99


	Weighted Average Exercise Price	Units Exercised
For the six months ended June 30, 2025	($/unit)	(thousands)
Stock Options With Associated Net Settlement Rights Exercised for Net Cash Payment	12.64	316
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 9 thousand common shares.

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


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Stock Options With Associated Net Settlement Rights	3	3	6	7
Cenovus Replacement Stock Options	1	—	(1)	3
Performance Share Units	5	13	15	61
Restricted Share Units	7	17	21	52
Deferred Share Units	(2)	1	(1)	12
Stock-Based Compensation Expense (Recovery)	14	34	40	135

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.



16. RELATED PARTY TRANSACTIONS

Husky Midstream Limited Partnership

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


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Revenues from Construction and Management Services	37	38	66	69
Transportation Expenses	69	71	137	140


Cenovus Energy Inc. – Q2 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 June 30, 2025



17. 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 June 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			(4)
As at June 30, 2025			212

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. – Q2 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 June 30, 2025

Summary of Risk Management Positions



	June 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	8	16	(8)	9	10	(1)
Power Contracts	6	—	6	6	—	6
Renewable Power Contracts	47	1	46	5	—	5
Foreign Exchange Rate Contracts	2	—	2	—	3	(3)
	63	17	46	20	13	7

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


	June 30,	December 31,
As at	2025	2024
Level 2 – Prices Sourced From Observable Data or Market Corroboration	—	2
Level 3 – Prices Sourced From Partially Unobservable Data	46	5
	46	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			48
Change in Fair Value of Contracts Entered Into During the Period			22
Fair Value of Contracts Realized During the Period			(31)

As at June 30, 2025			46

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


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Realized (Gain) Loss	(23)	28	(31)	38
Unrealized (Gain) Loss	(69)	(7)	(46)	24
(Gain) Loss on Risk Management	(92)	21	(77)	62

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


Cenovus Energy Inc. – Q2 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 June 30, 2025



18. 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 June 30, 2025, the fair value of risk management positions was a net asset of $46 million. As at June 30, 2025, there were foreign exchange contracts with a notional value of US$150 million (December 31, 2024 – US$250 million). As at June 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 June 30, 2025

Notional Volumes (1) (2)

Terms

Weighted

Average

Price (2)

Fair Value Asset (Liability)

WTI Contracts Related to Blending (3)

WTI Fixed – Sell

5.5 MMbbls

July 2025 - December 2026

US$63.41/bbl

—

WTI Fixed – Buy

0.1 MMbbls

July 2025 - December 2026

US$61.51/bbl

—

Power Contracts

Renewable Power Contracts

Other Financial Positions (4)

(8)

Foreign Exchange Rate Contracts

Total Fair Value

(1) Million barrels (“MMbbls”).

(2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month.

(3) Includes individual WTI contracts with varying terms, the longest of which is 18 months. WTI contracts related to blending are used to help manage price exposure to condensate used for blending.

(4) Includes risk management positions related to Western Canadian Select (“WCS”), heavy oil, light oil and condensate differentials, benchmark delivery location spreads, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts and the Company’s U.S. refining and marketing activities.

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 June 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	3	(3)
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(3)	3
Natural Gas Commodity Price	± US$0.50/Mcf (2) Applied to Natural Gas Hedges Tied to Production	—	—
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	13	(15)

(1)Excluding WCS at Hardisty.

(2)One thousand cubic feet (“Mcf”).

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


Cenovus Energy Inc. – Q2 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 June 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 June 30, 2025, approximately 74 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 0.4 percent as at June 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 10, 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 June 30, 2025	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	6,218	—	—	—	6,218
Short-Term Borrowings	256	—	—	—	256

Lease Liabilities (1)	526	890	684	2,504	4,604
Long-Term Debt (1)	498	3,081	675	6,805	11,059

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



19. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital


	June 30,	December 31,
As at	2025	2024
Total Current Assets	9,456	10,434
Total Current Liabilities	7,142	7,362
Working Capital	2,314	3,072

B) Changes in Non-Cash Working Capital


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2025	2024	2025	2024
Accounts Receivable and Accrued Revenues	(270)	111	(365)	(578)
Income Tax Receivable	244	(39)	166	177
Inventories	280	(140)	440	(381)
Accounts Payable and Accrued Liabilities	543	640	2	956
Income Tax Payable	48	(37)	(282)	(9)
Total Change in Non-Cash Working Capital	845	535	(39)	165

Net Change in Non-Cash Working Capital – Operating Activities	923	494	62	225
Net Change in Non-Cash Working Capital – Investing Activities	(78)	41	(101)	(60)
Total Change in Non-Cash Working Capital	845	535	(39)	165


Cenovus Energy Inc. – Q2 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 June 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	—	—	(39)	—	—

Principal Repayment of Leases	—	—	—	—	(145)
Dividends Paid	(865)	—	—	—	—


Non-Cash Changes:

Finance and Transaction Costs	—	—	—	(8)	—

Lease Additions	—	—	—	—	20
Base Dividends Declared on Common Shares	596	—	—	—	—
Variable Dividends Declared on Common Shares	251	—	—	—	—
Dividends Declared on Preferred Shares	18	—	—	—	—

Exchange Rate Movements and Other	—	—	(3)	175	67
As at June 30, 2024	9	—	137	7,275	2,600

As at December 31, 2024	—	—	173	7,534	2,927
Acquisition	—	—	—	12	—
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	66	—	—
Repayment of Long-Term Debt	—	—	—	(12)	—
Principal Repayment of Leases	—	—	—	—	(177)
Proceeds on Repurchase Agreements	—	330	—	—	—
Repayment of Repurchase Agreements	—	(102)	—	—	—



Dividends Paid	(701)	—	—	—	—
Non-Cash Changes:
Finance and Transaction Costs	—	—	—	(10)	—
Lease Additions	—	—	—	—	197
Base Dividends Declared on Common Shares	691	—	—	—	—

Dividends Declared on Preferred Shares	10	—	—	—	—
Exchange Rate Movements and Other	—	(13)	17	(283)	42
As at June 30, 2025	—	215	256	7,241	2,989



20. 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 June 30, 2025	Remainder of Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	1,081	2,015	1,976	1,950	1,861	14,431	23,314


Real Estate	32	63	60	59	63	532	809
Obligation to Fund HCML	49	99	93	54	42	99	436
Other Long-Term Commitments	466	202	199	165	118	580	1,730
Total Commitments	1,628	2,379	2,328	2,228	2,084	15,642	26,289

(1)Includes transportation commitments that are subject to regulatory approval or were approved but are not yet in service of $34 million. Terms are up to 7 years on commencement.

(2)As at June 30, 2025, includes $1.8 billion related to transportation and storage commitments with HMLP.


Cenovus Energy Inc. – Q2 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 June 30, 2025

There were outstanding letters of credit aggregating to $363 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.



21. 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 six months ended June 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 June 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,918	(303)	7,615	14,885	(303)	14,582
Purchased Product	7,124	(303)	6,821	7,184	(303)	6,881
Transportation and Blending	—	—	—	2,865	—	2,865
Purchased Product, Transportation and Blending	7,124	(303)	6,821	10,049	(303)	9,746
	794	—	794	4,836	—	4,836


	U.S. Refining Segment			Consolidated
For the six months ended June 30, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	15,153	(637)	14,516	28,282	(637)	27,645
Purchased Product	13,256	(637)	12,619	13,317	(637)	12,680
Transportation and Blending	—	—	—	5,440	—	5,440
Purchased Product, Transportation and Blending	13,256	(637)	12,619	18,757	(637)	18,120
	1,897	—	1,897	9,525	—	9,525


Cenovus Energy Inc. – Q2 2025 Interim Consolidated Financial Statements			30

EX-99.4 5 q22025ceocertificate.htm EX-99.4 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 June 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 April 1, 2025 and ended on June 30, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: July 31, 2025

/s/ Jonathan M. McKenzie

Jonathan M. McKenzie

President & Chief Executive Officer

EX-99.5 6 q22025cfocertificate.htm EX-99.5 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:

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 June 30, 2025.

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: July 31, 2025

/s/ Karamjit S. Sandhar

Karamjit S. Sandhar

Executive Vice-President & Chief Financial Officer