Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Period Ended March 31, 2025

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the period ended March 31, 2025

TABLE OF CONTENTS

OVERVIEW OF CENOVUS	3
QUARTERLY RESULTS OVERVIEW	4
OPERATING AND FINANCIAL RESULTS	6
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	10
OUTLOOK	14
REPORTABLE SEGMENTS	16
UPSTREAM	16
OIL SANDS	16
CONVENTIONAL	20
OFFSHORE	22
DOWNSTREAM	25
CANADIAN REFINING	25
U.S. REFINING	27
CORPORATE AND ELIMINATIONS	29
LIQUIDITY AND CAPITAL RESOURCES	30
RISK MANAGEMENT AND RISK FACTORS	34
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	35
CONTROL ENVIRONMENT	35
ADVISORY	35
ABBREVIATIONS AND DEFINITIONS	38
SPECIFIED FINANCIAL MEASURES	39
PRIOR PERIOD REVISIONS	49

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 May 7, 2025, should be read in conjunction with our March 31, 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 May 7, 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 May 7, 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. – Q1 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. For further details, see our 2025 corporate guidance dated December 11, 2024, available on our website at cenovus.com.

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. – Q1 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

During the first quarter of 2025, we saw strong operational performance across our upstream assets and improved operational performance in our downstream operations. Crude oil benchmark prices, market crack spreads and economic markets were volatile in the quarter due to uncertainty around a rapidly changing tariff environment and anticipation of increasing global crude oil supply, which impacted our financial results.

•Delivered safe and reliable operations. We delivered safe operations across our business, and we continue to strive to improve our safety record. Safety continues to be our top priority.

•Maintained strong upstream production. Upstream production was 818.9 thousand barrels of oil equivalent per day, compared with 816.0 thousand barrels of oil equivalent per day in the fourth quarter of 2024. Production increased due to strong results from our optimization programs and new sustaining well pads brought online in the quarter at Foster Creek. In the Conventional segment, production increased due to strong base performance and bringing on wells in 2025 that had been deferred in 2024 due to lower AECO pricing. The increases were offset by lower production at Christina Lake as our fourth quarter production benefited from positive post-turnaround impacts.

•Progressed key Oil Sands growth projects. The Narrows Lake tie-back to Christina Lake began steaming in April and is on track for first oil early in the third quarter, as planned. Construction of the Foster Creek optimization project is on track and on budget, and was approximately 75 percent complete as at March 31, 2025. 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. The SeaRose floating production storage and offloading (“FPSO”) vessel resumed operations and production safely restarted at the White Rose field in the first quarter. The West White Rose project was approximately 90 percent complete as at March 31, 2025, and preparations are underway to tow the concrete gravity structure to the field in the second quarter, with the transport of the topsides expected to occur in the third quarter.

•Achieved record crude oil unit throughput at our Canadian Refining assets. The Lloydminster Upgrader (the “Upgrader”) and the Lloydminster Refinery ran at, or above, capacity during the quarter. Average crude oil unit throughput (or “throughput”) was 111.9 thousand barrels per day and crude unit utilization was 104 percent, compared with 104.4 thousand barrels per day and crude unit utilization of 97 percent in the fourth quarter of 2024.

•Building operational momentum in our U.S. Refining segment. Revenues from U.S. Refining decreased two percent to $6.4 billion; however, Adjusted Refining Margin(1) increased 41 percent to $8.41 per barrel and Adjusted Market Capture(1) increased to 62 percent from 52 percent in the fourth quarter of 2024, primarily due to improved process unit reliability at our operated refineries. We began turnarounds at both of our non-operated refineries in March and the Toledo Refinery turnaround began in April.

•Reported solid financial results. Adjusted Funds Flow increased to $2.2 billion from $1.6 billion in the fourth quarter of 2024, mainly due to increased sales volumes and higher realized pricing in our upstream operations. Cash from operating activities was $1.3 billion, down from $2.0 billion in the fourth quarter of 2024, mainly due to changes in non-cash working capital.

•Redemption of preferred shares. On March 31, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company’s series 5 preferred shares at a price of $25.00 per share, for a total of $200 million.

•Credit rating upgrade. On March 31, 2025, we received a rating upgrade from Moody’s to Baa1 with a Stable outlook.

•Base dividend increase. On May 7, 2025, the Board declared a second quarter base dividend of $0.200 per common share, an increase of 11 percent from the first quarter dividend declared in February 2025.

(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Adjusted Refining Margin is the Gross Margin after adjusting for inventory holding gains or losses, on a per-barrel basis. Adjusted Market Capture is an indication of margin captured relative to what was available in the market based on widely-used benchmarks, after adjusting for inventory holding gains or losses.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  4

Summary of Quarterly Results

	2025	2024				2023
($ millions, except where indicated)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Upstream Production Volumes (1)(MBOE/d)	818.9	816.0	771.3	800.8	800.9	808.6	797.0	729.9
Downstream Total Processed Inputs (2) (3) (Mbbls/d)	700.5	700.5	674.4	652.9	683.8	605.7	691.3	566.9
Crude Oil Unit Throughput (2)(Mbbls/d)	665.4	666.7	642.9	622.7	655.2	579.1	664.3	537.8
Downstream Production Volumes (1)(2)(Mbbls/d)	722.4	722.6	685.2	659.5	702.1	627.4	706.0	571.9
Revenues (4)	13,299	12,813	13,819	14,582	13,063	13,134	14,577	12,231
Operating Margin (5)	2,811	2,274	2,408	2,936	3,191	2,151	4,369	2,400
Operating Margin – Upstream (6)	3,048	2,670	2,731	3,089	2,631	2,455	3,447	2,257
Operating Margin – Downstream (6)	(237)	(396)	(323)	(153)	560	(304)	922	143
Cash From (Used In) Operating Activities	1,315	2,029	2,474	2,807	1,925	2,946	2,738	1,990
Adjusted Funds Flow (5)	2,212	1,601	1,960	2,361	2,242	2,062	3,447	1,899
Per Share – Basic (5) ($)	1.21	0.88	1.06	1.27	1.20	1.10	1.82	1.00
Per Share – Diluted (5)($)	1.21	0.87	1.05	1.26	1.19	1.08	1.81	0.98
Capital Investment	1,229	1,478	1,346	1,155	1,036	1,170	1,025	1,002
Free Funds Flow (5)	983	123	614	1,206	1,206	892	2,422	897
Excess Free Funds Flow (5)	373	(416)	146	735	832	471	1,989	505
Net Earnings (Loss)	859	146	820	1,000	1,176	743	1,864	866
Per Share – Basic ($)	0.47	0.08	0.44	0.53	0.62	0.39	0.98	0.45
Per Share – Diluted ($)	0.47	0.07	0.42	0.53	0.62	0.32	0.97	0.44
Total Assets	56,380	56,539	54,680	56,000	54,994	53,915	54,427	53,747
Long-Term Debt, Including Current Portion	7,524	7,534	7,199	7,275	7,227	7,108	7,224	8,534
Net Debt	5,079	4,614	4,196	4,258	4,827	5,060	5,976	6,367
Cash Returns to Common and Preferred Shareholders	595	706	1,070	1,034	436	731	1,225	584
Common Shares – Base Dividends	327	330	329	334	262	261	264	265
Base Dividends Per Common Share($)	0.180	0.180	0.180	0.180	0.140	0.140	0.140	0.140
Common Shares – Variable Dividends	—	—	—	251	—	—	—	—
Variable Dividends Per Common Share($)	—	—	—	0.135	—	—	—	—
Purchase of Common Shares Under NCIB (7)	62	108	732	440	165	350	361	310
Payment for Purchase of Warrants	—	—	—	—	—	111	600	—
Dividends Paid on Preferred Shares	6	18	9	9	9	9	—	9
Preferred Share Redemptions	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.

(7)Normal course issuer bid (“NCIB”).

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  5

OPERATING AND FINANCIAL RESULTS

Selected Operating and Financial Results — Upstream

	Three Months Ended March 31,
		Percent Change
	2025		2024
Production Volumes by Segment (1) (MBOE/d)
Oil Sands	626.2	2	615.3
Conventional(2)	123.9	3	120.7
Offshore (3)	68.8	6	64.9
Total Production Volumes	818.9	2	800.9
Production Volumes by Product (1)
Bitumen (Mbbls/d)	602.5	1	595.4
Heavy Crude Oil (Mbbls/d)	21.8	22	17.9
Light Crude Oil (Mbbls/d)	16.8	34	12.5
NGLs (Mbbls/d)	29.8	(8)	32.4
Conventional Natural Gas (MMcf/d)	887.9	4	855.8
Total Production Volumes (MBOE/d)	818.9	2	800.9
Per-Unit Operating Expenses by Segment ($/BOE)
Oil Sands (4)	11.77	(1)	11.86
Conventional (2) (5)	10.92	(16)	13.05
Offshore (3) (5)	15.50	(10)	17.31

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

(2)For the three months ended March 31, 2025, reported Conventional segment production and per-unit operating expenses includes 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, for the three months ended March 31, 2025, were $127 million.

(3)Reported Offshore segment production and per-unit operating expenses includes 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 months ended March 31, 2025, were $89 million (2024 – $85 million).

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

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

Production

Total upstream production increased in the first quarter of 2025 compared with 2024 due to:

•Successful results from our optimization programs and new sustaining well pads at Foster Creek.

•Strong performance at the Terra Nova field and the safe restart of production at the White Rose field as the SeaRose FPSO resumed operations in our Atlantic region.

•Solid base production and new development wells at our Lloydminster conventional heavy oil assets.

Per-Unit Operating Expenses

For the three months ended March 31, 2025, per-unit operating expenses were relatively consistent in the Oil Sands segment, compared with the same period in 2024. Per-unit operating expenses decreased in the Conventional segment mainly due to lower processing and gathering costs. Per-unit operating expenses decreased in the Offshore segment compared with 2024, primarily due to higher sales volumes in our Atlantic operations. 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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  6

Selected Operating and Financial Results — Downstream

	Three Months Ended March 31,
		Percent Change
	2025		2024
Crude Oil Unit Throughput by Segment (Mbbls/d)
Canadian Refining	111.9	7	104.1
U.S. Refining	553.5	—	551.1
Total Crude Oil Unit Throughput	665.4	2	655.2
Production Volumes by Product (1)(Mbbls/d)
Gasoline	284.7	1	281.9
Distillates (2)	224.3	5	213.0
Synthetic Crude Oil	52.4	11	47.1
Asphalt	42.3	1	41.7
Ethanol	4.3	(20)	5.4
Other	114.4	1	113.0
Total Production Volumes	722.4	3	702.1
Per-Unit Operating Expenses by Segment (3) ($/bbl)
Canadian Refining	10.81	(27)	14.83
U.S. Refining	13.69	18	11.65
Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3)($/bbl)
Canadian Refining	10.81	(19)	13.36
U.S. Refining	12.15	10	11.01

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

(2)Includes diesel and jet fuel.

(3)Specified financial measure. 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.

In the first quarter of 2025, total downstream throughput and refined product production increased slightly compared with the same period in 2024. The increases were primarily due to our Canadian Refining assets running at, or above, capacity and improved process unit reliability at our operated refineries in the U.S. Refining segment.

In the first quarter of 2025, per-unit operating expenses, excluding turnaround costs, decreased in the Canadian Refining segment compared with the same period in 2024, primarily due to record throughput as a result of high reliability, combined with less overall project expenses. Per-unit operating expenses, excluding turnaround costs, in the U.S. Refining segment increased quarter-over-quarter, primarily due to higher energy costs and the weakening of the Canadian dollar relative to the U.S. dollar. On average, the Canadian dollar was six percent weaker than the U.S. dollar compared with the first quarter of 2024. Overall, controllable operating expenses excluding turnaround costs in the U.S. Refining segment decreased slightly when compared with the first quarter of 2024.

Selected Consolidated Financial Results

Revenues

Revenues increased two percent to $13.3 billion compared with the first quarter of 2024. Upstream revenue increased 17 percent compared with 2024, primarily due to the narrowing of the WTI-WCS and condensate-WCS differentials, and increased sales volumes. Downstream revenues decreased six percent compared with 2024, primarily due to lower refined product pricing.

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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 March 31,
($ millions)	2025	2024
Gross Sales
External Sales (1)	14,205	13,810
Intersegment Sales	2,752	2,287
	16,957	16,097
Royalties	(906)	(747)
Revenues (1)	16,051	15,350
Expenses
Purchased Product (1)	8,249	7,656
Transportation and Blending	3,247	2,811
Operating Expenses	1,747	1,685
Realized (Gain) Loss on Risk Management Activities	(3)	7
Operating Margin	2,811	3,191

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

Operating Margin by Segment

Three Months Ended March 31, 2025 and 2024

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

•Lower market crack spreads impacting our U.S. Refining segment.

•Higher heavy crude feedstock costs in both our Canadian and U.S. Refining segments, as the narrowing of the WTI-WCS differential increased the costs of some feedstocks entering our refineries.

The decreases were partially offset by higher Operating Margin in our Oil Sands segment due to higher Realized Sales Prices as a result of the narrowing of the WTI-WCS differential following the startup of the Trans Mountain Pipeline expansion project (“TMX”) and higher overall sales volumes. The increase was partially offset by higher transportation expenses.

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

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

	Three Months Ended March 31,
($ millions)	2025	2024
Cash From (Used in) Operating Activities	1,315	1,925
(Add) Deduct:
Settlement of Decommissioning Liabilities	(36)	(48)
Net Change in Non-Cash Working Capital	(861)	(269)
Adjusted Funds Flow	2,212	2,242

Adjusted Funds Flow was relatively consistent in the first quarter of 2025 compared with 2024, as the decrease in Operating Margin was mainly offset by a decrease in stock-based compensation costs.

Cash from operating activities decreased in the first quarter of 2025 compared with the same period in 2024, primarily due to changes in non-cash working capital, combined with lower Operating Margin. The net change in non-cash working capital resulted in a use of cash of $861 million due to decreased accounts payable and income taxes payable. In the first quarter of 2024, changes in non-cash working capital resulted in a use of cash of $269 million.

Net Earnings (Loss)

Net earnings in the first quarter of 2025 was $859 million (2024 – $1.2 billion). The decrease was primarily due to lower Operating Margin, higher depreciation, depletion and amortization expense, and a gain on divestiture of assets in 2024. The decrease was partially offset by lower income tax expense, minimal foreign exchange gains or losses in 2025 compared with a net foreign exchange loss of $99 million in 2024, and lower general and administrative costs.

Net Debt

As at ($ millions)	March 31, 2025	December 31, 2024
Short-Term Borrowings	323	173
Current Portion of Long-Term Debt	192	192
Long-Term Portion of Long-Term Debt	7,332	7,342
Total Debt	7,847	7,707
Cash and Cash Equivalents	(2,768)	(3,093)
Net Debt	5,079	4,614

Total debt increased primarily due to higher short-term borrowings under the WRB uncommitted demand facilities. Net Debt increased by $465 million from December 31, 2024, mainly due to capital investment of $1.2 billion, base dividends of $327 million, preferred share redemptions of $200 million and the increase in short-term borrowings, as discussed above, partially offset by cash from operating activities of $1.3 billion. For further details, see the Liquidity and Capital Resources section of this MD&A.

Capital Investment (1)

	Three Months Ended March 31,
($ millions)	2025	2024
Upstream
Oil Sands	763	647
Conventional	122	126
Offshore	241	159
Total Upstream	1,126	932
Downstream
Canadian Refining	22	31
U.S. Refining	77	67
Total Downstream	99	98
Corporate and Eliminations	4	6
Total Capital Investment	1,229	1,036

(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.

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

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

•The progression of the West White Rose project.

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

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

•Sustaining activities in our refining segments.

Drilling Activity

	Net Stratigraphic Test Wells and Observation Wells		Net Production Wells (1)
Three Months Ended March 31,	2025	2024	2025	2024
Foster Creek	73	82	8	7
Christina Lake	65	58	5	1
Sunrise	21	40	—	—
Lloydminster Thermal	—	—	2	3
Lloydminster Conventional Heavy Oil	—	—	9	2
	159	180	24	13

(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.

	Three Months Ended March 31, 2025			Three Months Ended March 31, 2024
(net wells)	Drilled	Completed	Tied-in	Drilled	Completed	Tied-in
Conventional (1)	13	14	13	16	11	5

(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 quarter of 2025 or 2024.

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

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

Selected Benchmark Prices and Exchange Rates (1)

(Average US$/bbl, unless otherwise indicated)	Q1 2025	Percent Change	Q1 2024	Q4 2024
Dated Brent	75.66	(9)	83.24	74.69
WTI	71.42	(7)	76.96	70.27
Differential Dated Brent – WTI	4.24	(32)	6.28	4.42
WCS at Hardisty	58.75	2	57.65	57.71
Differential WTI – WCS at Hardisty	12.67	(34)	19.31	12.56
WCS at Hardisty (C$/bbl)	84.31	8	77.77	80.74
WCS at Nederland	67.74	(3)	69.89	65.69
Differential WTI – WCS at Nederland	3.68	(48)	7.07	4.58
Condensate (C5 at Edmonton)	69.88	(4)	72.78	70.66
Differential Condensate – WTI Premium/(Discount)	(1.54)	(63)	(4.18)	0.39
Differential Condensate – WCS at HardistyPremium/(Discount)	11.13	(26)	15.13	12.95
Condensate (C$/bbl)	100.29	2	98.18	98.84

(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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  10

Selected Benchmark Prices and Exchange Rates — Continued (1)

(Average US$/bbl, unless otherwise indicated)	Q1 2025	Percent Change	Q1 2024	Q4 2024
Synthetic at Edmonton	69.07	(1)	69.42	71.11
Differential Synthetic – WTI Premium/(Discount)	(2.35)	(69)	(7.54)	0.84
Synthetic at Edmonton (C$/bbl)	99.12	6	93.65	99.45
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	83.08	(7)	89.48	78.95
Chicago Ultra-low Sulphur Diesel (“ULSD”)	89.12	(15)	104.27	89.28
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)	13.68	(22)	17.45	12.12
Group 3 3-2-1 Crack Spread (2)	16.48	(6)	17.50	12.66
Renewable Identification Numbers (“RINs”)	4.76	29	3.68	4.02
Upgrading Differential (3) (C$/bbl)	14.69	(6)	15.65	18.64
Natural Gas Prices
AECO (4)(C$/Mcf)	2.17	(13)	2.50	1.48
NYMEX (5)(US$/Mcf)	3.65	63	2.24	2.79
Foreign Exchange Rates
US$ per C$1 – Average	0.697	(6)	0.741	0.715
US$ per C$1 – End of Period	0.696	(6)	0.738	0.695
RMB per C$1 – Average	5.069	(5)	5.330	5.142

(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 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 first quarter of 2025, crude oil benchmark prices, Brent and WTI, decreased compared with the first quarter of 2024, due to uncertainty surrounding the U.S. economy, tariff policies and anticipation of increasing global supply with the potential unwinding of OPEC+ voluntary production cuts starting in May 2025. Relative to the fourth quarter of 2024, crude oil benchmark prices increased due to volatility in prices from continued geopolitical uncertainty, new U.S. sanctions targeting Iran and Venezuela, and low global and U.S. crude inventories. Geopolitical events related to Russia and Ukraine, Israel and Gaza, Iran, Venezuela and Guyana have added to volatility and risk premiums, but had a limited impact on physical supply and demand in global oil markets.

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. For the first quarter of 2025, the WTI-WCS differential at Hardisty narrowed compared with the first quarter of 2024, due to the start-up of 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 first quarter of 2025, the WTI-WCS at Nederland differential narrowed compared with the first and fourth quarters of 2024, due to strong global demand for heavy crudes, declining output from Mexico and continued voluntary production cuts from OPEC+ members, including Saudi Arabia.

In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Upgrader. The price realized for HSB is primarily driven by the price of WTI, and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  11

In the first quarter of 2025, synthetic crude oil at Edmonton was priced at a smaller discount to WTI, compared with the first quarter of 2024. The increase in pricing relative to the first quarter of 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. The synthetic crude oil price at Edmonton was priced at a discount to WTI in the first quarter of 2025, compared with a premium in the fourth quarter of 2024, as production of Canadian light crude oil is near record highs and the threat of tariffs has decreased the value relative to U.S. light crude oil grades.

Crude Oil Benchmark Prices (1)

(1)Forward pricing as at April 4, 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 first quarter of 2025, the average Edmonton condensate benchmark traded at a smaller discount to WTI compared with the first quarter of 2024, due to the same factors impacting the synthetic crude oil to WTI differential, as discussed above.

Refining Benchmarks

RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel, using current-month WTI- based crude oil feedstock prices and valued on a last-in, first-out basis.

In the first quarter of 2025, refined product prices declined compared with the first quarter in 2024, due to high global and regional supply of refined products as a result of incremental global refining capacity additions and U.S. refineries operating at high utilization rates for most of the quarter, especially in PADD 2 where some expected spring maintenance was deferred to later in the year. The average cost of RINs were higher in the first quarter of 2025 compared with the first and fourth quarters 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 refining margins are affected by various other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as our feedstock is valued on a first-in, first-out (“FIFO”) accounting basis. 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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  12

Refined Product Benchmarks (1)

(1)Forward pricing as at April 4, 2025.

Natural Gas Benchmarks

In the first quarter of 2025, AECO prices increased compared with the fourth quarter of 2024, but weakened compared with the first quarter of 2024, due to strong production levels and limited Western Canadian takeaway capacity. NYMEX natural gas prices increased compared with the first and fourth quarters of 2024, due to strong liquified natural gas (“LNG”) demand and low level of supply in U.S. inventory. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.

Foreign Exchange Benchmarks

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

In the first quarter of 2025, on average, the Canadian dollar weakened relative to the U.S. dollar compared with the first quarter of 2024, positively impacting our reported revenues and negatively impacting our U.S. Refining operating expenses. Although volatile throughout the period, the Canadian dollar ended the quarter unchanged compared with December 31, 2024.

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 first quarter of 2025, on average, the Canadian dollar weakened relative to RMB, compared with the first quarter 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 March 31, 2025, the Bank of Canada’s Policy Interest Rate was 2.75 percent. On April 16, 2025, the Bank of Canada held the overnight rate at 2.75 percent.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  13

OUTLOOK

Commodity Price Outlook

Recent U.S. tariffs announcements, pauses, delays and modifications have introduced significant uncertainty in the market and raised the probabilities 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.

Global crude oil prices have trended lower between the first quarter of 2024 and the first quarter of 2025. OPEC+ policy continues to remain crucial to global oil supply and demand balances, and prices. The potential unwinding of OPEC+ voluntary production cuts starting 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 quarter 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 Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-OPEC+ supply growth, developments relating to conflicts involving Iran and attacks on vessels in the Red Sea, and tensions between Venezuela and Guyana.

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

Refined product prices have trended lower in 2024 and 2025, as a result of incremental global capacity additions and U.S. refineries operating at very high utilization rates. Forward curves are showing signs of refined product crack spreads strengthening later in 2025.

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.

•NYMEX and AECO 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 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 policies toward Canada-U.S. trade, crude oil prices and emerging macro-economic factors.

Most of our upstream crude oil and downstream refined product production is exposed to movements in the WTI crude oil price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane, and is used as crude oil feedstock at our downstream refining operations. Condensate extracted from our blended crude oil is sold back to our Oil Sands segment.

Our refining capacity is focused in the U.S. Midwest, along with smaller exposures in the USGC and Alberta, exposing Cenovus to market crack spreads in these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly.

Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our refining capacity, and to a lesser degree, in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differentials, which could be subject to transportation constraints.

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

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

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

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

•Traditional crude oil storage tanks in various geographic locations.

Key Priorities for 2025

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

Top-tier Safety Performance

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

Downstream Competitiveness

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

We will continue to capitalize on our operational momentum in our downstream assets, leveraging our upstream expertise to maximize the long-term profitability of our assets.

Oil Sands Business

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

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 Narrows Lake tie-back to Christina Lake project, the Sunrise growth program and the Lloydminster conventional heavy oil growth project.

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.

Returns to Shareholders

Maintaining a strong balance sheet with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle is a key element of Cenovus’s capital allocation framework. We plan to steward Net Debt to $4.0 billion and return 100 percent of Excess Free Funds Flow to shareholders over time. For further details, see the Liquidity and Capital Resources section of this MD&A.

Sustainability

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

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

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  15

REPORTABLE SEGMENTS

UPSTREAM

Oil Sands

In the first quarter of 2025, we:

•Delivered safe and reliable operations.

•Produced 626.2 thousand BOE per day (2024 – 615.3 thousand BOE per day).

•Delivered successful results from our sustaining and optimization programs.

•Generated Operating Margin of $2.5 billion, an increase of $308 million compared with 2024, due to higher Realized Sales Prices as a result of the narrowing of the WTI-WCS differential since the startup of TMX and higher overall sales volumes. The increase was partially offset by increased transportation expenses due in part to the use of TMX.

•Earned a Netback of $44.34 per barrel (2024 – $40.79 per barrel).

•Invested capital of $763 million, primarily for sustaining activities and our integrated winter program, as well as growth projects. We continued to progress the Foster Creek optimization project and the Lloydminster conventional heavy oil drilling program. The Narrows Lake tie-back to Christina Lake began steaming in April and is on track for first oil early in the third quarter, as planned.

Financial Results

	Three Months Ended March 31,
($ millions)	2025	2024
Gross Sales
External Sales	5,904	5,013
Intersegment Sales	1,953	1,615
	7,857	6,628
Royalties	(861)	(697)
Revenues	6,996	5,931
Expenses
Purchased Product	632	289
Transportation and Blending	3,151	2,733
Operating	677	660
Realized (Gain) Loss on Risk Management	(8)	13
Operating Margin	2,544	2,236
Unrealized (Gain) Loss on Risk Management	(7)	(13)
Depreciation, Depletion and Amortization	834	774
Exploration Expense	4	3
(Income) Loss from Equity-Accounted Affiliates	—	—
Segment Income (Loss)	1,713	1,472

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  16

Operating Margin Variance

Three Months Ended March 31, 2025

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

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

Operating Results

	Three Months Ended March 31,
	2025	2024
Total Sales Volumes (1)(MBOE/d)	636.8	606.9
Crude Oil Production by Asset (Mbbls/d)
Foster Creek	202.7	196.0
Christina Lake	237.8	236.5
Sunrise	52.1	48.8
Lloydminster Thermal	109.9	114.1
Lloydminster Conventional Heavy Oil	21.8	17.9
Total Crude Oil Production (2) (Mbbls/d)	624.3	613.3
Natural Gas (1) (MMcf/d)	11.4	11.9
Total Production (MBOE/d)	626.2	615.3
Effective Royalty Rate (3) (percent)
Foster Creek	24.4	24.9
Christina Lake	26.8	25.0
Sunrise	6.6	3.8
Lloydminster (4)	11.4	6.8
Total Effective Royalty Rate	21.1	19.3
Netback (5) ($/bbl)
Realized Sales Price	80.99	72.79
Royalties	15.03	12.60
Transportation and Blending	9.85	7.54
Operating	11.77	11.86
Total Netback($/bbl)	44.34	40.79
Per-Unit DD&A (6) ($/BOE)	13.81	13.35

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

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

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

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

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

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  17

Revenues

Gross sales increased in the first quarter of 2025 compared with 2024, due to higher realized pricing and higher sales volumes.

Price

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

Our Realized Sales Price increased 11 percent in the first quarter of 2025 compared with 2024, mainly due to narrower WTI-WCS and condensate-WCS differentials, partially offset by a decrease in the WTI benchmark.

In first quarter of 2025, approximately 37 percent (2024 – 23 percent) of our crude oil sales volumes were sold to destinations outside of Alberta, including sales to our U.S. Refining operations. In the first quarter of 2025, approximately 25 percent (2024 – 20 percent) of our sales volumes were sold to our Canadian and U.S. downstream operations.

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

Production Volumes

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

•Increased production from our optimization programs and new sustaining well pads at Foster Creek.

•Strong base production and new development wells as we progress the execution of our drilling program at our Lloydminster conventional heavy oil assets.

•Successful results from our optimization programs and new sustaining well pads at our Sunrise asset.

The increases were partially offset by lower production at our Lloydminster thermal assets due to wells being offline for the execution of our redevelopment program in the first quarter of 2025, compared with 2024.

Production at our Christina Lake asset in the first quarter of 2025 was relatively consistent compared with 2024.

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 first quarter of 2025, Oil Sands royalties increased compared with 2024, primarily due to higher realized pricing and sales volumes. The Oil Sands effective royalty rate increased primarily due to higher realized prices, partially offset by lower Alberta sliding scale oil sands royalty rates.

Expenses

Transportation and Blending

In the first quarter of 2025, blending expenses increased $270 million compared with 2024, due primarily to higher sales volumes.

In the first quarter of 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, due to higher sales volumes on TMX and increased pipeline transportation rates on shipments to U.S. destinations.

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Per-Unit Transportation Expenses (1)

	Three Months Ended March 31,
($/bbl)	2025	2024
Foster Creek	15.85	10.25
Christina Lake	6.12	5.40
Sunrise	18.07	18.51
Lloydminster (2)	3.42	3.89
Total Oil Sands	9.85	7.54

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

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

At Foster Creek, per-unit transportation expenses increased primarily due to the use of TMX, partially offset by lower rail transportation costs. In 2025, 32 percent and 35 percent of our total sales volumes at Foster Creek were sold at West Coast and U.S. destinations, respectively (2024 – nil and 34 percent, respectively).

At Christina Lake, per-unit transportation expenses increased primarily due to increased pipeline transportation rates and higher rail transportation costs. In 2025, we shipped 15 percent (2024 – 11 percent) of our total sales volumes at Christina Lake to U.S. destinations.

At Sunrise, per-unit transportation expenses decreased primarily due to lower sales volumes to U.S. destinations, partially offset by the higher use of TMX. In 2025, 73 percent and 27 percent of our total sales volumes at Sunrise were sold at West Coast and U.S. destinations, respectively (2024 – nil and 94 percent, respectively).

At Lloydminster, per-unit transportation expenses decreased primarily due to lower sales volumes to U.S. destinations. In 2025, we shipped two percent (2024 – four percent) of our total sales volumes at Lloydminster to U.S. destinations.

Operating

Primary drivers of our operating expenses in the first quarter of 2025 were fuel, workforce, and repairs and maintenance. Total operating expenses increased compared with the same period in 2024, due to increased workover activity and GHG compliance costs. The increases were partially offset by lower fuel costs as a result of lower AECO benchmark prices and lower electricity costs. 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.

Per-Unit Operating Expenses (1)

	Three Months Ended March 31,
($/bbl)	2025	Percent Change	2024
Foster Creek
Fuel	2.41	(25)	3.22
Non-Fuel	7.41	(2)	7.59
Total	9.82	(9)	10.81
Christina Lake
Fuel	2.50	(9)	2.76
Non-Fuel	6.26	9	5.75
Total	8.76	3	8.51
Sunrise
Fuel	4.33	—	4.32
Non-Fuel	13.22	4	12.70
Total	17.55	3	17.02
Lloydminster (2)
Fuel	3.68	(11)	4.15
Non-Fuel	14.78	6	13.90
Total	18.46	2	18.05

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

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  19

Per-Unit Operating Expenses — Continued (1)

	Three Months Ended March 31,
($/bbl)	2025	Percent Change	2024
Total Oil Sands
Fuel	2.85	(14)	3.31
Non-Fuel	8.92	4	8.55
Total	11.77	(1)	11.86

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

Per-unit fuel expenses decreased overall due to lower AECO natural gas prices, as discussed above. Sunrise per-unit fuel expenses were relatively consistent in the first quarter of 2025 compared with 2024, as lower natural gas prices were fully offset by increased consumption volumes from well pads coming online.

Overall, non-fuel expenses increased in the first quarter of 2025 compared with 2024, due to:

•Higher GHG compliance costs and lower sales volumes, partially offset by lower waste fluid handling and trucking costs at our Christina Lake assets.

•Higher GHG compliance costs, workover activity and chemical costs, partially offset by increased sales volumes and lower electricity costs at our Sunrise assets.

•Higher workover activity and lower sales volumes at our Lloydminster assets.

The increases were partially offset by a decrease in non-fuel expenses at our Foster Creek assets due to increased sales volumes, lower chemical and GHG compliance costs, partially offset by increased repairs and maintenance.

Conventional

In the first quarter of 2025, we:

•Delivered safe and reliable operations.

•Produced 123.9 thousand BOE per day (2024 – 120.7 thousand BOE per day).

•Generated Operating Margin of $173 million, an increase of $24 million from 2024.

•Earned a Netback of $15.77 per BOE (2024 – $13.04 per BOE).

•Invested capital of $122 million primarily related to drilling, completion, tie-in and infrastructure projects. Completions and tie-in activities increased in the first quarter, due in part to well development activities that were deferred in the second half of 2024 due to lower natural gas benchmark prices.

Financial Results

	Three Months Ended March 31,
($ millions)	2025	2024
Gross Sales
External Sales	443	377
Intersegment Sales	501	502
	944	879
Royalties	(20)	(24)
Revenues	924	855
Expenses
Purchased Product	535	482
Transportation and Blending	90	78
Operating	127	153
Realized (Gain) Loss on Risk Management	(1)	(7)
Operating Margin	173	149
Unrealized (Gain) Loss on Risk Management	—	6
Depreciation, Depletion and Amortization	120	110
Exploration Expense	—	—
(Income) Loss From Equity-Accounted Affiliates	—	1
Segment Income (Loss)	53	32

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  20

Operating Margin Variance

Three Months Ended March 31, 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 March 31,
	2025	2024
Total Sales Volumes (1)(MBOE/d)	123.9	120.7
Realized Sales Price (1) (2) ($/BOE)
Light Crude Oil ($/bbl)	89.17	87.97
NGLs($/bbl)	64.91	57.40
Conventional Natural Gas($/Mcf)	4.11	4.00
Production by Product (1)
Light Crude Oil (Mbbls/d)	5.2	5.3
NGLs(Mbbls/d)	20.5	22.0
Conventional Natural Gas (MMcf/d)	589.3	560.5
Total Production(MBOE/d)	123.9	120.7
Conventional Natural Gas Production (percentage of total)	79	77
Crude Oil and NGLs Production (percentage of total)	21	23
Effective Royalty Rate (1) (3)(percent)	9.0	9.9
Netback (1) (2) ($/BOE)
Realized Sales Price	34.01	32.92
Royalties	1.83	2.16
Transportation and Blending	5.49	4.67
Operating	10.92	13.05
Total Netback($/BOE)	15.77	13.04
Per-Unit DD&A (4) ($/BOE)	10.43	9.90

(1)For the three months ended March 31, 2025, reported production volumes, sales volumes, associated per-unit values and 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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  21

Revenues

Gross sales increased in the first quarter of 2025 compared with 2024, due to higher Realized Sales Price and increased sales volumes.

Price

Our total Realized Sales Price increased in the first quarter of 2025, compared with 2024. For the three months ended March 31, 2025, 27 percent (2024 – 28 percent) of our sales volumes of natural gas were sold to U.S. destinations where NYMEX natural gas benchmark prices are higher. These increases were partially offset by a reduction in the AECO natural gas benchmark price. For the three months ended March 31, 2025, the AECO natural gas benchmark price was $2.17 per Mcf (2024 – $2.50 per Mcf) and the NYMEX natural gas benchmark price was US$3.65 per Mcf (2024 – US$2.24 per Mcf).

Production Volumes

Production volumes increased in the first quarter of 2025, compared with 2024, primarily due to strong base performance and bringing on wells in 2025 that had been deferred in 2024 due to lower AECO pricing.

Royalties

Royalties decreased in the first quarter of 2025, compared with 2024, primarily due to lower natural gas benchmark prices used to calculate our royalties.

Expenses

Transportation

Our transportation expenses reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. In the first quarter of 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 quarter of 2025 were repairs and maintenance, workforce and property tax costs. Total operating expenses and per-unit operating expenses decreased compared with 2024, mainly due to lower processing and gathering costs. The decrease in per-unit operating expenses was also due to higher sales volumes.

Offshore

In the first quarter of 2025, we:

•Delivered safe and reliable operations.

•Produced 68.8 thousand BOE per day of light crude oil, NGLs and natural gas (2024 – 64.9 thousand BOE per day).

•Generated Operating Margin of $331 million, an increase of $85 million from 2024, primarily due to increased sales volumes, partially offset by lower realized pricing in our Atlantic operations.

•Earned a Netback of $58.03 per BOE (2024 – $52.80 per BOE).

•Invested capital of $241 million, mainly related to the progression of the West White Rose project.

The West White Rose project continues to progress toward installation and commissioning of the offshore platform. Preparations are underway to tow the concrete gravity structure to the field in the second quarter, with the transport of the topsides expected to occur in the third quarter. As at March 31, 2025, the project was approximately 90 percent completed 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 $1.8 billion.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  22

Financial Results

	Three Months Ended March 31,
	2025			2024
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	146	305	451	42	315	357
Intersegment Sales	—	—	—	—	—	—
	146	305	451	42	315	357
Royalties	(2)	(23)	(25)	(2)	(24)	(26)
Revenues	144	282	426	40	291	331
Expenses
Purchased Product	—	—	—	—	—	—
Transportation and Blending	6	—	6	—	—	—
Operating	64	25	89	57	28	85
Operating Margin (1)	74	257	331	(17)	263	246
Depreciation, Depletion and Amortization			130			131
Exploration Expense			1			4
(Income) Loss from Equity-Accounted Affiliates			(8)			(10)
Segment Income (Loss)			208			121

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

Operating Margin Variance

Three Months Ended March 31, 2025

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  23

Operating Results

	Three Months Ended March 31,
	2025	2024
Sales Volumes
Atlantic (Mbbls/d)	15.8	3.9
Asia Pacific (MBOE/d)
China	42.0	43.7
Indonesia (1)	15.2	14.0
Total Asia Pacific	57.2	57.7
Total Sales Volumes (MBOE/d)	73.0	61.6
Production by Product
Atlantic – Light Crude Oil (Mbbls/d)	11.6	7.2
Asia Pacific (1)
NGLs(Mbbls/d)	9.3	10.4
Conventional Natural Gas (MMcf/d)	287.2	283.4
Total Asia Pacific (MBOE/d)	57.2	57.7
Total Production(MBOE/d)	68.8	64.9
Effective Royalty Rate (2)(percent)
Atlantic	1.0	4.5
Asia Pacific (1)	12.6	7.6
Per-Unit DD&A (3) ($/BOE)	19.07	29.17

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

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

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

Netbacks (1)

	Three Months Ended March 31, 2025
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)
Realized Sales Price		102.63	81.01		64.65		82.26
Royalties		1.04	6.13		19.44		7.81
Transportation and Blending		4.25	—		—		0.92
Operating Expenses		45.47	6.00		10.67		15.50
Netback		51.87	68.88		34.54		58.03

	Three Months Ended March 31, 2024
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)
Realized Sales Price		114.07	79.21		53.05		75.48
Royalties		5.09	6.00		4.10		5.51
Transportation and Blending		(2.14)	—		—		(0.14)
Operating Expenses		158.70	6.28		11.86		17.31
Netback		(47.58)	66.93		37.09		52.80

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

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

Revenues

Gross sales increased in the first quarter of 2025, compared with 2024, primarily due to increased sales volumes, partially offset by a lower Realized Sales Price at our Atlantic operations.

Price

Our Atlantic Realized Sales Price on light crude oil decreased in the first quarter of 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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  24

Production Volumes

Atlantic production increased in the first quarter of 2025, compared with 2024, primarily due to strong performance at the Terra Nova field and the safe restart of production at the White Rose field. Atlantic production in 2024 was lower as production at the White Rose field was suspended in late December 2023 in preparation for the SeaRose Asset Life Extension (“ALE”) project and production at Terra Nova was ramping up after its 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 was consistent in the first quarter of 2025, compared with 2024.

Royalties

For the three months ended March 31, 2025, the Atlantic effective royalty rate decreased compared with 2024. The decrease was primarily due to a lower effective royalty rate applied to Terra Nova field sales in the first quarter of 2025, compared with a higher effective royalty rate applicable to White Rose field sales in the first quarter of 2024. There were no White Rose field sales in 2025.

Royalty rates in Asia Pacific are governed by production-sharing contracts, in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for Asia Pacific for the first quarter of 2025 increased compared with 2024, primarily due to credits received in 2024.

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 first quarter of 2025 increased to $6 million (2024 – $nil) primarily due to increased sales volumes, compared with minimal sales in the first quarter of 2024.

Operating

Primary drivers of our Atlantic operating expenses in the first quarter of 2025 were repairs and maintenance, costs related to vessels and air services, and workforce. Operating expenses increased compared with 2024, primarily due to a significant increase in sales volumes, partially offset by lower repairs and maintenance costs. Per-unit operating expenses decreased in the first quarter of 2025, compared with 2024, mainly due to the increase in sales volumes as a result of the timing of lifts.

Primary drivers of our China operating expenses in the first quarter of 2025 were repairs and maintenance, workforce costs and insurance. Operating expenses decreased compared with 2024, primarily due to lower insurance costs, partially offset by increased repairs and maintenance costs. Per-unit operating expenses decreased compared with 2024, due to the factors discussed above, partially offset by lower sales volumes.

Primary drivers of our Indonesia operating expenses in the first quarter of 2025 were repairs and maintenance, workforce costs, and costs related to vessel services. Indonesia per-unit operating expenses decreased in the first quarter of 2025, compared with 2024, due to higher sales volumes.

DOWNSTREAM

Canadian Refining

In the first quarter of 2025, we:

•Delivered safe and reliable operations.

•Achieved record throughput of 111.9 thousand barrels per day (2024 – 104.1 thousand barrels per day).

•Incurred per-unit operating expenses excluding turnaround costs of $10.81 per barrel (2024 – $13.36 per barrel).

•Recorded Operating Margin of $68 million as increased production and lower operating expenses were offset by lower refined product prices (2024 – $68 million).

•Invested capital of $22 million, primarily focused on sustaining activities.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  25

Financial and Operating Results

	Three Months Ended March 31,
($ millions)	2025	2024
Revenues	1,282	1,332
Purchased Product	1,076	1,087
Gross Margin (1)	206	245
Expenses
Operating	138	177
Operating Margin	68	68
Depreciation, Depletion and Amortization	47	44
Segment Income (Loss)	21	24

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

	Three Months Ended March 31,
($ millions, except where indicated)	2025	2024
Gross Margin	206	245
Inventory Holding (Gain) Loss (1)	3	(23)
Adjusted Gross Margin (2)	209	222
Adjusted Refining Margin (3)($/bbl)	17.33	20.23

(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. 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 months ended March 31, 2025, were $1.2 billion (2024 – $1.2 billion).

The Upgrader processes blended heavy crude oil and bitumen into high-value synthetic crude oil and low-sulphur diesel. Upgrading Gross Margin is primarily dependent on the differential between the sales price of synthetic crude oil and diesel, and the cost of heavy crude oil and bitumen feedstock.

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

Revenues decreased in the first quarter of 2025, compared with 2024, primarily due to lower diesel benchmark prices, partially offset by an increase in sales volumes.

Adjusted Gross Margin and Adjusted Refining Margin decreased quarter-over-quarter, primarily due to lower benchmark diesel prices, as discussed above, combined with higher heavy crude oil and bitumen feedstock costs as a result of the narrowing of the WTI-WCS differential. The upgrading differential narrowed six percent compared with the first quarter of 2024.

	Three Months Ended March 31,
(Mbbls/d, except where indicated)	2025	2024
Operable Capacity	108.0	108.0
Total Processed Inputs	119.5	108.8
Crude Oil Unit Throughput	111.9	104.1
Crude Unit Utilization(percent)	104	96
Total Production	126.5	116.2
Synthetic Crude Oil	52.4	47.1
Asphalt	16.6	15.6
Diesel	15.5	12.9
Other	37.7	35.2
Ethanol	4.3	5.4

The Upgrader and Lloydminster Refinery source their crude oil feedstock from our Oil Sands segment. In the first quarter of 2025, 14 percent of our Oil Sands segment’s sales volumes were purchased by our Canadian Refining segment (2024 – 13 percent).

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  26

Throughput and total production increased in the first quarter of 2025 compared with 2024, as our assets ran at, or above, capacity for the majority of the quarter. This was due in part to the benefits of the turnaround and projects completed in 2024.

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 March 31,
($ millions, except where indicated)	2025	2024
Operating Expenses – Upgrading and Refining	116	147
Operating Expenses – Excluding Turnaround Costs	116	132
Operating Expenses – Turnaround Costs	—	15
Per-Unit Operating Expenses (1)($/bbl)	10.81	14.83
Per-Unit Operating Expenses – Excluding Turnaround Costs	10.81	13.36
Per-Unit Operating Expenses – Turnaround Costs	—	1.47

(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 first quarter of 2025, operating expenses excluding turnaround costs decreased compared with 2024, primarily due to lower project expenses in 2025. The decrease in operating expenses, combined with increased total processed inputs, resulted in decreased per-unit operating expenses compared with 2024.

U.S. Refining

In the first quarter of 2025, we:

•Delivered safe and reliable operations.

•Achieved a crude unit utilization of 90 percent (2024 – 90 percent) and throughput of 553.5 thousand barrels per day compared with 551.1 thousand barrels per day in the first quarter of 2024.

•Incurred per-unit operating expenses excluding turnaround costs of $12.15 per barrel (2024 – $11.01 per barrel), primarily due to increased energy costs and the weakening of the Canadian dollar, on average, relative to the U.S. dollar.

•Recorded an Operating Margin shortfall of $305 million, a decrease of $797 million from the first quarter of 2024. The decrease was primarily due to lower market crack spreads, a narrower WTI-WCS differential and higher operating costs.

•Invested capital of $77 million, primarily focused on sustaining activities.

Financial and Operating Results

	Three Months Ended March 31,
($ millions)	2025	2024
Revenues (1)	6,423	6,901
Purchased Product (1)	6,006	5,798
Gross Margin (2)	417	1,103
Expenses
Operating	716	610
Realized (Gain) Loss on Risk Management	6	1
Operating Margin	(305)	492
Unrealized (Gain) Loss on Risk Management	(8)	8
Depreciation, Depletion and Amortization	158	111
Segment Income (Loss)	(455)	373

(1)Comparative period reflects 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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  27

	Three Months Ended March 31,
($ millions, except where indicated)	2025	2024
Gross Margin	417	1,103
Inventory Holding (Gain) Loss (1)	23	(194)
Adjusted Gross Margin (2)	440	909
Adjusted Refining Margin (2)($/bbl)	8.41	17.37
Adjusted Market Capture (2)(percent)	62	93

(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.

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 first quarter of 2025, the Chicago 3-2-1 crack spread decreased 22 percent and the Group 3 3-2-1 crack spread decreased six percent, compared with the first quarter of 2024.

The 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.

Revenues decreased in the first quarter of 2025, compared with 2024, due to declines in benchmark gasoline and diesel prices and a slight decrease in sales volumes.

Adjusted Gross Margin and Adjusted Refining Margin decreased quarter-over-quarter, primarily due to the decline in benchmark market crack spreads, as discussed above, partially offset by increased process unit reliability at our operated refineries.

The WTI-WCS differential narrowed by 34 percent to US$12.67 per barrel in the first quarter of 2025, compared with 2024, as the start-up of TMX increased the cost of heavy crude entering our refineries, which negatively impacted our Adjusted Gross Margin and Adjusted Market Capture.

	Three Months Ended March 31,
(Mbbls/d, except where indicated)	2025	2024
Operable Capacity	612.3	612.3
Total Processed Inputs	581.0	575.0
Crude Oil Unit Throughput	553.5	551.1
Heavy Crude Oil	226.3	224.7
Light/Medium Crude Oil	327.2	326.4
Crude Unit Utilization(percent)	90	90
Total Refined Product Production	595.9	585.9
Gasoline	284.7	281.9
Distillates (1)	208.8	200.1
Asphalt	25.7	26.1
Other	76.7	77.8

(1)Includes diesel and jet fuel.

Throughput was relatively consistent and total refined product production increased slightly in the first quarter of 2025, compared with 2024. This was primarily due to higher process unit reliability at our operated refineries, partially offset by turnarounds that began at both of our non-operated refineries in March. These are expected to be completed in the second quarter.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  28

Operating Expenses

	Three Months Ended March 31,
($ millions, except where indicated)	2024	2024
Operating Expenses	716	610
Operating Expenses – Excluding Turnaround Costs	635	576
Operating Expenses – Turnaround Costs	81	34
Per-Unit Operating Expenses (1) ($/bbl)	13.69	11.65
Per-Unit Operating Expenses – Excluding Turnaround Costs	12.15	11.01
Per-Unit Operating Expenses – Turnaround Costs	1.54	0.64

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

Primary drivers of operating expenses were workforce, repairs and maintenance, and turnaround costs. In the first quarter of 2025, operating expenses increased mainly due to turnaround and workforce costs, as we prepared the Toledo Refinery for the East Side turnaround, which began in April. Our non-operated refineries began turnarounds in March.

Operating expenses, operating expenses excluding turnaround costs and related per-unit metrics increased due to higher energy costs and the weakening of the Canadian dollar relative to the U.S. dollar. On average, the Canadian dollar was six percent weaker than the U.S. dollar compared with the first quarter of 2024. The increases were partially offset by lower repairs and maintenance expense. Overall, controllable operating expenses excluding turnaround costs decreased slightly when compared with the first quarter of 2024. Per-unit operating expense increases were partially offset by slightly higher total processed inputs.

CORPORATE AND ELIMINATIONS

Financial Results

	Three Months Ended March 31,
($ millions)	2025	2024
Realized (Gain) Loss on Risk Management	(5)	3
Unrealized (Gain) Loss on Risk Management	38	30
General and Administrative	197	246
Finance Costs, Net	136	135
Foreign Exchange (Gain) Loss, Net	—	99

General and Administrative

Primary drivers of our general and administrative expenses for the three months ended March 31, 2025, were workforce costs and information technology related costs. The decrease in general and administrative expenses was primarily due to lower long-term incentive costs, as our closing common share price decreased from $21.79 on December 31, 2024 to $20.00 on March 31, 2025, compared with an increase from $22.08 on December 31, 2023 to $27.08 on March 31, 2024.

Finance Costs, Net

Net finance costs were consistent in the first quarter of 2025, compared with the same quarter in 2024. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.

The annualized weighted average interest rate on outstanding debt for the three months ended March 31, 2025, was 4.54 percent (2024 – 4.47 percent).

Foreign Exchange (Gain) Loss, Net

	Three Months Ended March 31,
($ millions)	2025	2024
Unrealized Foreign Exchange (Gain) Loss	19	124
Realized Foreign Exchange (Gain) Loss	(19)	(25)
	—	99

For the three months ended March 31, 2025, unrealized and realized foreign exchange losses and gains were primarily related to working capital.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  29

Income Taxes

	Three Months Ended March 31,
($ millions)	2025	2024
Current Tax
Canada	279	346
United States	—	11
Asia Pacific	45	44
Other International	13	9
Total Current Tax Expense (Recovery)	337	410
Deferred Tax Expense (Recovery)	(66)	(32)
	271	378

For the three months ended March 31, 2025, we recorded 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 three months of 2025 was 24.0 percent, consistent with the same period in the prior year (2024 – 24.3 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.

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. In the first quarter of 2025, we received a rating upgrade from Moody’s to Baa1 with a Stable outlook. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.

	Three Months Ended March 31,
($ millions)	2025	2024
Cash From (Used In)
Operating Activities	1,315	1,925
Investing Activities	(1,348)	(1,135)
Net Cash Provided (Used) Before Financing Activities	(33)	790
Financing Activities	(294)	(677)
Effect of Foreign Exchange on Cash and Cash Equivalents	2	60
Increase (Decrease) in Cash and Cash Equivalents	(325)	173
	March 31,	December 31,
As at ($ millions)	2025	2024
Cash and Cash Equivalents	2,768	3,093
Total Debt	7,847	7,707

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  30

Cash From (Used in) Operating Activities

In the first quarter of 2025, cash from operating activities decreased compared with the same period in 2024, primarily due to changes in non-cash working capital, combined with lower Operating Margin. The net change in non-cash working capital resulted in a use of cash of $861 million in the quarter, primarily due to decreased accounts payable and income taxes payable. In the first quarter of 2024, changes in non-cash working capital resulted in a use of cash of $269 million.

Cash From (Used in) Investing Activities

Cash used in investing activities increased in the first quarter of 2025 compared with 2024, primarily due to an increase in capital investment in the quarter.

Cash From (Used in) Financing Activities

Cash used in financing activities decreased in the first quarter of 2025 compared with 2024. The decrease was primarily due to the issuance of short-term borrowings, compared with a repayment in the first quarter of 2024, partially offset by the redemption of $200 million of preferred shares.

Working Capital

Working capital as at March 31, 2025, was $3.2 billion (December 31, 2024 – $3.1 billion). The increase was primarily driven by lower income taxes payable and accounts payable, partially offset by lower cash and inventories.

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

Returns to Shareholders Target

Maintaining a strong balance sheet, with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle, is a key element of Cenovus’s capital allocation framework. Our Net Debt target is $4.0 billion and represents a Net Debt to Adjusted Funds Flow ratio target of approximately 1.0 times at the bottom of the commodity pricing cycle, which we believe is 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 March 31,
($ millions)	2025	2024
Excess Free Funds Flow (1)	373	832
Target Return (2)	373	416
Shareholder Returns by way of:
Purchase of Common Shares Under NCIB	62	165
Preferred Share Redemption	200	—
Total	262	165

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

(2)The target return for the three months ended March 31, 2025, was 100 percent of Excess Free Funds Flow. The target return for the three months ended March 31, 2024, was 50 percent of Excess Free Funds Flow.

Short-Term Borrowings

There were no direct borrowings on our uncommitted demand facilities as at March 31, 2025, or December 31, 2024. As at March 31, 2025, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$225 million (C$323 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 March 31, 2025, was $7.5 billion (December 31, 2024 – $7.5 billion). We hold U.S. dollar denominated unsecured notes of US$3.8 billion (C$5.5 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 March 31, 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.

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Available Sources of Liquidity

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

($ millions)	Maturity	Amount Available
Cash and Cash Equivalents	n/a	2,768
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	1,064
WRB (3)	n/a	—

(1)No amounts were drawn on the committed credit facility as at March 31, 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 March 31, 2025, there were outstanding letters of credit aggregating to $368 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 March 31, 2025, US$225 million (C$323 million) of this capacity was drawn (December 31, 2024 – US$120 million (C$173 million)).

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	March 31, 2025	December 31, 2024
Net Debt to Adjusted EBITDA Ratio (times)	0.5	0.5
Net Debt to Adjusted Funds Flow Ratio (times)	0.6	0.6
Net Debt to Capitalization Ratio (percent)	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 March 31, 2025, were consistent with December 31, 2024, as a result of higher Net Debt offset by higher Operating Margin. 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 March 31, 2025, increased compared with December 31, 2024, primarily due to higher Net Debt.

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Share Capital and Stock-Based Compensation Plans

Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Our cumulative redeemable preferred shares series 1, 2 and 7 are listed on the TSX. On March 31, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company’s series 5 preferred shares at a price of $25.00 per share, for a total of $200 million.

As at March 31, 2025, there were approximately 1,822.7 million common shares outstanding (December 31, 2024 – 1,825.0 million common shares) and 18.0 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 three months ended March 31, 2025, the Trust purchased 2.8 million common shares for a total of $58 million and distributed 3.8 million common shares for a total of $81 million under the employee benefit plan. As at March 31, 2025, there were 1.0 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.

As at March 31, 2025, there were approximately 3.4 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 May 5, 2025	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	1,813,779	n/a
Cenovus Warrants	3,411	n/a
Series 1 First Preferred Shares	10,740	n/a
Series 2 First Preferred Shares	1,260	n/a
Series 7 First Preferred Shares	6,000	n/a
Stock Options	12,107	6,033
Other Stock-Based Compensation Plans	20,095	1,988

Common Share Dividends

In the three months ended March 31, 2025, we paid base dividends of $327 million or $0.180 per common share (2024 – $262 million or $0.140 per common share).

On May 7, 2025, the Board declared a second quarter base dividend of $0.200 per common share, an increase of 11 percent from the first quarter dividend declared in February 2025. The dividend is payable on June 30, 2025, to common shareholders of record as at June 13, 2025. The increase is aligned with our long-term value proposition and our plans to sustainably grow our base dividend.

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

Cumulative Redeemable Preferred Share Dividends

In the three months ended March 31, 2025, dividends of $6 million were paid on the series 1, 2, 5 and 7 preferred shares. For the three months ended March 31, 2024, dividends of $9 million were paid on the series 1, 2, 3, 5 and 7 preferred shares.

On May 7, 2025, the Board declared a second quarter dividend on the series 1, 2 and 7 preferred shares for a total of $4 million, payable on June 30, 2025, to preferred shareholders of record as at June 13, 2025.

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

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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 March 31,
	2025	2024
Common Shares Purchased and Cancelled Under NCIB (millions of common shares)	3.0	7.4
Weighted Average Price per Common Share ($)	20.68	22.30
Purchase of Common Shares Under NCIB ($ millions)	62	165

From April 1, 2025, to May 5, 2025, the Company purchased an additional 10.9 million common shares for $178 million. As at May 5, 2025, the Company can further purchase up to 112.5 million common shares under the NCIB.

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 $27.5 billion as at March 31, 2025 (December 31, 2024 – $27.3 billion), of which $24.3 billion are for various transportation and storage commitments. Transportation commitments include $833 million that are subject to regulatory approval, or were approved, but are not yet in service. Terms are up to 20 years on commencement and should help align with the Company’s future transportation requirements.

As at March 31, 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 March 31, 2025, outstanding letters of credit issued as security for performance under certain contracts totaled $368 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:

For the three months ended March 31,	2025	2024
Revenues from Construction and Management Services	29	31
Transportation Expenses	68	69

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.

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CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

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

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

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

CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at March 31, 2025. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at March 31, 2025.

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

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 “aim”, “anticipate”, “believe”, “continue”, “could”, “estimate”, “expect”, “focus”, “may”, “objective”, “opportunities”, “plan”, “position”, “priority”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our five strategic objectives; shareholder value and returns; safety performance; sustainability; our commitment to the Pathways Alliance foundational project; maximizing value; disciplined capital allocation; Free Funds Flow; cash flow volatility and stability; price alignment and volatility management strategies; growing our base dividend; focus on cost and sustainability improvements; liquidity; growth of our base business; capital investment; our 2025 corporate guidance; realizing the full value of our integrated 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; progression of our drilling program and production increases; growing our competitive advantages while operating safely and reliably monitoring market fundamentals and optimizing run rates at our refineries; safe and reliable operations; being best-in-class operators; maintaining a strong balance sheet; costs; margins; long-term value for Cenovus; downstream reliability and profitability; timing of completion of the West White Rose project; progressing growth projects,

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including the Narrows Lake tie-back to Christina Lake, the Foster Creek optimization, Lloydminster drilling program and Sunrise growth projects; our ESG focus areas; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; volatility of refined product prices; impact of U.S. tariffs on market benchmarks and Cenovus; Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; capitalizing on opportunities throughout the commodity price cycle; Net Debt to Adjusted EBITDA ratio; maintaining sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar, the factors that affect such outlook, and the influences and effects on Cenovus.

Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast bitumen, crude oil and natural gas, NGLs, condensate and refined products prices, and light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs, projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change), Indigenous relations, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions and the supply and demand for bitumen, crude oil and natural gas, NGLs, condensate and refined products; the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, third party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company’s share price and market capitalization over the long-term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the Company’s ability to use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange rate and interest rates; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue and fund future investments and development plans and dividends, including any increase thereto; our downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; 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 climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2025 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.

2025 guidance dated December 11, 2024, and available on cenovus.com, assumes: Brent prices of US$74.00 per barrel, WTI prices of US$70.00 per barrel; WCS of US$56.00 per barrel; Differential WTI-WCS of US$14.00 per barrel; AECO natural gas prices of $2.05 per Mcf; Chicago 3-2-1 crack spread of US$18.50 per barrel; and an exchange rate of $0.72 US$/C$.

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 ambitions and the commercial viability and scalability of ESG strategies and related technology and products; the development and execution of implementing strategies to meet ESG targets and ambitions; 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

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downstream operations to help mitigate the impact of volatility in light-heavy crude oil differentials and contribute to its net earnings; foreign exchange risk, including related to agreements denominated in foreign currencies; the Company’s continued liquidity being sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential remaining largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of the Company’s outlook for commodity prices, the impact of tariffs and responses thereto, currency and interest rates; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; the ability to complete and optimize drilling, completion, tie in and infrastructure projects; the ability of the Company to ramp up activities at its refineries on its anticipated timelines; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; tax audits and reassessments; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and refining processes; the occurrence of unexpected events resulting in operational interruptions, including at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics and pandemics; and catastrophic events, including, but not limited to, war, adverse sea conditions, extreme weather events, natural disasters, acts of activism, vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying refining or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s business, including potential cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and the Company’s ability to attract and retain, critical and diverse talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.

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

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

ABBREVIATIONS AND DEFINITIONS

Abbreviations

The following abbreviations and definitions are used in this document:

Crude Oil and NGLs		Natural Gas		Other
bbl	barrel	Mcf	thousand cubic feet	BOE	barrel of oil equivalent
Mbbls/d	thousand barrels per day	MMcf	million cubic feet	MBOE/d	thousand barrels of oil    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 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 March 31,
	2025	2024	2025	2024	2025	2024
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales
External Sales (2)	6,798	5,747	7,407	8,063	14,205	13,810
Intersegment Sales	2,454	2,117	298	170	2,752	2,287
	9,252	7,864	7,705	8,233	16,957	16,097
Royalties	(906)	(747)	—	—	(906)	(747)
Revenues (2)	8,346	7,117	7,705	8,233	16,051	15,350
Expenses
Purchased Product (2)	1,167	771	7,082	6,885	8,249	7,656
Transportation and Blending	3,247	2,811	—	—	3,247	2,811
Operating	893	898	854	787	1,747	1,685
Realized (Gain) Loss on Risk Management	(9)	6	6	1	(3)	7
Operating Margin	3,048	2,631	(237)	560	2,811	3,191

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

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  39

Operating Margin by Asset

	Three Months Ended March 31, 2025
($ millions)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	146	305	451
Royalties	(2)	(23)	(25)
Revenues	144	282	426
Expenses
Transportation and Blending	6	—	6
Operating	64	25	89
Operating Margin	74	257	331

	Three Months Ended March 31, 2024
($ millions)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	42	315	357
Royalties	(2)	(24)	(26)
Revenues	40	291	331
Expenses
Transportation and Blending	—	—	—
Operating	57	28	85
Operating Margin	(17)	263	246

(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.

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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  40

	Three Months Ended March 31,
($ millions)	2025	2024
Cash From (Used in) Operating Activities	1,315	1,925
(Add) Deduct:
Settlement of Decommissioning Liabilities	(36)	(48)
Net Change in Non-Cash Working Capital	(861)	(269)
Adjusted Funds Flow	2,212	2,242
Capital Investment	1,229	1,036
Free Funds Flow	983	1,206
Add (Deduct):
Base Dividends Paid on Common Shares	(327)	(262)
Dividends Paid on Preferred Shares	(6)	(9)
Purchase of Common Shares Under Employee    Benefit Plan	(58)	—
Settlement of Decommissioning Liabilities	(36)	(48)
Principal Repayment of Leases	(83)	(70)
Acquisitions, Net of Cash Acquired	(100)	(10)
Proceeds From Divestitures	—	25
Excess Free Funds Flow	373	832

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. We have added Adjusted Gross Margin, and replaced our definitions of Refining Margin and Market Capture to exclude the impact of inventory holding gains or losses. We believe these changes provide more comparability and accuracy when measuring the performance of our downstream operations.

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  41

Canadian Refining

	Three Months Ended March 31, 2025
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,221	61	1,282
Purchased Product	1,037	39	1,076
Gross Margin	184	22	206
Add (Deduct):
Inventory Holding (Gain) Loss	3	—	3
Adjusted Gross Margin	187	22	209
Total Processed Inputs(Mbbls/d)	119.5
Adjusted Refining Margin ($/bbl)	17.33

(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 March 31, 2024
($ millions, except where indicated)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,249	83	1,332
Purchased Product	1,024	63	1,087
Gross Margin	225	20	245
Add (Deduct):
Inventory Holding (Gain) Loss	(24)	1	(23)
Adjusted Gross Margin	201	21	222
Total Processed Inputs (Mbbls/d)	108.8
Adjusted Refining Margin ($/bbl)	20.23

(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.

	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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  42

	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.

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

	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.

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  43

U.S. Refining

	Three Months Ended March 31,
($ millions, except where indicated)	2025	2024
Revenues (1)	6,423	6,901
Purchased Product (1)	6,006	5,798
Gross Margin	417	1,103
Add (Deduct):
Inventory Holding (Gain) Loss	23	(194)
Adjusted Gross Margin	440	909
Total Processed Inputs (Mbbls/d)	581.0	575.0
Adjusted Refining Margin ($/bbl)	8.41	17.37
Operable Capacity(Mbbls/d)	612.3	612.3
Operable Capacity by Regional Benchmark(percent)
Chicago 3-2-1 Crack Spread Weighting	81	81
Group 3 3-2-1 Crack Spread Weighting	19	19
Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	13.68	17.45
Group 3 3-2-1 Crack Spread (US$/bbl)	16.48	17.50
RINs (US$/bbl)	4.76	3.68
US$ per C$1 – Average	0.697	0.741
Weighted Average Crack Spread, Net of RINs($/bbl)	13.58	18.59
Adjusted Market Capture(percent)	62	93

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  44

	Three Months Ended			Twelve Months Ended
($ millions, except where indicated)	December 31, 2024	September 30, 2024	June 30, 2024	December 31, 2024
Revenues (1)	6,574	7,218	7,615	28,308
Purchased Product (1)	6,296	6,854	6,821	25,769
Gross Margin	278	364	794	2,539
Add (Deduct):
Inventory Holding (Gain) Loss	45	209	(83)	(23)
Adjusted Gross Margin	323	573	711	2,516
Total Processed Inputs (Mbbls/d)	588.4	568.0	594.0	581.4
Adjusted Refining Margin ($/bbl)	5.98	10.97	13.15	11.83
Operable Capacity(Mbbls/d)	612.3	612.3	612.3	612.3
Operable Capacity by Regional Benchmark(percent)
Chicago 3-2-1 Crack Spread Weighting	81	81	81	81
Group 3 3-2-1 Crack Spread Weighting	19	19	19	19
Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	12.12	18.62	18.76	16.74
Group 3 3-2-1 Crack Spread (US$/bbl)	12.66	18.95	18.13	16.81
RINs (US$/bbl)	4.02	3.89	3.39	3.74
US$ per C$1 – Average	0.715	0.733	0.731	0.730
Weighted Average Crack Spread, Net of RINs($/bbl)	11.47	20.18	20.86	17.82
Adjusted Market Capture(percent)	52	54	63	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. In the three months ended 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. – Q1 2025 Management's Discussion and Analysis  45

Oil Sands

	Basis of Netback Calculation
Three Months Ended March 31, 2025 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,717	1,619	389	910	4,635
Royalties	(342)	(398)	(20)	(99)	(859)
Revenues	1,375	1,221	369	811	3,776
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	312	132	80	39	563
Operating	193	189	78	213	673
Netback	870	900	211	559	2,540
Realized (Gain) Loss on Risk Management					(8)
Operating Margin					2,548

	Basis of Netback Calculation	Adjustments
Three Months Ended March 31, 2025 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	4,635		2,575	553	94	7,857
Royalties	(859)		—	—	(2)	(861)
Revenues	3,776		2,575	553	92	6,996
Expenses
Purchased Product	—		—	553	79	632
Transportation and Blending	563		2,575	—	13	3,151
Operating	673		—	—	4	677
Netback	2,540		—	—	(4)	2,536
Realized (Gain) Loss on Risk Management	(8)		—	—	—	(8)
Operating Margin	2,548		—	—	(4)	2,544

(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 March 31, 2024 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster (1)	Total Oil Sands (2)
Gross Sales	1,356	1,474	340	850	4,020
Royalties	(293)	(339)	(11)	(54)	(697)
Revenues	1,063	1,135	329	796	3,323
Expenses
Purchased Product	—	—	—	—	—
Transportation and Blending	181	119	71	45	416
Operating	191	188	65	211	655
Netback	691	828	193	540	2,252
Realized (Gain) Loss on Risk Management					13
Operating Margin					2,239

	Basis of Netback Calculation	Adjustments
Three Months Ended March 31, 2024 ($ millions)	Total Oil Sands (2)		Condensate	Third-party Sourced	Other (3)	Total Oil Sands (4)
Gross Sales	4,020		2,305	213	90	6,628
Royalties	(697)		—	—	—	(697)
Revenues	3,323		2,305	213	90	5,931
Expenses
Purchased Product	—		—	213	76	289
Transportation and Blending	416		2,305	—	12	2,733
Operating	655		—	—	5	660
Netback	2,252		—	—	(3)	2,249
Realized (Gain) Loss on Risk Management	13		—	—	—	13
Operating Margin	2,239		—	—	(3)	2,236

(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. – Q1 2025 Management's Discussion and Analysis  46

Conventional

	Basis of Netback Calculation	Adjustments
Three Months Ended March 31, 2025 ($ millions)	Conventional (1)	Third-party Sourced	Other (1)(2)	Conventional (3)
Gross Sales	379	534	31	944
Royalties	(20)	—	—	(20)
Revenues	359	534	31	924
Expenses
Purchased Product	—	534	1	535
Transportation and Blending	61	—	29	90
Operating	122	—	5	127
Netback	176	—	(4)	172
Realized (Gain) Loss on Risk Management	(1)	—	—	(1)
Operating Margin	177	—	(4)	173

	Basis of Netback Calculation	Adjustments
Three Months Ended March 31, 2024 ($ millions)	Conventional	Third-party Sourced	Other (2)	Conventional (3)
Gross Sales	362	482	35	879
Royalties	(24)	—	—	(24)
Revenues	338	482	35	855
Expenses
Purchased Product	—	482	—	482
Transportation and Blending	51	—	27	78
Operating	143	—	10	153
Netback	144	—	(2)	142
Realized (Gain) Loss on Risk Management	(7)	—	—	(7)
Operating Margin	151	—	(2)	149

(1)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.

Offshore

	Basis of Netback Calculation
Three Months Ended March 31, 2025 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Total Offshore (2)
Gross Sales	146	305	89	394	540	(89)	451
Royalties	(2)	(23)	(27)	(50)	(52)	27	(25)
Revenues	144	282	62	344	488	(62)	426
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	6	—	—	—	6	—	6
Operating	64	23	15	38	102	(13)	89
Netback	74	259	47	306	380	(49)	331
Realized (Gain) Loss on Risk Management					—	—	—
Operating Margin					380	(49)	331

	Basis of Netback Calculation
Three Months Ended March 31, 2024 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Total Offshore (2)
Gross Sales	42	315	68	383	425	(68)	357
Royalties	(2)	(24)	(5)	(29)	(31)	5	(26)
Revenues	40	291	63	354	394	(63)	331
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	—	—	—	—	—	—	—
Operating	57	25	15	40	97	(12)	85
Netback	(17)	266	48	314	297	(51)	246
Realized (Gain) Loss on Risk Management					—	—	—
Operating Margin					297	(51)	246

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

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  47

Upstream Sales Volumes (1)

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

	Three Months Ended March 31,
(MBOE/d)	2025	2024
Oil Sands (2)
Foster Creek	218.6	194.0
Christina Lake	239.6	242.2
Sunrise	49.5	42.3
Lloydminster	128.1	128.4
Total Oil Sands	635.8	606.9
Conventional (3)	123.9	120.7
Offshore
Atlantic	15.8	3.9
Asia Pacific
China	42.0	43.7
Indonesia (4)	15.2	14.0
Total Asia Pacific	57.2	57.7
Total Offshore	73.0	61.6

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

(2)Includes bitumen and heavy crude oil sales.

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

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

Other Specified Financial Measures

Per-Unit Operating Expenses

Per-unit operating expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. Our upstream per-unit operating expenses are defined as total operating expenses divided by sales volumes and are part of our Netback calculation, which can be found above.

We define Canadian Refining per-unit operating expenses as total operating expenses from the Upgrader, the Lloydminster Refinery and the commercial fuels business, divided by total processed inputs. We define U.S. Refining per-unit operating expenses as operating expenses divided by total processed inputs.

Per-Unit Transportation Expenses

Per-unit transportation expenses are specified financial measures used to measure transportation expenses on a per-unit basis in our upstream segments. We define per-unit transportation expenses as the total transportation expenses divided by sales volumes. Our upstream per-unit transportation expenses are part of the transportation and blending line in our Netback calculation, which can be found above.

Per-Unit Depreciation, Depletion and Amortization

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

Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis  48

PRIOR PERIOD REVISIONS

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

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

	U.S. Refining Segment			Consolidated
For the three months ended March 31, 2024	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Revenues	7,235	(334)	6,901	13,397	(334)	13,063
Purchased Product	6,132	(334)	5,798	6,133	(334)	5,799
Transportation and Blending	—	—	—	2,575	—	2,575
Purchased Product, Transportation    and Blending	6,132	(334)	5,798	8,708	(334)	8,374
	1,103	—	1,103	4,689	—	4,689

	U.S. Refining Segment			Consolidated
For the three months ended 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 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. – Q1 2025 Management's Discussion and Analysis  49