EX-99.2 3 q22025managementsdiscussio.htm EX-99.2
Exhibit 99.2
Cenovus Energy Inc.
Management’s Discussion and Analysis (unaudited)
For the Periods Ended June 30, 2025
(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the periods ended June 30, 2025

TABLE OF CONTENTS |  |  |  |

OVERVIEW OF CENOVUS |  | 3
QUARTERLY RESULTS OVERVIEW |  | 4
OPERATING AND FINANCIAL RESULTS |  | 6
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS |  | 11
OUTLOOK |  | 14
REPORTABLE SEGMENTS |  | 17
UPSTREAM |  | 17
OIL SANDS |  | 17
CONVENTIONAL |  | 22
OFFSHORE |  | 24
DOWNSTREAM |  | 29
CANADIAN REFINING |  | 29
U.S. REFINING |  | 30
CORPORATE AND ELIMINATIONS |  | 33
LIQUIDITY AND CAPITAL RESOURCES |  | 34
RISK MANAGEMENT AND RISK FACTORS |  | 38
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES |  | 38
CONTROL ENVIRONMENT |  | 39
ADVISORY |  | 39
ABBREVIATIONS AND DEFINITIONS |  | 42
SPECIFIED FINANCIAL MEASURES |  | 43
PRIOR PERIOD REVISIONS |  | 56

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, joint arrangements, and partnership interests held directly or indirectly by, Cenovus Energy Inc.) dated July 30, 2025, should be read in conjunction with our June 30, 2025 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2024 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2024 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as at July 30, 2025, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (“the Board”) reviewed and recommended the MD&A for approval by the Board, which occurred on July 30, 2025. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, do not constitute part of this MD&A.
Basis of Presentation
This MD&A and the interim Consolidated Financial Statements were prepared in Canadian dollars (which includes references to “dollar” or “$”), except where another currency is indicated, and in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”). Production volumes are presented on a before royalties basis. Refer to the Abbreviations and Definitions section for commonly used oil and gas terms.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 2

OVERVIEW OF CENOVUS

We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are one of the largest Canadian-based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the largest Canadian-based refiners and upgraders, with downstream operations in Canada and the United States (“U.S.”).
Our upstream operations include oil sands projects in northern Alberta; thermal and conventional crude oil, natural gas and natural gas liquids (“NGLs”) projects across Western Canada; crude oil production offshore Newfoundland and Labrador; and natural gas and NGLs production offshore China and Indonesia. Our downstream operations include upgrading and refining operations in Canada and the U.S., and commercial fuel operations across Canada.
Our operations involve activities across the full value chain to develop, produce, refine, transport and market crude oil, natural gas and refined petroleum products in Canada and internationally. Our physically and economically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil price differentials and contribute to our net earnings by capturing value from crude oil, natural gas and NGLs production through to the sale of finished products such as transportation fuels.
Our Strategy
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five strategic objectives include: delivering top-tier safety performance and sustainability leadership; maximizing value through competitive cost structures and optimizing margins; a focus on financial discipline, including maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle; and absolute and per share free funds flow growth.
On December 12, 2024, we released our 2025 corporate guidance, which focused on disciplined capital allocation in support of increasing shareholder returns over time. We will continue to be focused on controlling costs, improving the profitability of our strategic downstream business and optimizing our advantaged portfolio to deliver value for our shareholders. Our 2025 corporate guidance was updated on July 30, 2025, and is available on our website at cenovus.com. For further details, see the Outlook section of this MD&A.
Our Operations
The Company operates through the following reportable segments:
Upstream Segments
•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.
•Conventional, includes assets rich in NGLs and natural gas in Alberta and British Columbia in the Edson, Clearwater and Rainbow Lake operating areas, in addition to the Northern Corridor, which includes Elmworth and Wapiti. The segment also includes interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.
•Offshore, includes offshore operations, exploration and development activities in the east coast of Canada and the Asia Pacific region, representing China and the equity-accounted investment in Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for, and production of, NGLs and natural gas in offshore Indonesia.
Downstream Segments
•Canadian Refining, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.

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•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment also includes the jointly-owned Wood River and Borger refineries held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.
Corporate and Eliminations
Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.

QUARTERLY RESULTS OVERVIEW

The second quarter of 2025 marks the achievement of a number of milestones on our growth projects and the safe execution of turnarounds at our Oil Sands and U.S. Refining assets. Financial results reflect the volatility in pricing through the second quarter. We continue to increase our total returns to common and preferred shareholders through share buybacks, dividends and the redemption of preferred shares.
•Delivered safe and reliable operations. We delivered safe operations across our business and safely completed turnarounds at Foster Creek, Sunrise and the Toledo Refinery. In late May, we responded to wildfire activity in northern Alberta by temporarily shutting-in production at Christina Lake to ensure the safety of our staff and assets. We resumed production in early June. Safety continues to be our top priority.
•Maintained upstream production. Upstream production was 765.9 thousand barrels of oil equivalent per day, a decrease from 818.9 thousand barrels of oil equivalent per day in the first quarter of 2025. Production decreased due to the shut-in at Christina Lake and turnaround activities, as discussed above. Turnarounds were well executed with production resuming in June. We temporarily shut-in production at our Rush Lake facilities within our Lloydminster thermal assets as we respond to a casing failure at a steam injection well. The well is under control and we are undertaking an investigation of the incident and developing a plan to restart production.
•Progressed key Oil Sands growth projects. We completed commissioning of the Narrows Lake tie-back to Christina Lake and achieved first oil in July. As part of the Sunrise growth program, we brought one new well pad online. The optimization project at Foster Creek is progressing as planned and was approximately 87 percent complete as at June 30, 2025. In July, we brought four new boilers online that will generate steam at the facility, with related well pads on track for 2026. At our Lloydminster conventional heavy oil assets, we progressed our drilling program and production continued to ramp-up from new development wells coming online.
•Achieved Offshore milestones. In the quarter, we achieved major milestones on the West White Rose Project. The concrete gravity structure was towed out and installed on the seabed. The topsides arrived in Newfoundland and, in July, were set in place atop the concrete gravity structure. Hookup and commissioning work has commenced. The West White Rose project was approximately 92 percent complete as at June 30, 2025.
•Strong crude oil unit throughput in our Canadian Refining segment. Average crude oil unit throughput (“throughput”) was 112.4 thousand barrels per day, compared with 111.9 thousand barrels per day in the first quarter of 2025. We continue to run at, or above, capacity at the Lloydminster Upgrader (“Upgrader”) and the Lloydminster Refinery due to continuous improvement initiatives resulting in high reliability.
•U.S. Refining operations performed as expected. We safely completed the turnaround at the Toledo Refinery ahead of schedule. Turnarounds were also completed at both of our non-operated refineries early in the quarter. Despite turnaround activities, throughput from the U.S. Refining segment was 553.4 thousand barrels per day, consistent with the prior quarter, due to improved process unit reliability at our other operated assets and ongoing operational improvements to our business.
•Reported solid financial results. Adjusted Funds Flow was $1.5 billion down from $2.2 billion in the first quarter of 2025, mainly due to lower realized pricing and lower sales volumes in our upstream assets, partially offset by stronger refining margins in our downstream operations. Cash from operating activities was $2.4 billion, an increase from $1.3 billion in the first quarter of 2025, mainly due to changes in non-cash working capital.
•Redemption of preferred shares. On June 30, 2025, Cenovus exercised its right to redeem all 6.0 million of the Company’s series 7 preferred shares at a price of $25.00 per share, for a total of $150 million.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 4

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

| Six Months Ended June 30, |  | 2025 |  | 2024 |  | 2023 |  |
($ millions, except where indicated) | 2025 |  | 2024 |  | Q2 |  | Q1 |  | Q4 |  | Q3 |  | Q2 |  | Q1 |  | Q4 |  | Q3 |  |
Upstream Production Volumes (1) (MBOE/d) | 792.2 |  |  | 800.9 |  |  | 765.9 |  |  | 818.9 |  |  | 816.0 |  |  | 771.3 |  |  | 800.8 |  |  | 800.9 |  |  | 808.6 |  |  | 797.0 |  |  |
Downstream Total Processed Inputs (2) (3) (Mbbls/d) | 707.7 |  |  | 668.3 |  |  | 714.9 |  |  | 700.5 |  |  | 700.5 |  |  | 674.4 |  |  | 652.9 |  |  | 683.8 |  |  | 605.7 |  |  | 691.3 |  |  |
Crude Oil Unit Throughput (2) (Mbbls/d) | 665.7 |  |  | 639.0 |  |  | 665.8 |  |  | 665.4 |  |  | 666.7 |  |  | 642.9 |  |  | 622.7 |  |  | 655.2 |  |  | 579.1 |  |  | 664.3 |  |  |
Downstream Production Volumes (1) (2) (Mbbls/d) | 725.8 |  |  | 680.8 |  |  | 729.4 |  |  | 722.4 |  |  | 722.6 |  |  | 685.2 |  |  | 659.5 |  |  | 702.1 |  |  | 627.4 |  |  | 706.0 |  |  |
Revenues (4) | 25,618 |  |  | 27,645 |  |  | 12,319 |  |  | 13,299 |  |  | 12,813 |  |  | 13,819 |  |  | 14,582 |  |  | 13,063 |  |  | 13,134 |  |  | 14,577 |  |  |
Operating Margin (5) | 4,877 |  |  | 6,127 |  |  | 2,066 |  |  | 2,811 |  |  | 2,274 |  |  | 2,408 |  |  | 2,936 |  |  | 3,191 |  |  | 2,151 |  |  | 4,369 |  |  |
Operating Margin – Upstream (6) | 5,185 |  |  | 5,720 |  |  | 2,137 |  |  | 3,048 |  |  | 2,670 |  |  | 2,731 |  |  | 3,089 |  |  | 2,631 |  |  | 2,455 |  |  | 3,447 |  |  |
Operating Margin – Downstream (6) | (308) |  |  | 407 |  |  | (71) |  |  | (237) |  |  | (396) |  |  | (323) |  |  | (153) |  |  | 560 |  |  | (304) |  |  | 922 |  |  |
Cash From (Used In) Operating Activities | 3,689 |  |  | 4,732 |  |  | 2,374 |  |  | 1,315 |  |  | 2,029 |  |  | 2,474 |  |  | 2,807 |  |  | 1,925 |  |  | 2,946 |  |  | 2,738 |  |  |
Adjusted Funds Flow (5) | 3,731 |  |  | 4,603 |  |  | 1,519 |  |  | 2,212 |  |  | 1,601 |  |  | 1,960 |  |  | 2,361 |  |  | 2,242 |  |  | 2,062 |  |  | 3,447 |  |  |
Per Share – Basic (5) ($) | 2.05 |  |  | 2.47 |  |  | 0.84 |  |  | 1.21 |  |  | 0.88 |  |  | 1.06 |  |  | 1.27 |  |  | 1.20 |  |  | 1.10 |  |  | 1.82 |  |  |
Per Share – Diluted (5) ($) | 2.04 |  |  | 2.45 |  |  | 0.84 |  |  | 1.21 |  |  | 0.87 |  |  | 1.05 |  |  | 1.26 |  |  | 1.19 |  |  | 1.08 |  |  | 1.81 |  |  |
Capital Investment | 2,393 |  |  | 2,191 |  |  | 1,164 |  |  | 1,229 |  |  | 1,478 |  |  | 1,346 |  |  | 1,155 |  |  | 1,036 |  |  | 1,170 |  |  | 1,025 |  |  |
Free Funds Flow (5) | 1,338 |  |  | 2,412 |  |  | 355 |  |  | 983 |  |  | 123 |  |  | 614 |  |  | 1,206 |  |  | 1,206 |  |  | 892 |  |  | 2,422 |  |  |
Excess Free Funds Flow (5) | 67 |  |  | 1,567 |  |  | (306) |  |  | 373 |  |  | (416) |  |  | 146 |  |  | 735 |  |  | 832 |  |  | 471 |  |  | 1,989 |  |  |
Net Earnings (Loss) | 1,710 |  |  | 2,176 |  |  | 851 |  |  | 859 |  |  | 146 |  |  | 820 |  |  | 1,000 |  |  | 1,176 |  |  | 743 |  |  | 1,864 |  |  |
Per Share – Basic ($) | 0.94 |  |  | 1.16 |  |  | 0.47 |  |  | 0.47 |  |  | 0.08 |  |  | 0.44 |  |  | 0.53 |  |  | 0.62 |  |  | 0.39 |  |  | 0.98 |  |  |
Per Share – Diluted ($) | 0.92 |  |  | 1.15 |  |  | 0.45 |  |  | 0.47 |  |  | 0.07 |  |  | 0.42 |  |  | 0.53 |  |  | 0.62 |  |  | 0.32 |  |  | 0.97 |  |  |
Total Assets | 55,820 |  |  | 56,000 |  |  | 55,820 |  |  | 56,380 |  |  | 56,539 |  |  | 54,680 |  |  | 56,000 |  |  | 54,994 |  |  | 53,915 |  |  | 54,427 |  |  |
Long-Term Debt, Including Current Portion | 7,241 |  |  | 7,275 |  |  | 7,241 |  |  | 7,524 |  |  | 7,534 |  |  | 7,199 |  |  | 7,275 |  |  | 7,227 |  |  | 7,108 |  |  | 7,224 |  |  |
Net Debt | 4,934 |  |  | 4,258 |  |  | 4,934 |  |  | 5,079 |  |  | 4,614 |  |  | 4,196 |  |  | 4,258 |  |  | 4,827 |  |  | 5,060 |  |  | 5,976 |  |  |
Cash Returns to Common and Preferred Shareholders | 1,414 |  |  | 1,470 |  |  | 819 |  |  | 595 |  |  | 706 |  |  | 1,070 |  |  | 1,034 |  |  | 436 |  |  | 731 |  |  | 1,225 |  |  |
Common Shares – Base Dividends | 691 |  |  | 596 |  |  | 364 |  |  | 327 |  |  | 330 |  |  | 329 |  |  | 334 |  |  | 262 |  |  | 261 |  |  | 264 |  |  |
Base Dividends Per Common Share ($) | 0.380 |  |  | 0.320 |  |  | 0.200 |  |  | 0.180 |  |  | 0.180 |  |  | 0.180 |  |  | 0.180 |  |  | 0.140 |  |  | 0.140 |  |  | 0.140 |  |  |
Common Shares – Variable Dividends | — |  |  | 251 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 251 |  |  | — |  |  | — |  |  | — |  |  |
Variable Dividends Per Common Share ($) | — |  |  | 0.135 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.135 |  |  | — |  |  | — |  |  | — |  |  |
Purchase of Common Shares Under NCIB | 363 |  |  | 605 |  |  | 301 |  |  | 62 |  |  | 108 |  |  | 732 |  |  | 440 |  |  | 165 |  |  | 350 |  |  | 361 |  |  |
Payment for Purchase of Warrants | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 111 |  |  | 600 |  |  |
Dividends Paid on Preferred Shares | 10 |  |  | 18 |  |  | 4 |  |  | 6 |  |  | 18 |  |  | 9 |  |  | 9 |  |  | 9 |  |  | 9 |  |  | — |  |  |
Preferred Share Redemptions | 350 |  |  | — |  |  | 150 |  |  | 200 |  |  | 250 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  |

(1)Refer to the Operating and Financial Results section of this MD&A for a summary of total production by product type.
(2)Represents Cenovus’s net interest in refining operations.
(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.
(4)2024 comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.
(5)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(6)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 5

OPERATING AND FINANCIAL RESULTS

Selected Operating and Financial Results — Upstream

| Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |  |
|  |  | Percent Change |  |  |  |  |  | Percent Change |  |  |  |  |  |
| 2025 |  |  | 2024 |  | 2025 |  |  | 2024 |  |  |
Production Volumes by Segment (1) (MBOE/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands | 579.8 |  | (5) |  |  | 611.5 |  | 602.9 |  | (2) |  |  | 613.4 |  |  |  |
Conventional (2) | 119.8 |  | (3) |  |  | 123.1 |  | 121.8 |  | — |  |  | 121.9 |  |  |  |
Offshore (3) | 66.3 |  | — |  |  | 66.2 |  | 67.5 |  | 3 |  |  | 65.6 |  |  |  |
Total Production Volumes | 765.9 |  | (4) |  |  | 800.8 |  | 792.2 |  | (1) |  |  | 800.9 |  |  |  |
Production Volumes by Product (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bitumen (Mbbls/d) | 552.1 |  | (7) |  |  | 591.7 |  | 577.1 |  | (3) |  |  | 593.5 |  |  |  |
Heavy Crude Oil (Mbbls/d) | 25.0 |  | 38 |  |  | 18.1 |  | 23.4 |  | 30 |  |  | 18.0 |  |  |  |
Light Crude Oil (Mbbls/d) | 17.0 |  | 26 |  |  | 13.5 |  | 16.9 |  | 30 |  |  | 13.0 |  |  |  |
NGLs (Mbbls/d) | 29.9 |  | (9) |  |  | 33.0 |  | 29.9 |  | (9) |  |  | 32.8 |  |  |  |
Conventional Natural Gas (MMcf/d) | 851.4 |  | (2) |  |  | 867.2 |  | 869.5 |  | 1 |  |  | 861.5 |  |  |  |
Total Production Volumes (MBOE/d) | 765.9 |  | (4) |  |  | 800.8 |  | 792.2 |  | (1) |  |  | 800.9 |  |  |  |
Per-Unit Operating Expenses by Segment ($/BOE) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands (4) | 13.60 |  |  | 19 |  |  | 11.47 |  | 12.64 |  | 8 |  |  | 11.67 |  |  |  |
Conventional (2) (5) | 9.95 |  | (12) |  |  | 11.25 |  | 10.44 |  | (14) |  |  | 12.14 |  |  |  |
Offshore (3) (5) | 15.94 |  | (29) |  |  | 22.34 |  | 15.71 |  | (22) |  |  | 20.03 |  |  |  |

(1)Refer to the Oil Sands, Conventional and Offshore reportable segments section of this MD&A for a summary of production by product type by segment.
(2)For the three and six months ended June 30, 2025, reported Conventional segment production and per-unit operating expenses include Cenovus’s 30 percent equity interest in the Duvernay Energy Corporation (“Duvernay”) joint venture, which is accounted for using the equity method in the interim Consolidated Financial Statements. Operating expenses for the Conventional segment, excluding our equity interests in the Duvernay joint venture, were $115 million and $242 million, respectively.
(3)Reported Offshore segment production and per-unit operating expenses include Cenovus’s 40 percent equity interest in the HCML joint venture, which is accounted for using the equity method in the interim Consolidated Financial Statements. Operating expenses for the Offshore segment, excluding our equity interests in the HCML joint venture, for the three and six months ended June 30, 2025, were $81 million and $170 million, respectively (2024 – $142 million and $227 million, respectively).
(4)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(5)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
Production
Total upstream production decreased in the three and six months ended June 30, 2025, compared with 2024, due to:
•The temporary shut-in of production at Christina Lake in response to wildfire activity in late May.
•Turnaround activities at Foster Creek and Sunrise.
•The temporary shut-in of production at our Rush Lake facilities as we respond to a casing failure at a steam injection well.
The decreases were partially offset by:
•Increased production from optimization activities and the ramp-up of well pads at Foster Creek and Sunrise.
•The safe restart of production at the White Rose field as the SeaRose floating production, storage and offloading unit (“FPSO”) resumed operations in our Atlantic region in the first quarter of 2025 and fully ramped up in the second quarter. There was no production at the White Rose field in 2024.
•Strong base production and additional volumes from new development wells at our Lloydminster conventional heavy oil assets.
Per-Unit Operating Expenses
For the six months ended June 30, 2025, per-unit operating expenses increased in the Oil Sands segment compared with 2024, primarily due to turnaround activities, and higher waste fluid handling and trucking costs. Per-unit operating expenses decreased in the Conventional segment mainly due to lower processing and gathering costs, and lower repairs and maintenance costs. Per-unit operating expenses decreased in the Offshore segment compared with 2024, primarily due to lower repairs and maintenance, and vessels and air service costs as the SeaRose asset life extension (“ALE”) project was completed in the first quarter of 2025.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 6

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

| Three Months Ended June 30, |  | Six Months Ended June 30,
|  |  | Percent Change |  |  |  |  |  | Percent Change |  |
| 2025 |  |  | 2024 |  | 2025 |  |  | 2024
Crude Oil Unit Throughput by Segment (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |
Canadian Refining | 112.4 |  | 109 |  |  | 53.8 |  | 112.2 |  | 42 |  |  | 79.0
U.S. Refining | 553.4 |  | (3) |  |  | 568.9 |  | 553.5 |  | (1) |  |  | 560.0
Total Crude Oil Unit Throughput | 665.8 |  | 7 |  |  | 622.7 |  | 665.7 |  | 4 |  |  | 639.0 |
Production Volumes by Product (1) (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |
Gasoline | 277.1 |  | — |  |  | 278.3 |  | 280.9 |  | — |  |  | 280.1
Distillates (2) | 221.9 |  | — |  |  | 221.5 |  | 223.1 |  | 3 |  |  | 217.2
Synthetic Crude Oil | 55.3 |  | 167 |  |  | 20.7 |  | 53.8 |  | 59 |  |  | 33.9
Asphalt | 41.0 |  | 2 |  |  | 40.2 |  | 41.6 |  | 1 |  |  | 41.0
Ethanol | 5.0 |  | 14 |  |  | 4.4 |  | 4.6 |  | (6) |  |  | 4.9
Other | 129.1 |  | 37 |  |  | 94.4 |  | 121.8 |  | 17 |  |  | 103.7
Total Production Volumes | 729.4 |  | 11 |  |  | 659.5 |  | 725.8 |  | 7 |  |  | 680.8
Per-Unit Operating Expenses by Segment (3) ($/bbl) |  |  |  |  |  |  |  |  |  |  |
Canadian Refining | 10.70 |  | (85) |  |  | 70.44 |  | 10.75 |  | (69) |  |  | 34.36
U.S. Refining | 14.92 |  | 18 |  |  | 12.66 |  | 14.31 |  | 18 |  |  | 12.17
Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3) ($/bbl) |  |  |  |  |  |  |  |  |  |  |
Canadian Refining | 10.63 |  | (66) |  |  | 30.92 |  | 10.72 |  | (45) |  |  | 19.53
U.S. Refining | 10.52 |  | (9) |  |  | 11.58 |  | 11.32 |  | — |  |  | 11.30

(1)Refer to the Canadian Refining and U.S. Refining reportable segments section of this MD&A for a summary of production by product by segment.
(2)Includes diesel and jet fuel.
(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A. In the Canadian Refining segment, operating expenses represent expenses associated with the Lloydminster Upgrader, the Lloydminster Refinery and the commercial fuels business.
Total downstream throughput and refined product production increased in the three and six months ended June 30, 2025, compared with 2024, due to strong throughput as our Canadian Refining assets ran at, or above capacity. In the second quarter of 2024, we executed the largest turnaround in the history of the Upgrader, which significantly reduced throughput and refined product production.
The increase above was partially offset by lower throughput in our U.S. Refining assets in the three and six months ended June 30, 2025, compared with 2024. The limited impact to throughput and total refined product production was due to the Toledo turnaround being well executed, combined with improved process unit reliability across our other operated refineries driven by ongoing operational improvements made to the U.S. Refining business.
In the six months ended June 30, 2025, per-unit operating expenses excluding turnaround costs decreased in the Canadian Refining segment compared with 2024, due to lower project costs and higher total processed inputs. Total processed inputs were lower and operating expenses were higher in 2024, due to the major turnaround completed at the Upgrader.
In the six months ended June 30, 2025, per-unit operating expenses excluding turnaround costs were relatively consistent in the U.S. Refining segment compared with 2024, primarily due to lower repairs and maintenance, and project costs, mainly offset by higher electricity costs and foreign exchange impacts from a slight weakening of the Canadian dollar, on average, relative to the U.S. dollar.
Selected Consolidated Financial Results
Revenues
Revenues decreased 16 percent to $12.3 billion and seven percent to $25.6 billion in the three and six months ended June 30, 2025, respectively, compared with the same periods in 2024. The decrease for both periods was primarily due to lower benchmark crude oil and refined product pricing. The quarter-over-quarter decrease was also due to lower sales volumes in our upstream and U.S. Refining assets due to turnaround activities in the second quarter of 2025. Year-over-year, the decrease was partially offset by higher sales volumes in our upstream assets.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 7

Operating Margin
Operating Margin is a non-GAAP financial measure and is used to provide a consistent measure of the cash-generating performance of our assets for comparability of our underlying financial performance between periods.

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

(1)Comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.
Operating Margin by Segment
Three Months Ended June 30, 2025 and 2024
Operating Margin decreased compared with the second quarter of 2024, primarily due to:
•Lower Realized Sales Prices and lower sales volumes impacting revenues in our Oil Sands and Offshore segments.
•Lower refined product prices and the narrowing of the WTI-WCS and upgrading differentials impacting our U.S. Refining and Canadian Refining segments, respectively.
•Higher operating expenses for turnaround activities at our Oil Sands and U.S. Refining assets.
The decreases were partially offset by:
•Lower operating expenses and higher sales volumes in our Canadian Refining segment due to the turnaround at the Upgrader in the second quarter of 2024, as discussed above.
•Lower operating expenses related to the SeaRose ALE project in our Atlantic operations, due to the completion of the project in the first quarter of 2025.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 8

Six Months Ended June 30, 2025 and 2024
Operating Margin decreased in the six months ended June 30, 2025, compared with 2024, primarily due to the reasons discussed above, partially offset by higher sales volumes at our Oil Sands and Atlantic operations.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
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 June 30, |  | Six Months Ended June 30, |
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024 |  |
Cash From (Used in) Operating Activities | 2,374 |  |  | 2,807 |  |  | 3,689 |  |  | 4,732 |  |  |
(Add) Deduct: |  |  |  |  |  |  |  |  |
Settlement of Decommissioning Liabilities | (68) |  |  | (48) |  |  | (104) |  |  | (96) |  |  |
Net Change in Non-Cash Working Capital | 923 |  |  | 494 |  |  | 62 |  |  | 225 |  |  |
Adjusted Funds Flow | 1,519 |  |  | 2,361 |  |  | 3,731 |  |  | 4,603 |  |  |

Cash from operating activities and Adjusted Funds Flow decreased in the three and six months ended June 30, 2025, compared with the same periods in 2024, primarily due to lower Operating Margin, as discussed above.
For the three months ended June 30, 2025, changes in non-cash working capital increased cash from operating activities by $923 million, primarily due to changes in accounts payable, inventories and income tax receivable, partially offset by changes in accounts receivable.
Net Earnings (Loss)
Net earnings in the three and six months ended June 30, 2025, was $851 million and $1.7 billion, respectively, compared with $1.0 billion and $2.2 billion, respectively, in 2024. The decrease in both periods was due to lower Operating Margin, as discussed above, partially offset by foreign exchange gains in 2025, compared with losses in 2024, and lower income tax expense.
Net Debt

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

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

Total debt decreased by $210 million from December 31, 2024, primarily due to an unrealized foreign exchange gain of $283 million on long-term debt, as the Canadian dollar strengthened relative to the U.S. dollar as at June 30, 2025. This was partially offset by higher short-term borrowings under the WRB uncommitted demand facilities. Net Debt increased by $320 million from December 31, 2024, mainly due to capital investment of $2.4 billion, base dividends of $691 million and preferred share redemptions of $350 million, partially offset by cash from operating activities of $3.7 billion. For further details, see the Liquidity and Capital Resources section of this MD&A.
Capital Investment (1)

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

(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes capital expenditures related to equity interests in joint ventures accounted for using the equity method in the interim Consolidated Financial Statements.
Capital investment in the first six months of 2025 was mainly related to:
•Sustaining, optimization and redevelopment programs in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated winter program.
•The progression of the West White Rose project.
•Growth projects in our Oil Sands segment, including the Sunrise growth program, the optimization project at Foster Creek, the progression of the drilling program at our Lloydminster conventional heavy oil assets and the Narrows Lake tie-back to Christina Lake.
•Reliability and sustaining activities in our refining segments.
•Drilling, completion, tie-in and infrastructure projects in the Conventional segment.
Drilling Activity

| Net Stratigraphic Test Wells and Observation Wells |  | Net Production Wells (1)
Six Months Ended June 30, | 2025 |  | 2024 |  | 2025 |  | 2024
Foster Creek | 73 |  |  | 82 |  |  | 25 |  |  | 7 |
Christina Lake | 65 |  |  | 58 |  |  | 13 |  |  | 9 |
Sunrise | 21 |  |  | 40 |  |  | 2 |  |  | — |
Lloydminster Thermal | — |  |  | — |  |  | 12 |  |  | 4 |
Lloydminster Conventional Heavy Oil | — |  |  | — |  |  | 15 |  |  | 3 |
| 159 |  |  | 180 |  |  | 67 |  |  | 23 |

(1)Steam-assisted gravity drainage well pairs in the Oil Sands segment are counted as a single producing well.
Stratigraphic test wells were drilled to help identify future well pad locations and to further evaluate our assets. Observation wells were drilled to gather information and monitor reservoir conditions.

| Six Months Ended June 30, 2025 (1) |  | Six Months Ended June 30, 2024
(net wells) | Drilled |  | Completed |  | Tied-in |  | Drilled |  | Completed |  | Tied-in
Conventional | 18 |  |  | 24 |  |  | 21 |  |  | 18 |  |  | 14 |  |  | 14 |

(1)Includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay joint venture.
In the Offshore segment, no wells were drilled or completed in the first six months of 2025 (2024 – commenced drilling one well in China).

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

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined product prices and refining crack spreads, as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)

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

(1)These benchmark prices are not our Realized Sales Prices and represent approximate values. For our Realized Sales Prices refer to the Netback tables in the upstream reportable segments section of this MD&A.
(2)The average 3-2-1 crack spread is an indicator of the adjusted refining margin and is valued on a last-in, first-out accounting basis.
(3)The upgrading differential is the difference between synthetic crude oil at Edmonton and Lloydminster Blend crude oil at Hardisty. The upgrading differential does not precisely mirror the configuration and the product output of our Canadian Refining assets; however, it is used as a general market indicator.
(4)Alberta Energy Company (“AECO”) 5A natural gas daily index.
(5)New York Mercantile Exchange (“NYMEX”) natural gas monthly index.
Crude Oil and Condensate Benchmarks
In the second quarter of 2025, global crude oil benchmark prices, Brent and WTI, decreased compared with the second quarter of 2024 and the first quarter of 2025, due to uncertainty surrounding the U.S. economy, tariff policies and increasing global supply with the unwinding of OPEC+ voluntary production cuts that started in May 2025. Volatility in prices remained high during the quarter due to continued geopolitical uncertainty, new U.S. sanctions targeting Iran and Venezuela, low global and U.S. crude inventories, and the conflict between Israel and Iran.

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

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices, and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties.
WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude, and the cost of transport. In the six months ended June 30, 2025, the WTI-WCS differential at Hardisty narrowed compared with 2024, due to the start-up of Trans Mountain Pipeline expansion project (“TMX”) increasing market access for WCS crude, low inventory levels in the Western Canadian Sedimentary Basin and stronger global demand for heavy crude.
WCS at Nederland is a heavy oil benchmark for sales of our product at the U.S. Gulf Coast (“USGC”). The WTI-WCS at Nederland differential is representative of the heavy oil quality differential and is influenced by global heavy oil refining capacity and global heavy oil supply. In the six months ended June 30, 2025, the WTI-WCS at Nederland differential narrowed compared with 2024, due to strong global demand for heavy crudes, declining output from Mexico and Venezuela, remaining impacts of production cuts from OPEC+ members, including Saudi Arabia, and strong pricing for fuel oil in which heavy grades yield more versus light grades.
In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Upgrader. The price realized for HSB is primarily driven by the price of WTI, and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
In the six months ended June 30, 2025, synthetic crude oil at Edmonton strengthened relative to WTI, compared with 2024. The strength in pricing relative to 2024 was a function of deep discounts in the first quarter of 2024 due to high synthetic crude oil production in Alberta and the supply of light crude oil being above pipeline capacity on light crude oil pipelines with limited local storage capacity.
Crude Oil Benchmark Prices (1)
(1)Forward pricing as at June 30, 2025.
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated as diluent volumes as a percentage of total blended volumes, range from approximately 20 percent to 35 percent. The Condensate-WCS differential is an important benchmark, as a higher premium generally results in a decrease in Operating Margin when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending, as well as timing of blended product sales.
In the six months ended June 30, 2025, the average Edmonton condensate benchmark traded at a smaller discount to WTI compared with 2024, due to the same factors impacting the synthetic crude oil to WTI differential, as discussed above, as well as tight Canadian supply and low Canadian inventories.

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

Refining Benchmarks
RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the adjusted refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel, using current-month WTI-based crude oil feedstock prices and valued on a last-in, first-out basis.
In the six months ended June 30, 2025, refined product crack spreads in Chicago declined slightly compared with the same period in 2024, as U.S. refineries continued operating at high utilization rates, especially in PADD 2 where some expected spring maintenance was deferred to later in the year. Group 3 crack spreads increased in the six months ended June 30, 2025, compared with the same period in 2024, largely as a function of tight regional gasoline inventories. Crack spreads increased in the second quarter of 2025, compared with the first quarter of 2025, consistent with seasonal trends as driving season increases demand. The average cost of RINs were higher in the six months ended June 30, 2025, compared with the same period of 2024, due to weaker U.S. production and imports of renewable diesel and biodiesel causing a decline in RINs generation.
North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices. The strength of refining market crack spreads in the U.S. Midwest and Midcontinent generally reflects the differential between Brent and WTI benchmark prices.
Our adjusted refining margin is affected by various other factors such as the quality and purchase location of crude oil feedstock, and refinery configuration and product output. The benchmark market crack spreads do not precisely mirror the configuration and product output of our refineries, or the location we sell product; however, they are used as a general market indicator.
Refined Product Benchmarks (1)
(1)Forward pricing as at June 30, 2025.
Natural Gas Benchmarks
In the six months ended June 30, 2025, AECO prices increased compared with 2024, though not as much as the increase in NYMEX pricing, as the AECO discount widened due to strong production levels and limited Western Canadian takeaway capacity. In the six months ended June 30, 2025, NYMEX natural gas prices increased compared with 2024. This is largely a rebound from weak 2024 pricing due to oversupply and high inventories, whereas prices in 2025 have been supported by strong liquified natural gas (“LNG”) demand. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.

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

Foreign Exchange Benchmarks
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. dollar benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported revenue. In addition to our revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. Changes in foreign exchange rates also impact the translation of our U.S. and Asia Pacific operations.
In the three and six months ended June 30, 2025, on average, the Canadian dollar weakened relative to the U.S. dollar compared with the same periods of 2024, positively impacting our reported revenues and negatively impacting our U.S. Refining operating expenses.
A portion of our long-term sales contracts in the Asia Pacific region are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. In the three and six months ended June 30, 2025, on average, the Canadian dollar weakened relative to RMB, compared with the same periods of 2024, positively impacting our reported revenues.
Interest Rate Benchmarks
Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. A change in interest rates could change our net finance costs, affect how certain liabilities are measured, and impact our cash flow and financial results.
As at June 30, 2025, the Bank of Canada’s policy interest rate was 2.75 percent. On July 30, 2025, the Bank of Canada held the policy interest rate at 2.75 percent.

OUTLOOK

Commodity Price Outlook
Global crude oil prices have trended lower in the first five months of 2025, with a modest rebound in June. OPEC+ policy continues to remain crucial to global oil supply and demand balances, and prices. The unwinding of OPEC+ voluntary production cuts that started in May 2025 has weighed on oil prices. Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers. Price volatility remained heightened over the first half of 2025, with continued geopolitical risks.
The policies around tariffs, trade relations and global conflicts will be key considerations for energy prices. Global policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shift global trade patterns. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing geopolitical tensions between Israel and Iran, the Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-OPEC+ supply growth, and tensions between Venezuela and Guyana.
Recent U.S. tariff announcements, pauses, delays and modifications have introduced significant uncertainty in the market and raised the probability of a global recession. We expect heightened price volatility across all commodities to continue until there is a firm resolution on the duration and magnitude of the tariffs. In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession remain risks to the pace of demand growth. Impacts of the One Big Beautiful Bill Act in the U.S. are generally positive for the oil and gas industry in the long-term, but it is unlikely that there will be significant near-term implications.
In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
•In the near-term, there is a higher risk of a tariff-induced global economic slowdown that could slow oil demand.
•We expect the WTI-WCS at Hardisty differential will remain largely tied to global supply factors and heavy crude oil processing capacity, as long as supply does not exceed Canadian crude oil export capacity. As expected, the start-up of TMX in 2024 is having a narrowing impact on the WTI-WCS differential.
•Refined product prices and market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America and globally.
•AECO and NYMEX natural gas prices are expected to remain range bound. The prospect of new LNG facilities in the U.S. and Canada coming into service or ramping up in the next year could increase demand and support North American natural gas prices. Weather will also continue to be a key driver of demand and impact prices.
•We expect the Canadian dollar to continue to be impacted by the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, the U.S. Administration’s policies toward Canada-U.S. trade, crude oil prices and emerging macro-economic factors.

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

Most of our upstream crude oil and downstream refined product production is exposed to movements in the WTI crude oil price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane, and is used as crude oil feedstock at our downstream refining operations. Condensate extracted from our blended crude oil is sold back to our Oil Sands segment.
Our refining capacity is primarily focused in the U.S. Midwest, along with smaller exposures in the USGC and Alberta, exposing us to market crack spreads in these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly.
Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our refining capacity, and to a lesser degree, in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differentials, which could be subject to transportation constraints.
While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product differentials through the following:
•Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.
•Integration – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil and spreads on refined products.
•Monitoring market fundamentals and optimizing run rates at our refineries accordingly.
•Traditional crude oil storage tanks in various geographic locations.
Key Priorities for 2025
Our 2025 priorities are focused on top-tier safety performance, maintaining and growing our competitive advantages in our Oil Sands business, executing on our growth projects and implementing operational improvements in our downstream business. We will continue to maintain our returns to shareholders, and focus on cost and sustainability improvements.
Top-tier Safety Performance
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, and aim to be best-in-class operators for each of our major assets and businesses.
Oil Sands Business
Our Oil Sands business is the backbone of our company. Maintaining and growing our competitive advantage through our asset development and operating strategy, while operating safely and reliably, is critical to our company.
Project Execution
Investing in future growth is a focus for us, with several key projects underway, including the West White Rose project, the optimization and sulphur recovery projects at Foster Creek, the Sunrise growth program and the Lloydminster conventional heavy oil drilling program. We completed commissioning of the Narrows Lake tie-back to Christina Lake and achieved first oil in July.
Downstream Competitiveness
A competitive, reliable downstream business is essential to our integrated business. It allows us to be agile in our response to fluctuating demand for refined products and serves as a natural partial hedge in times of widening location and heavy oil differentials.
We will continue to implement operational improvements to our downstream assets to maximize the long-term profitability of our assets.
Returns to Shareholders
Maintaining a strong balance sheet with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle is a key element of Cenovus’s capital allocation framework. We plan to steward Net Debt to $4.0 billion and return 100 percent of Excess Free Funds Flow to shareholders over time. For further details, see the Liquidity and Capital Resources section of this MD&A.

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Cost Leadership
We aim to maximize shareholder value through a continued focus on low-cost structures and margin optimization across our business. We are focused on reducing operating, capital, and general and administrative costs, realizing the full value of our integrated strategy, while making decisions that support long-term value for Cenovus.
Sustainability
Sustainability is central to Cenovus’s culture. We have established targets in our environmental, social and governance (“ESG”) focus areas, and we continue to advance work to support progress against these targets.
We continue to support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal and provincial governments that provide a sufficient level of fiscal support to progress large-scale carbon capture projects, while maintaining global competitiveness. It is critical that the federal and provincial governments provide support at a level consistent with what similar large-scale carbon capture projects are receiving globally to enable Canada to achieve its greenhouse gas (“GHG”) emissions goals.
Additional information on Cenovus’s performance in safety, Indigenous reconciliation, and acceptance and belonging is available in Cenovus’s 2024 Corporate Social Responsibility report on our website at cenovus.com.
2025 Corporate Guidance
Our 2025 guidance, as updated on July 30, 2025, is available on our website at cenovus.com.
Changes to our updated guidance include:
•A decrease at the midpoint of total upstream production due to the temporary shut-in of production at our Rush Lake facilities.
•An increase at the midpoint of total downstream throughput due to strong year-to-date performance.
The following table is a sub-set of our full guidance for 2025:

| Capital Investment ($ millions) |  | Production (MBOE/d) |  | Crude Oil Unit Throughput (Mbbls/d)
Upstream |  |  |  |  |
Oil Sands | 2,700 - 2,800 |  | 620 - 625 |  |
Conventional | 350 - 400 |  | 120 - 125 |  |
Offshore | 900 - 1,000 |  | 65 - 75 |  |
Upstream Total | 3,950 - 4,200 |  | 805 - 825 |  |
Downstream | 650 - 750 |  |  |  | 655 - 690
Corporate and Eliminations | Up to 50 |  |  |  |

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

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REPORTABLE SEGMENTS

UPSTREAM
Oil Sands
In the second quarter of 2025, we:
•Delivered safe and reliable operations, including the safe execution of turnarounds at Foster Creek and Sunrise. The turnarounds were well executed, and we returned to full production in June.
•Produced 579.8 thousand BOE per day (2024 – 611.5 thousand BOE per day). The decrease was due to the temporary shut-in of production at our Christina Lake asset in response to wildfire activity, planned downtime for turnaround activities discussed above and the temporary shut-in of production at our Rush Lake facilities within our Lloydminster thermal assets as we respond to a casing failure at a steam injection well.
•Generated Operating Margin of $1.8 billion, a decrease of $926 million compared with 2024, primarily due to lower Realized Sales Prices and lower sales volumes.
•Averaged a Netback of $35.57 per barrel (2024 – $52.10 per barrel).
•Invested capital of $644 million for sustaining activities and growth projects.
Major growth projects remain on track. We completed commissioning of the Narrows Lake tie-back to Christina Lake and achieved first oil in July. The Foster Creek optimization project was approximately 87 percent complete as at June 30, 2025. As part of the Sunrise growth program, we brought one new well pad online. We continued to progress the Lloydminster conventional heavy oil drilling program.
Financial Results

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

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

Operating Margin Variance
Three Months Ended June 30, 2025
Six Months Ended June 30, 2025
(1)Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses.
(2)Includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil or natural gas.
Operating Results

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Total Sales Volumes (1) (MBOE/d) | 568.2 |  |  | 584.5 |  |  | 602.2 |  |  | 595.6 |
Crude Oil Production by Asset (Mbbls/d) |  |  |  |  |  |  |
Foster Creek | 186.1 |  |  | 195.0 |  |  | 194.3 |  |  | 195.5 |
Christina Lake | 217.9 |  |  | 237.1 |  |  | 227.8 |  |  | 236.8 |
Sunrise | 50.3 |  |  | 46.1 |  |  | 51.2 |  |  | 47.4 |
Lloydminster Thermal | 97.8 |  |  | 113.5 |  |  | 103.8 |  |  | 113.8 |
Lloydminster Conventional Heavy Oil | 25.0 |  |  | 18.1 |  |  | 23.4 |  |  | 18.0 |
Total Crude Oil Production (2) (Mbbls/d) | 577.1 |  |  | 609.8 |  |  | 600.5 |  |  | 611.5 |
Natural Gas (1) (MMcf/d) | 16.5 |  |  | 10.5 |  |  | 13.9 |  |  | 11.2 |
Total Production (MBOE/d) | 579.8 |  |  | 611.5 |  |  | 602.9 |  |  | 613.4 |

(1)Bitumen, heavy crude oil and natural gas. Natural gas is a conventional natural gas product type.
(2)Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.

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Operating Results — Continued

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Effective Royalty Rate (1) (percent) |  |  |  |  |  |  |
Foster Creek | 20.5 |  |  | 21.1 |  |  | 22.8 |  |  | 22.9 |
Christina Lake | 23.9 |  |  | 25.9 |  |  | 25.5 |  |  | 25.5 |
Sunrise | 6.3 |  |  | 7.3 |  |  | 6.5 |  |  | 5.8 |
Lloydminster (2) | 13.2 |  |  | 11.2 |  |  | 12.2 |  |  | 9.2 |
Total Effective Royalty Rate | 18.9 |  |  | 19.4 |  |  | 20.2 |  |  | 19.4 |
Netback (3) ($/bbl) |  |  |  |  |  |  |
Realized Sales Price | 70.78 |  |  | 88.76 |  |  | 76.16 |  |  | 80.62 |
Royalties | 11.43 |  |  | 15.21 |  |  | 13.33 |  |  | 13.88 |
Transportation and Blending | 10.18 |  |  | 9.98 |  |  | 10.01 |  |  | 8.74 |
Operating | 13.60 |  |  | 11.47 |  |  | 12.64 |  |  | 11.67 |
Total Netback ($/bbl) | 35.57 |  |  | 52.10 |  |  | 40.18 |  |  | 46.33 |
Per-Unit DD&A (4) ($/BOE) | 14.21 |  |  | 13.68 |  |  | 14.00 |  |  | 13.51 |

(1)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(2)Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets.
(3)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(4)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Revenues
Gross sales decreased for the three months ended June 30, 2025, compared with 2024, due to lower Realized Sales Prices and lower sales volumes. Gross sales slightly increased for the six months ended June 30, 2025, compared with 2024, due to higher sales volumes, offset by lower Realized Sales Prices.
Price
Our bitumen and heavy oil production must be blended with condensate to reduce its viscosity in order to transport it to market through pipelines. Within our Netback calculations, our realized bitumen and heavy oil sales price excludes the impact of purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending increases relative to the price of blended crude oil or our blend ratio increases, our realized bitumen and heavy oil sales price decreases.
Our Realized Sales Price averaged $70.78 per barrel and $76.16 per barrel, respectively, in the three and six months ended June 30, 2025, (2024 – $88.76 per barrel and $80.62 per barrel, respectively), mainly due to a lower WTI benchmark price and a narrower condensate-WCS differential, partially offset by a narrower WTI-WCS differential.
For the three and six months ended June 30, 2025, approximately 41 percent and 39 percent, respectively (2024 – approximately 34 percent and 28 percent, respectively) of our crude oil sales volumes were sold at destinations outside of Alberta. In the same periods, approximately 30 percent and 25 percent, respectively (2024 – approximately 20 percent for both periods) of our sales volumes were sold to our downstream operations.
Cenovus makes storage and transportation decisions to use our marketing and transportation infrastructure, including storage and pipeline assets, in order to optimize product mix, delivery points, transportation commitments and customer diversification. To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.
Production Volumes
Oil Sands crude oil production decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to:
•The temporary shut-in of production at Christina Lake in response to wildfire activity. Production resumed in June.
•Turnaround activities at Foster Creek and Sunrise.
•The temporary shut-in of production at our Rush Lake facilities.

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The decreases were partially offset by:
•Increased production from optimization activities and the ramp-up of well pads at Foster Creek and Sunrise.
•Strong base production and additional volumes from new development wells at our Lloydminster conventional heavy oil assets.
Royalties
Our Alberta oil sands royalty projects are based on government prescribed pre- and post-payout royalty rates. Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.
For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes each project's Crown and freehold split.
Refer to our 2024 annual MD&A for further details.
In the three and six months ended June 30, 2025, Oil Sands royalties decreased compared with 2024, mainly due to lower realized pricing. For the three months ended June 30, 2025, the Oil Sands effective royalty rate decreased, primarily due to lower Alberta sliding scale oil sands royalty rates, partially offset by annual adjustments. For the six months ended June 30, 2025, the Oil Sands effective royalty rate increased, primarily due to annual adjustments, partially offset by lower Alberta sliding scale oil sands royalty rates.
Expenses
Transportation and Blending
In the three and six months ended June 30, 2025, blending expenses were $2.0 billion and $4.6 billion, respectively (2024 – $2.4 billion and $4.7 billion, respectively). The decrease for both periods was primarily due to lower condensate prices, partially offset by the use of higher priced condensate purchased in prior periods.
Transportation expenses were consistent for the three months ended June 30, 2025, compared with 2024, as the decrease in sales volumes was offset by an increase in per-unit transportation expenses. Per-unit transportation expenses increased in the three months ended June 30, 2025, compared with 2024, due to higher sales volumes on TMX, partially offset by lower sales volumes at U.S. destinations. Transportation expenses and per-unit transportation expenses increased in the six months ended June 30, 2025, compared with 2024, primarily due to higher sales volumes on TMX and increased pipeline transportation rates on shipments to U.S. destinations, partially offset by lower sales volumes at U.S. destinations.
Per-Unit Transportation Expenses (1)

| Three Months Ended June 30, |  | Six Months Ended June 30, |  |
($/bbl) | 2025 |  | 2024 |  | 2025 |  | 2024 |  |
Foster Creek | 18.41 |  |  | 14.69 |  |  | 17.01 |  |  | 12.42 |  |  |
Christina Lake | 6.07 |  |  | 7.16 |  |  | 6.10 |  |  | 6.23 |  |  |
Sunrise | 15.28 |  |  | 18.71 |  |  | 16.66 |  |  | 18.62 |  |  |
Lloydminster (2) | 3.28 |  |  | 4.55 |  |  | 3.35 |  |  | 4.22 |  |  |
Total Oil Sands | 10.18 |  |  | 9.98 |  |  | 10.01 |  |  | 8.74 |  |  |

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
At Foster Creek, per-unit transportation expenses increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to the higher use of TMX and higher sales to U.S. destinations. The year-over-year increase was partially offset by lower rail transportation costs. In the three and six months ended June 30, 2025, 38 percent and 35 percent, respectively, of our total sales volumes were sold at West Coast destinations (2024 – 10 percent and five percent, respectively). In the three and six months ended June 30, 2025, 47 percent and 41 percent, respectively, of our total sales volumes were sold at U.S. destinations (2024 – 39 percent and 36 percent, respectively).
At Christina Lake, per-unit transportation expenses decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations. In the three and six months ended June 30, 2025, we shipped 16 and 15 percent, respectively, of our total sales volumes to U.S. destinations (2024 – 23 percent and 17 percent, respectively).
At Sunrise, per-unit transportation expenses decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations, partially offset by the higher use of TMX. In the three and six months ended June 30, 2025, 51 percent and 62 percent, respectively, of our total sales volumes were sold at West Coast destinations (2024 – 16 percent and nine percent, respectively). In the three and six months ended June 30, 2025, 38 percent and 33 percent, respectively, of our total sales volumes were sold at U.S. destinations (2024 – 78 percent and 85 percent, respectively).

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At Lloydminster, per-unit transportation expenses decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes at U.S. destinations. In both the three and six months ended June 30, 2025, we shipped two percent of our total sales to U.S. destinations (2024 – six percent and five percent, respectively).
Operating
Primary drivers of our operating expenses in the first six months of 2025 were fuel, repairs and maintenance, and workforce. Total operating expenses increased in the three and six months ended June 30, 2025, compared with the same periods in 2024, due to higher costs from waste fluid handling and trucking, and turnaround activities combined with higher fuel costs as a result of higher AECO benchmark prices.
Per-Unit Operating Expenses (1)

| Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |  |
($/bbl) | 2025 |  | Percent Change |  | 2024 |  | 2025 |  | Percent Change |  | 2024 |  |  |  |
Foster Creek |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel | 2.90 |  |  | 49 |  |  | 1.95 |  |  | 2.63 |  |  | 1 |  |  | 2.60 |  |  |  |  |
Non-Fuel | 9.44 |  |  | 16 |  |  | 8.11 |  |  | 8.34 |  |  | 6 |  |  | 7.84 |  |  |  |  |
Total | 12.34 |  |  | 23 |  |  | 10.06 |  |  | 10.97 |  |  | 5 |  |  | 10.44 |  |  |  |  |
Christina Lake |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel | 2.28 |  |  | 19 |  |  | 1.91 |  |  | 2.40 |  |  | 2 |  |  | 2.36 |  |  |  |  |
Non-Fuel | 6.42 |  |  | (2) |  |  | 6.58 |  |  | 6.33 |  |  | 3 |  |  | 6.14 |  |  |  |  |
Total | 8.70 |  |  | 2 |  |  | 8.49 |  |  | 8.73 |  |  | 3 |  |  | 8.50 |  |  |  |  |
Sunrise |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel | 4.59 |  |  | 51 |  |  | 3.04 |  |  | 4.47 |  |  | 24 |  |  | 3.61 |  |  |  |  |
Non-Fuel | 15.67 |  |  | 55 |  |  | 10.13 |  |  | 14.45 |  |  | 28 |  |  | 11.30 |  |  |  |  |
Total | 20.26 |  |  | 54 |  |  | 13.17 |  |  | 18.92 |  |  | 27 |  |  | 14.91 |  |  |  |  |
Lloydminster (2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel | 3.13 |  |  | 39 |  |  | 2.25 |  |  | 3.41 |  |  | 7 |  |  | 3.20 |  |  |  |  |
Non-Fuel | 17.99 |  |  | 16 |  |  | 15.56 |  |  | 16.37 |  |  | 11 |  |  | 14.73 |  |  |  |  |
Total | 21.12 |  |  | 19 |  |  | 17.81 |  |  | 19.78 |  |  | 10 |  |  | 17.93 |  |  |  |  |
Total Oil Sands |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel | 2.87 |  |  | 37 |  |  | 2.10 |  |  | 2.86 |  |  | 5 |  |  | 2.72 |  |  |  |  |
Non-Fuel | 10.73 |  |  | 15 |  |  | 9.37 |  |  | 9.78 |  |  | 9 |  |  | 8.95 |  |  |  |  |
Total | 13.60 |  |  | 19 |  |  | 11.47 |  |  | 12.64 |  |  | 8 |  |  | 11.67 |  |  |  |  |

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
In the three and six months ended June 30, 2025, per-unit fuel expenses increased, as discussed above.
Foster Creek and Sunrise per-unit non-fuel costs increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to turnaround activities. In the three months ended June 30, 2025, per-unit non-fuel costs were further impacted by lower sales volumes. Sunrise per-unit non-fuel costs also increased in the three and six months ended June 30, 2025, due to higher GHG compliance costs.
Christina Lake per-unit non-fuel costs decreased in the three months ended June 30, 2025, compared with 2024, primarily due to lower GHG compliance costs, partially offset by lower sales volumes. Per-unit non-fuel costs increased in the six months ended June 30, 2025, compared with 2024, primarily due to lower sales volumes.
Lloydminster per-unit non-fuel costs increased in the three and six months ended June 30, 2025, compared with 2024, due to higher waste fluid handling and trucking costs, and lower sales volumes as we respond to a casing failure at a steam injection well at Rush Lake.

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

Conventional
In the second quarter of 2025, we:
•Delivered safe and reliable operations.
•Produced 119.8 thousand BOE per day (2024 – 123.1 thousand BOE per day).
•Generated Operating Margin of $84 million, an increase of $42 million from 2024.
•Earned a Netback of $7.79 per BOE (2024 – $3.68 per BOE), primarily due to higher Realized Sales Prices and lower operating expenses.
•Invested capital of $73 million, primarily related to drilling, completion, tie-in and infrastructure projects.
Financial Results

| Three Months Ended June 30, |  | Six Months Ended June 30, |  |
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024 |  |
Gross Sales |  |  |  |  |  |  |  |  |
External Sales | 281 |  |  | 264 |  |  | 724 |  |  | 641 |  |  |
Intersegment Sales | 268 |  |  | 427 |  |  | 769 |  |  | 929 |  |  |
| 549 |  |  | 691 |  |  | 1,493 |  |  | 1,570 |  |  |
Royalties | (12) |  |  | (22) |  |  | (32) |  |  | (46) |  |  |
Revenues | 537 |  |  | 669 |  |  | 1,461 |  |  | 1,524 |  |  |
Expenses |  |  |  |  |  |  |  |  |
Purchased Product | 255 |  |  | 412 |  |  | 790 |  |  | 894 |  |  |
Transportation and Blending | 83 |  |  | 83 |  |  | 173 |  |  | 161 |  |  |
Operating | 115 |  |  | 132 |  |  | 242 |  |  | 285 |  |  |
Realized (Gain) Loss on Risk Management | — |  |  | — |  |  | (1) |  |  | (7) |  |  |
Operating Margin | 84 |  |  | 42 |  |  | 257 |  |  | 191 |  |  |
Unrealized (Gain) Loss on Risk Management | (1) |  |  | 2 |  |  | (1) |  |  | 8 |  |  |
Depreciation, Depletion and Amortization | 117 |  |  | 111 |  |  | 237 |  |  | 221 |  |  |
(Income) Loss From Equity-Accounted Affiliates | 1 |  |  | — |  |  | 1 |  |  | 1 |  |  |
Segment Income (Loss) | (33) |  |  | (71) |  |  | 20 |  |  | (39) |  |  |

Operating Margin Variance
Three Months Ended June 30, 2025
(1)Changes to price include the impact of realized risk management gains and losses.
(2)Reflects Operating Margin from processing facilities.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 22

Six Months Ended June 30, 2025
(1)Changes to price include the impact of realized risk management gains and losses.
(2)Reflects Operating Margin from processing facilities.
Operating Results

| Three Months Ended June 30, |  | Six Months Ended June 30, |  |
| 2025 |  | 2024 |  | 2025 |  | 2024 |  |
Total Sales Volumes (1) (MBOE/d) | 119.8 |  |  | 123.1 |  |  | 121.8 |  |  | 121.9 |  |  |
Realized Sales Price (1) (2) ($/BOE) |  |  |  |  |  |  |  |  |
Light Crude Oil ($/bbl) | 77.83 |  |  | 98.12 |  |  | 83.86 |  |  | 92.96 |  |  |
NGLs ($/bbl) | 47.56 |  |  | 56.29 |  |  | 56.22 |  |  | 56.86 |  |  |
Conventional Natural Gas ($/Mcf) | 2.77 |  |  | 1.77 |  |  | 3.45 |  |  | 2.87 |  |  |
Production by Product (1) |  |  |  |  |  |  |  |  |
Light Crude Oil (Mbbls/d) | 4.5 |  |  | 5.1 |  |  | 4.8 |  |  | 5.2 |  |  |
NGLs (Mbbls/d) | 20.4 |  |  | 21.4 |  |  | 20.5 |  |  | 21.7 |  |  |
Conventional Natural Gas (MMcf/d) | 569.2 |  |  | 579.4 |  |  | 579.2 |  |  | 569.9 |  |  |
Total Production (MBOE/d) | 119.8 |  | 123.1 |  | 121.8 |  | 121.9 |  |
Conventional Natural Gas Production (percentage of total) | 79 |  |  | 78 |  |  | 79 |  |  | 78 |  |  |
Crude Oil and NGLs Production (percentage of total) | 21 |  |  | 22 |  |  | 21 |  |  | 22 |  |  |
Effective Royalty Rate (1) (3) (percent) | 7.4 |  |  | 12.4 |  |  | 8.3 |  |  | 11.0 |  |  |
Netback (1) (2) ($/BOE) |  |  |  |  |  |  |  |  |
Realized Sales Price | 24.19 |  |  | 22.20 |  |  | 29.16 |  |  | 27.50 |  |  |
Royalties | 1.18 |  |  | 2.02 |  |  | 1.51 |  |  | 2.09 |  |  |
Transportation and Blending | 5.27 |  |  | 5.25 |  |  | 5.38 |  |  | 4.97 |  |  |
Operating | 9.95 |  |  | 11.25 |  |  | 10.44 |  |  | 12.14 |  |  |
Total Netback ($/BOE) | 7.79 |  |  | 3.68 |  |  | 11.83 |  |  | 8.30 |  |  |
Per-Unit DD&A (4) ($/BOE) | 10.38 |  |  | 9.88 |  |  | 10.37 |  |  | 9.89 |  |  |

(1)For the three and six months ended June 30, 2025, reported production volumes, sales volumes, associated per-unit values and effective royalty rates reflect Cenovus’s 30 percent equity interest in the Duvernay joint venture.
(2)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(3)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(4)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Revenues
Gross sales decreased in the three and six months ended June 30, 2025, compared with 2024, due to lower commodity trading volumes sourced from third parties, partially offset by higher Realized Sales Prices. The quarter-over-quarter decrease was also due to lower sales volumes.

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

Price
Our total Realized Sales Price increased for the three and six months ended June 30, 2025, compared with 2024, primarily due to higher natural gas benchmark prices. For the three and six months ended June 30, 2025, 33 percent and 30 percent, respectively, of our natural gas sales volumes were sold at U.S. destinations where NYMEX natural gas benchmark prices were higher (2024 – 29 percent and 28 percent, respectively). For the three and six months ended June 30, 2025, the AECO natural gas benchmark price was $1.69 per Mcf and $1.93 per Mcf, respectively (2024 – $1.18 per Mcf and $1.84 per Mcf, respectively), and the NYMEX natural gas benchmark price was US$3.44 per Mcf and US$3.55 per Mcf, respectively (2024 – US$1.89 per Mcf and US$2.07 per Mcf, respectively).
Production Volumes
For the three months ended June 30, 2025, production volumes decreased compared with 2024, primarily due to third-party pipeline outages and the divestiture of non-core assets in the third quarter of 2024, partially offset by strong base performance. For the six months ended June 30, 2025, production volumes were relatively consistent compared with 2024, as the decreases in the second quarter were offset by strong base production in the first quarter.
Royalties
Royalties and the effective royalty rate decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower production of natural gas liquids and light crude oil, which are subject to higher royalty rates.
Expenses
Transportation
Our transportation expenses reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. In the three months ended June 30, 2025, transportation expenses and per-unit transportation expenses were consistent compared with 2024. In the six months ended June 30, 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, primarily due to increased pipeline transportation rates.
Operating
Primary drivers of operating expenses in the first six months of 2025 were repairs and maintenance, workforce and property tax costs. Total operating expenses and per-unit operating expenses decreased in the three and six months ended June 30, 2025, compared with 2024, mainly due to lower processing and gathering costs, and lower repairs and maintenance costs.
Offshore
In the second quarter of 2025, we:
•Delivered safe and reliable operations.
•Produced 66.3 thousand BOE per day of light crude oil, NGLs and natural gas (2024 – 66.2 thousand BOE per day).
•Generated Operating Margin of $231 million, a decrease of $68 million from 2024, primarily due to lower sales volumes.
•Averaged a Netback of $51.02 per BOE (2024 – $54.33 per BOE).
•Invested capital of $270 million, mainly related to the progression of the West White Rose project.
The West White Rose project reached major milestones in the second quarter of 2025. The concrete gravity structure was towed out and installed on the seabed. The topsides arrived in Newfoundland and, in July, were set in place atop the concrete gravity structure. Hookup and commissioning work has commenced. As at June 30, 2025, the project was approximately 92 percent complete and we remain on track to deliver first oil in the second quarter of 2026. Since our decision in 2022 to restart the project, we have invested approximately $2.1 billion.

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

Financial Results

| Three Months Ended June 30,
| 2025 |  | 2024
($ millions) | Atlantic |  | Asia Pacific |  | Offshore |  | Atlantic |  | Asia Pacific |  | Offshore
Gross Sales |  |  |  |  |  |  |  |  |  |  |
External Sales | 72 |  | 263 |  | 335 |  | 151 |  | 320 |  | 471
Intersegment Sales | — |  | — |  | — |  | — |  | — |  | —
| 72 |  | 263 |  | 335 |  | 151 |  | 320 |  | 471
Royalties | — |  | (20) |  | (20) |  | 1 |  | (24) |  | (23)
Revenues | 72 |  | 243 |  | 315 |  | 152 |  | 296 |  | 448
Expenses |  |  |  |  |  |  |  |  |  |  |
Transportation and Blending | 3 |  | — |  | 3 |  | 7 |  | — |  | 7
Operating | 48 |  | 33 |  | 81 |  | 110 |  | 32 |  | 142
Operating Margin (1) | 21 |  | 210 |  | 231 |  | 35 |  | 264 |  | 299
Depreciation, Depletion and Amortization |  |  |  |  | 93 |  |  |  |  |  | 156
Exploration Expense |  |  |  |  | 1 |  |  |  |  |  | 4
(Income) Loss from Equity-Accounted Affiliates |  |  |  |  | (7) |  |  |  |  |  | (13)
Segment Income (Loss) |  |  |  |  | 144 |  |  |  |  |  | 152

| Six Months Ended June 30,
| 2025 |  | 2024
($ millions) | Atlantic |  | Asia Pacific |  | Offshore |  | Atlantic |  | Asia Pacific |  | Offshore
Gross Sales |  |  |  |  |  |  |  |  |  |  |
External Sales | 218 |  | 568 |  | 786 |  | 193 |  | 635 |  | 828
Intersegment Sales | — |  | — |  | — |  | — |  | — |  | —
| 218 |  | 568 |  | 786 |  | 193 |  | 635 |  | 828
Royalties | (2) |  | (43) |  | (45) |  | (1) |  | (48) |  | (49)
Revenues | 216 |  | 525 |  | 741 |  | 192 |  | 587 |  | 779
Expenses |  |  |  |  |  |  |  |  |  |  |
Transportation and Blending | 9 |  | — |  | 9 |  | 7 |  | — |  | 7
Operating | 112 |  | 58 |  | 170 |  | 167 |  | 60 |  | 227
Operating Margin (1) | 95 |  | 467 |  | 562 |  | 18 |  | 527 |  | 545
Depreciation, Depletion and Amortization |  |  |  |  | 223 |  |  |  |  |  | 287
Exploration Expense |  |  |  |  | 2 |  |  |  |  |  | 8
(Income) Loss from Equity-Accounted Affiliates |  |  |  |  | (15) |  |  |  |  |  | (23)
Segment Income (Loss) |  |  |  |  | 352 |  |  |  |  |  | 273

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

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 25

Operating Margin Variance
Three Months Ended June 30, 2025
Six Months Ended June 30, 2025
Operating Results

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Sales Volumes |  |  |  |  |  |  |
Atlantic (Mbbls/d) | 7.9 |  |  | 14.8 |  |  | 11.8 |  |  | 9.4 |
Asia Pacific (MBOE/d) |  |  |  |  |  |  |
China | 37.9 |  | 43.5 |  | 39.8 |  | 43.6
Indonesia (1) | 15.9 |  | 14.3 |  | 15.6 |  | 14.2
Total Asia Pacific | 53.8 |  | 57.8 |  | 55.4 |  | 57.8
Total Sales Volumes (MBOE/d) | 61.7 |  | 72.6 |  |  | 67.2 |  | 67.2 |
Production by Product |  |  |  |  |  |  |
Atlantic – Light Crude Oil (Mbbls/d) | 12.5 |  | 8.4 |  | 12.1 |  | 7.8
Asia Pacific (1) |  |  |  |  |  |  |
NGLs (Mbbls/d) | 9.5 |  | 11.6 |  | 9.4 |  | 11.1
Conventional Natural Gas (MMcf/d) | 265.7 |  | 277.3 |  | 276.4 |  | 280.4
Total Asia Pacific (MBOE/d) | 53.8 |  | 57.8 |  | 55.4 |  | 57.8
Total Production (MBOE/d) | 66.3 |  | 66.2 |  | 67.5 |  | 65.6

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

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

Operating Results — Continued

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Effective Royalty Rate (1) (percent) |  |  |  |  |  |  |
Atlantic | 0.9 |  |  | (0.6) |  |  | 1.0 |  |  | 0.5 |
Asia Pacific (2) | 11.9 |  |  | 9.5 |  |  | 12.3 |  |  | 8.6 |
Per-Unit DD&A (3) ($/BOE) | 15.91 |  |  | 22.90 |  |  | 17.61 |  |  | 22.70 |

(1)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(2)Reflects Cenovus’s 40 percent equity interest in the HCML joint venture.
(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Netbacks (1)

| Three Months Ended June 30, 2025
($/BOE, except where indicated) | Atlantic ($/bbl) |  | China | Indonesia | Total Offshore (2)
Realized Sales Price |  | 100.23 |  |  | 76.49 |  |  | 59.06 |  |  | 75.01 |
Royalties |  | 0.94 |  |  | 5.88 |  |  | 14.65 |  |  | 7.52 |
Transportation and Blending |  | 4.14 |  |  | — |  |  | — |  |  | 0.53 |
Operating Expenses |  | 61.44 |  |  | 8.72 |  |  | 10.56 |  |  | 15.94 |
Netback |  | 33.71 |  |  | 61.89 |  |  | 33.85 |  |  | 51.02 |

| Three Months Ended June 30, 2024
($/BOE, except where indicated) | Atlantic ($/bbl) |  | China | Indonesia | Total Offshore (2)
Realized Sales Price |  | 112.74 |  |  | 80.95 |  |  | 60.43 |  |  | 83.38 |
Royalties |  | (0.72) |  |  | 6.20 |  |  | 10.17 |  |  | 5.57 |
Transportation and Blending |  | 5.60 |  |  | — |  |  | — |  |  | 1.14 |
Operating Expenses |  | 79.03 |  |  | 7.24 |  |  | 9.68 |  |  | 22.34 |
Netback |  | 28.83 |  |  | 67.51 |  |  | 40.58 |  |  | 54.33 |

| Six Months Ended June 30, 2025
($/BOE, except where indicated) | Atlantic ($/bbl) |  | China | Indonesia | Total Offshore (2)
Realized Sales Price |  | 101.82 |  |  | 78.85 |  |  | 61.77 |  |  | 78.92 |
Royalties |  | 1.00 |  |  | 6.01 |  |  | 16.98 |  |  | 7.68 |
Transportation and Blending |  | 4.21 |  |  | — |  |  | — |  |  | 0.74 |
Operating Expenses |  | 50.84 |  |  | 7.30 |  |  | 10.61 |  |  | 15.71 |
Netback |  | 45.77 |  |  | 65.54 |  |  | 34.18 |  |  | 54.79 |

| Six Months Ended June 30, 2024
($/BOE, except where indicated) | Atlantic ($/bbl) |  | China | Indonesia | Total Offshore (2)
Realized Sales Price |  | 113.02 |  |  | 80.08 |  |  | 56.77 |  |  | 79.75 |
Royalties |  | 0.50 |  |  | 6.10 |  |  | 7.17 |  |  | 5.54 |
Transportation and Blending |  | 3.97 |  |  | — |  |  | — |  |  | 0.55 |
Operating Expenses |  | 95.82 |  |  | 6.76 |  |  | 10.76 |  |  | 20.03 |
Netback |  | 12.73 |  |  | 67.22 |  |  | 38.84 |  |  | 53.63 |

(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Reported per-unit values reflect Cenovus’s 40 percent equity interest in the HCML joint venture.
Revenues
For the three and six months ended June 30, 2025, gross sales decreased compared with 2024, due to lower sales volumes in our China operations and lower Offshore Realized Sales Prices. The quarter-over-quarter decrease was also impacted by lower sales volumes in our Atlantic operations. The year-over-year decrease was partially offset by higher Atlantic sales volumes.

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

Price
Our Atlantic Realized Sales Price decreased in the three and six months ended June 30, 2025, compared with 2024, due to lower Brent benchmark pricing. The prices we receive for natural gas sold in Asia Pacific are set under long-term contracts.
Production Volumes
Atlantic production increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to the ramp-up of production at the White Rose field early in the second quarter of 2025. The quarter-over-quarter increase was partially offset by maintenance activities at the Terra Nova field. Atlantic production was lower in the same periods in 2024, as production at the White Rose field was suspended in late December 2023 in preparation for the SeaRose ALE project. Light crude oil production from the White Rose and Terra Nova fields are offloaded from the SeaRose and Terra Nova FPSO vessels, respectively, to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales.
Asia Pacific production decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower contracted sales volumes in China and the timing of annual maintenance. The decrease was partially offset by increased production in Indonesia due to higher buyer nominations.
Royalties
For the three and six months ended June 30, 2025, the Atlantic effective royalty rate increased compared with 2024, primarily due to a credit received in 2024.
Royalty rates in Asia Pacific are governed by production-sharing contracts, in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for Asia Pacific increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower cost recoveries resulting in higher royalty rates in Indonesia. The effective royalty rate was lower in 2024, due to credits received in the period.
Expenses
Transportation
Transportation expenses include the costs of transporting crude oil from the Terra Nova and SeaRose FPSOs to onshore terminals and storage costs. Transportation expenses for the three months ended June 30, 2025, decreased to $3 million (2024 – $7 million), primarily due to lower sales volumes. Transportation expenses for the six months ended June 30, 2025, increased to $9 million (2024 – $7 million), primarily due to higher sales volumes.
Operating
Primary drivers of our Atlantic operating expenses in the first six months of 2025 were repairs and maintenance, costs related to vessels and air services, and workforce. In the three and six months ended June 30, 2025, operating expenses and per-unit operating expenses decreased compared with 2024. The decrease for both periods was primarily due to lower repairs and maintenance, and vessels and air service costs as the SeaRose ALE project was completed in the first quarter of 2025.
Primary drivers of our China operating expenses in the first six months of 2025 were repairs and maintenance, insurance and workforce costs. Per-unit operating expenses increased in the three and six months ended June 30, 2025, compared with 2024, due to lower sales volumes.
Primary drivers of our Indonesia operating expenses in the first six months of 2025 were repairs and maintenance, and workforce costs. Indonesia per-unit operating expenses increased in the three months ended June 30, 2025, compared with 2024, due to higher repairs and maintenance costs, partially offset by higher sales volumes. Per-unit operating expenses decreased in the six months ended June 30, 2025, compared with 2024, due to higher sales volumes, partially offset by higher repairs and maintenance costs.

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

DOWNSTREAM
Canadian Refining
In the second quarter of 2025, we:
•Delivered safe and reliable operations.
•Achieved strong crude oil throughput of 112.4 thousand barrels per day and crude unit utilization of 104 percent (2024 – 53.8 thousand barrels per day and 50 percent, respectively).
•Incurred per-unit operating expenses excluding turnaround costs of $10.63 per barrel (2024 – $30.92 per barrel).
•Recorded Operating Margin of $107 million, an increase of $362 million from the second quarter of 2024. The increase was primarily due to lower operating expenses and higher sales volumes, partially offset by lower refined product pricing, and higher heavy crude oil and bitumen feedstock costs due to the narrowing of the upgrading differential.
•Invested capital of $28 million, primarily focused on sustaining activities.
Financial and Operating Results

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Revenues | 1,288 |  |  | 1,135 |  |  | 2,570 |  |  | 2,467 |
Purchased Product | 1,040 |  |  | 975 |  |  | 2,116 |  |  | 2,062 |
Gross Margin (1) | 248 |  |  | 160 |  |  | 454 |  |  | 405 |
Expenses |  |  |  |  |  |  |
Operating | 141 |  |  | 415 |  |  | 279 |  |  | 592 |
Operating Margin | 107 |  |  | (255) |  |  | 175 |  |  | (187) |
Depreciation, Depletion and Amortization | 52 |  |  | 54 |  |  | 99 |  |  | 98 |
Segment Income (Loss) | 55 |  |  | (309) |  |  | 76 |  |  | (285) |

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

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions, except where indicated) | 2025 |  | 2024 |  | 2025 |  | 2024
Gross Margin | 248 |  | 160 |  | 454 |  | 405
Inventory Holding (Gain) Loss (1) | (12) |  | 5 |  | (9) |  | (18)
Adjusted Gross Margin (2) | 236 |  | 165 |  | 445 |  | 387
Adjusted Refining Margin (3) ($/bbl) | 19.64 |  | 26.23 |  | 18.50 |  | 22.34

(1)Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the first-in, first-out (“FIFO”) or weighted average cost basis, as required by IFRS Accounting Standards.
(2)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(3)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader, the Lloydminster Refinery and the commercial fuels business for the three and six months ended June 30, 2025, were $1.2 billion and $2.4 billion, respectively (2024 – $1.1 billion and $2.3 billion, respectively).
Revenues, Adjusted Gross Margin and Adjusted Refining Margin
The Upgrader processes blended heavy crude oil and bitumen into high-value synthetic crude oil and low-sulphur diesel. Upgrading Gross Margin is primarily dependent on the differential between the sales price of synthetic crude oil and diesel, and the cost of heavy crude oil and bitumen feedstock.
The Lloydminster Refinery processes blended heavy crude oil into asphalt, bulk distillates and industrial products. Gross Margin is largely dependent on asphalt and industrial products pricing, and the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery are seasonal and increase during paving season, which typically runs from May through October each year.
Revenues increased in the three and six months ended June 30, 2025, compared with 2024, primarily due to higher sales volumes, partially offset by lower refined product pricing.
Adjusted Gross Margin increased in the three and six months ended June 30, 2025, compared with the same periods in 2024, primarily due to higher sales volumes, partially offset by higher heavy crude oil and bitumen feedstock costs as a result of the narrowing of the upgrading differential.
Adjusted Refining Margin decreased in the three and six months ended June 30, 2025, as the increase in Adjusted Gross Margin, as discussed above, was more than offset by the increase in total processed inputs.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 29

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Mbbls/d, except where indicated) | 2025 |  | 2024 |  | 2025 |  | 2024
Operable Capacity | 108.0 |  |  | 108.0 |  |  | 108.0 |  |  | 108.0 |
Total Processed Inputs | 120.7 |  |  | 58.9 |  |  | 120.1 |  |  | 83.8 |
Crude Oil Unit Throughput | 112.4 |  |  | 53.8 |  |  | 112.2 |  |  | 79.0 |
Crude Unit Utilization (percent) | 104 |  |  | 50 |  |  | 104 |  |  | 73 |
Total Production | 129.0 |  |  | 64.0 |  |  | 127.6 |  |  | 90.1 |
Synthetic Crude Oil | 55.3 |  |  | 20.7 |  |  | 53.8 |  |  | 33.9 |
Asphalt | 16.7 |  |  | 14.0 |  |  | 16.6 |  |  | 14.8 |
Diesel | 15.1 |  |  | 5.2 |  |  | 15.3 |  |  | 9.0 |
Other | 36.9 |  |  | 19.7 |  |  | 37.3 |  |  | 27.5 |
Ethanol | 5.0 |  |  | 4.4 |  |  | 4.6 |  |  | 4.9 |

The Upgrader and Lloydminster Refinery source their crude oil feedstock from our Oil Sands segment. In the three and six months ended June 30, 2025, 16 percent and 15 percent, respectively, of our Oil Sands segment’s sales volumes were purchased by our Canadian Refining segment (2024 – seven percent and 10 percent, respectively).
Throughput and total production increased in the three and six months ended June 30, 2025, compared with 2024. In 2025, our assets ran at, or above, capacity due to ongoing improvement initiatives and high asset reliability. In the second quarter of 2024, we safely executed the largest turnaround in the history of the Upgrader, which significantly decreased throughput and increased operating expenses.
Operating Expenses
The following table and discussion represent operating expenses associated with the Upgrader, the Lloydminster Refinery and the commercial fuels business.

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions, except where indicated) | 2025 |  | 2024 |  | 2025 |  | 2024
Operating Expenses – Upgrading and Refining | 117 |  |  | 377 |  |  | 234 |  |  | 524 |
Operating Expenses – Excluding Turnaround Costs | 116 |  |  | 166 |  |  | 233 |  |  | 298 |
Operating Expenses – Turnaround Costs | 1 |  |  | 211 |  |  | 1 |  |  | 226 |
Per-Unit Operating Expenses (1) ($/bbl) | 10.70 |  |  | 70.44 |  |  | 10.75 |  |  | 34.36 |
Per-Unit Operating Expenses – Excluding Turnaround Costs | 10.63 |  |  | 30.92 |  |  | 10.72 |  |  | 19.53 |
Per-Unit Operating Expenses – Turnaround Costs | 0.07 |  |  | 39.52 |  |  | 0.03 |  |  | 14.83 |

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Primary drivers of operating expenses were workforce, and repairs and maintenance costs.
In the three and six months ended June 30, 2025, operating expenses decreased compared with the same periods in 2024, mainly due to the turnaround completed at the Upgrader and other project expenses incurred in the second quarter of 2024.
Operating expenses excluding turnaround costs decreased in the three and six months ended June 30, 2025, compared with 2024, due to lower project costs.
In the three and six months ended June 30, 2025, the decrease in operating expenses, combined with increased total processed inputs, resulted in decreased per-unit operating metrics compared with 2024.
U.S. Refining
In the second quarter of 2025, we:
•Delivered safe and reliable operations.
•Safely executed the turnaround at the Toledo Refinery ahead of schedule. Turnarounds were also completed at the non-operated Wood River and Borger refineries.
•Achieved crude unit utilization of 90 percent (2024 – 93 percent) and throughput of 553.4 thousand barrels per day, compared with 568.9 thousand barrels per day in the second quarter of 2024.
•Incurred per-unit operating expenses excluding turnaround costs of $10.52 per barrel (2024 – $11.58 per barrel).
•Recorded an Operating Margin shortfall of $178 million, a decrease of $280 million from the second quarter of 2024, primarily due to the narrowing of the WTI-WCS differential combined with higher operating expenses from turnaround activities.
•Invested capital of $146 million, primarily focused on reliability and sustaining activities.

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

Financial and Operating Results

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Revenues (1) | 6,455 |  |  | 7,615 |  |  | 12,878 |  |  | 14,516 |
Purchased Product (1) | 5,838 |  |  | 6,821 |  |  | 11,844 |  |  | 12,619 |
Gross Margin (2) | 617 |  |  | 794 |  |  | 1,034 |  |  | 1,897 |
Expenses |  |  |  |  |  |  |
Operating | 806 |  |  | 684 |  |  | 1,522 |  |  | 1,294 |
Realized (Gain) Loss on Risk Management | (11) |  |  | 8 |  |  | (5) |  |  | 9 |
Operating Margin | (178) |  |  | 102 |  |  | (483) |  |  | 594 |
Unrealized (Gain) Loss on Risk Management | — |  |  | (10) |  |  | (8) |  |  | (2) |
Depreciation, Depletion and Amortization | 149 |  |  | 112 |  |  | 307 |  |  | 223 |
Segment Income (Loss) | (327) |  |  | — |  |  | (782) |  |  | 373 |

(1)Comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.
(2)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions, except where indicated) | 2025 |  | 2024 |  | 2025 |  | 2024
Gross Margin | 617 |  |  | 794 |  |  | 1,034 |  |  | 1,897 |
Inventory Holding (Gain) Loss (1) | 62 |  |  | (83) |  |  | 85 |  |  | (277) |
Adjusted Gross Margin (2) | 679 |  |  | 711 |  |  | 1,119 |  |  | 1,620 |
Adjusted Refining Margin (2) ($/bbl) | 12.57 |  |  | 13.15 |  |  | 10.53 |  |  | 15.23 |
Adjusted Market Capture (2) (percent) | 58 |  |  | 63 |  |  | 59 |  |  | 77 |

(1)Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the FIFO or weighted average cost basis, as required by IFRS Accounting Standards.
(2)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
Revenues
Revenues decreased in the three and six months ended June 30, 2025, compared with 2024, primarily due to lower benchmark gasoline and diesel prices.
Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture
Benchmark market crack spreads do not precisely mirror the refinery configuration for crude diet and product yields, or the location we sell product; however, they are used as a general market indicator.
In the three months ended June 30, 2025, the Chicago 3-2-1 crack spread increased 15 percent and the Group 3 3-2-1 crack spread increased 27 percent, compared with 2024. During this period, the average cost of RINs increased by 81 percent. Quarter-over-quarter, Adjusted Gross Margin decreased due to the narrowing of the WTI-WCS differential by 25 percent, partially offset by the increase in the weighted average crack spread, net of RINs.
In the first half of 2025, the Chicago 3-2-1 crack spread decreased two percent and the Group 3 3-2-1 crack spread increased 11 percent compared with 2024, which was more than offset by a 54 percent increase in the average cost of RINs. Year-over-year, Adjusted Gross Margin decreased due to the narrowing of the WTI-WCS differential by 30 percent and the lower weighted average crack spread, net of RINs.
Adjusted Refining Margin, which is the Adjusted Gross Margin on a per-barrel basis, is affected by many factors. Some of these factors include the type of crude oil feedstock processed; refinery configuration and the proportion of gasoline, distillates and secondary product output; and the cost of feedstock.
Adjusted Refining Margin and Adjusted Market Capture decreased in the three and six months ended June 30, 2025, compared with the same periods in 2024, due to the decrease in Adjusted Gross Margin. While the turnaround at the Toledo Refinery in the quarter impacted the Adjusted Refining Margin and Adjusted Market Capture, this was offset by ongoing operational improvements in our U.S. Refining business.

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

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Mbbls/d, except where indicated) | 2025 |  | 2024 |  | 2025 |  | 2024
Operable Capacity | 612.3 |  |  | 612.3 |  |  | 612.3 |  |  | 612.3 |
Total Processed Inputs | 594.2 |  |  | 594.0 |  |  | 587.6 |  |  | 584.5 |
Crude Oil Unit Throughput | 553.4 |  |  | 568.9 |  |  | 553.5 |  |  | 560.0 |
Heavy Crude Oil | 214.2 |  |  | 219.4 |  |  | 220.2 |  |  | 222.1 |
Light/Medium Crude Oil | 339.2 |  |  | 349.5 |  |  | 333.3 |  |  | 337.9 |
Crude Unit Utilization (percent) | 90 |  |  | 93 |  |  | 90 |  |  | 91 |
Total Refined Product Production | 600.4 |  |  | 595.5 |  |  | 598.2 |  |  | 590.7 |
Gasoline | 277.1 |  |  | 278.3 |  |  | 280.9 |  |  | 280.1 |
Distillates (1) | 206.8 |  |  | 216.3 |  |  | 207.8 |  |  | 208.2 |
Asphalt | 24.3 |  |  | 26.2 |  |  | 25.0 |  |  | 26.2 |
Other | 92.2 |  |  | 74.7 |  |  | 84.5 |  |  | 76.2 |

(1)Includes diesel and jet fuel.
In the second quarter of 2025, we completed turnarounds at the Toledo Refinery and at the non-operated Wood River and Borger refineries.
Throughput decreased slightly in the three and six months ended June 30, 2025, compared with the same periods in 2024. Total refined product production increased slightly in the three and six months ended June 30, 2025, compared with the same periods in 2024.
The limited impact to throughput and total refined product production in the three and six months ended June 30, 2025, is due to the Toledo turnaround being well executed, combined with improved process unit reliability across our other operated refineries driven by ongoing operational improvements made to the U.S. Refining business.
Operating Expenses

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions, except where indicated) | 2025 |  | 2024 |  | 2025 |  | 2024
Operating Expenses | 806 |  |  | 684 |  |  | 1,522 |  |  | 1,294 |
Operating Expenses – Excluding Turnaround Costs | 568 |  |  | 626 |  |  | 1,204 |  |  | 1,202 |
Operating Expenses – Turnaround Costs | 238 |  |  | 58 |  |  | 318 |  |  | 92 |
Per-Unit Operating Expenses (1) ($/bbl) | 14.92 |  |  | 12.66 |  |  | 14.31 |  |  | 12.17 |
Per-Unit Operating Expenses – Excluding Turnaround Costs | 10.52 |  |  | 11.58 |  |  | 11.32 |  |  | 11.30 |
Per-Unit Operating Expenses – Turnaround Costs | 4.40 |  |  | 1.08 |  |  | 2.99 |  |  | 0.87 |

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Primary drivers of operating expenses were turnarounds, workforce, and repairs and maintenance costs.
In the three and six months ended June 30, 2025, operating expenses increased compared with the same periods in 2024. This was mainly due to $238 million of turnaround costs recognized in the quarter, as discussed above, partially offset by a decrease in repairs and maintenance costs.
Overall, controllable operating expenses excluding turnaround costs decreased in the three and six months ended June 30, 2025, compared with 2024, due to ongoing business improvement initiatives and improved reliability.
Operating expenses excluding turnaround costs and related per-unit metrics for the three months ended June 30, 2025, decreased primarily due to lower controllable operating expenses, including lower repairs and maintenance, and project costs, partially offset by higher electricity costs and foreign exchange impacts from a slight weakening of the Canadian dollar, on average, relative to the U.S. dollar.
Operating expenses excluding turnaround costs and related per-unit metrics for the six months ended June 30, 2025, were relatively consistent, as the decrease in controllable operating expenses, as discussed above, was mainly offset by higher electricity costs and foreign exchange impacts.

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

CORPORATE AND ELIMINATIONS
Financial Results

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Realized (Gain) Loss on Risk Management | (20) |  |  | — |  |  | (25) |  |  | 3 |
Unrealized (Gain) Loss on Risk Management | (84) |  |  | — |  |  | (46) |  |  | 30 |
General and Administrative | 153 |  |  | 175 |  |  | 350 |  |  | 421 |
Finance Costs, Net | 114 |  |  | 141 |  |  | 250 |  |  | 276 |
Integration, Transaction and Other Costs | 77 |  |  | 39 |  |  | 79 |  |  | 72 |
Foreign Exchange (Gain) Loss, Net | (353) |  |  | 55 |  |  | (353) |  |  | 154 |
Other (Income) Loss, Net | (26) |  |  | (40) |  |  | (32) |  |  | (130) |

General and Administrative
Primary drivers of our general and administrative expenses for the three and six months ended June 30, 2025, were workforce and information technology related costs. For the three and six months ended June 30, 2025, general and administrative expenses decreased compared with 2024, primarily due to lower long-term incentive costs.
Finance Costs, Net
Net finance costs were lower in the three and six months ended June 30, 2025, compared with the same periods in 2024, due to higher interest income. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.
The annualized weighted average interest rate on outstanding debt for the three and six months ended June 30, 2025, was 4.53 percent and 4.54 percent, respectively (2024 – 4.49 and 4.48 percent, respectively).
Foreign Exchange (Gain) Loss, Net

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

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

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

For the six months ended June 30, 2025, we recorded a current tax expense related to operations in all jurisdictions in which we operate, except the U.S. The decrease in current tax expense is due to lower earnings compared with the same period in 2024.
The effective tax rate in the first six months of 2025 was 20.3 percent, a decrease from the same period in the prior year (2024 – 24.0 percent). Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to, different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax basis and other legislation.

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

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and, with consideration of the current economic environment, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.

LIQUIDITY AND CAPITAL RESOURCES

Our capital allocation framework enables us to preserve our balance sheet, provide flexibility in both high and low commodity price environments, and deliver value to shareholders.
We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and cash equivalents, and other sources of liquidity. Our other sources of liquidity include draws on our committed credit facility, draws on our uncommitted demand facilities, and other corporate and financial opportunities, which provide timely access to funding to supplement cash flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Ratings, Morningstar DBRS and Fitch Ratings. The cost and availability of borrowing, and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Cash From (Used In) |  |  |  |  |  |  |
Operating Activities | 2,374 |  |  | 2,807 |  |  | 3,689 |  |  | 4,732 |
Investing Activities | (1,375) |  |  | (1,170) |  |  | (2,723) |  |  | (2,305) |
Net Cash Provided (Used) Before Financing Activities | 999 |  |  | 1,637 |  |  | 966 |  |  | 2,427 |
Financing Activities | (1,078) |  |  | (912) |  |  | (1,372) |  |  | (1,589) |
Effect of Foreign Exchange on Cash and Cash Equivalents | (126) |  |  | 29 |  |  | (124) |  |  | 89 |
Increase (Decrease) in Cash and Cash Equivalents | (205) |  |  | 754 |  |  | (530) |  |  | 927 |
|  |  |  |  | June 30, |  | December 31,
As at ($ millions) |  |  |  |  | 2025 |  | 2024
Cash and Cash Equivalents |  |  |  |  | 2,563 |  |  | 3,093 |
Total Debt |  |  |  |  | 7,497 |  |  | 7,707 |

Cash From (Used in) Operating Activities
In the three and six months ended June 30, 2025, cash from operating activities decreased compared with the same periods in 2024, primarily due to lower Operating Margin. For the three months ended June 30, 2025, changes in non-cash working capital increased cash from operating activities by $923 million, primarily due to changes in accounts payable, inventories and income tax receivable, partially offset by changes in accounts receivable.
Cash From (Used in) Investing Activities
Cash used in investing activities increased in the three and six months ended June 30, 2025, compared with 2024. Cash used in investing activities primarily relates to capital investment.
Cash From (Used in) Financing Activities
Cash used in financing activities increased in the three months ended June 30, 2025, compared with 2024, primarily related to a repayment of short-term borrowings in the second quarter of 2025, compared with an issuance in the second quarter of 2024, and preferred share redemptions of $150 million in the second quarter of 2025. These increases were partially offset by fewer purchases under the Company’s NCIB and variable dividends of $251 million paid in 2024, with no variable dividend declared in 2025.
Cash used in financing activities decreased in the six months ended June 30, 2025, compared with 2024, due to the variable dividends, as discussed above, and fewer common shares purchased under the Company’s NCIB. This was partially offset by preferred share redemptions of $350 million in the six months ended June 30, 2025.
Working Capital
Working capital as at June 30, 2025, was $2.3 billion (December 31, 2024 – $3.1 billion). The decrease was primarily driven by lower inventories and cash and cash equivalents, partially offset by higher accounts receivable.
We anticipate that we will continue to meet our payment obligations as they come due.

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

Returns to Shareholders Target
Maintaining a strong balance sheet, with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle, is a key element of Cenovus’s capital allocation framework. Our Net Debt target is $4.0 billion and represents a Net Debt to Adjusted Funds Flow ratio target of approximately 1.0 times at the bottom of the commodity pricing cycle, which we believe is a WTI price of approximately US$45.00 per barrel.
We plan to return 100 percent of Excess Free Funds Flow to shareholders over time, while stewarding Net Debt near $4.0 billion. Working capital movements, foreign exchange rate changes and other factors may result in periods where shareholder returns are less than, or exceed, Excess Free Funds Flow and Net Debt is above or below our target. The allocation of Excess Free Funds Flow to shareholder returns may be accelerated, deferred or reallocated between quarters at Management’s discretion.

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Excess Free Funds Flow (1) | (306) |  |  | 735 |  |  | 67 |  |  | 1,567 |
Target Return (2) | (306) |  |  | 368 |  |  | 67 |  |  | 784 |
Shareholder Returns by way of: |  |  |  |  |  |  |
Purchase of Common Shares Under NCIB | 301 |  |  | 440 |  |  | 363 |  |  | 605 |
Variable Dividends Paid | — |  |  | 251 |  |  | — |  |  | 251 |
Preferred Share Redemption | 150 |  |  | — |  |  | 350 |  |  | — |
Total | 451 |  |  | 691 |  |  | 713 |  |  | 856 |

(1)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)The target return for the three and six months ended June 30, 2025, was 100 percent of Excess Free Funds Flow. The target return for the three and six months ended June 30, 2024, was 50 percent of Excess Free Funds Flow.
Short-Term Borrowings
There were no direct borrowings on our uncommitted demand facilities as at June 30, 2025, or December 31, 2024. As at June 30, 2025, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$188 million (C$256 million) (December 31, 2024 – US$120 million (C$173 million)).
Long-Term Debt, Including Current Portion
Long-term debt, including the current portion, as at June 30, 2025, was $7.2 billion (December 31, 2024 – $7.5 billion). We hold U.S. dollar denominated unsecured notes of US$3.8 billion (C$5.2 billion) (December 31, 2024 – US$3.8 billion (C$5.5 billion)) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2024 – $2.0 billion).
As at June 30, 2025, we were in compliance with all of the terms of our debt agreements, which includes the terms of our committed credit facility. We are required to maintain a debt to capitalization ratio, as defined in the debt agreements, not to exceed 65 percent. We are below this limit.
Upon maturity on July 15, 2025, the Company repaid its 5.38 percent unsecured notes with a principal of US$133 million in full.
Available Sources of Liquidity
The following sources of liquidity are available as at June 30, 2025:

($ millions) | Maturity |  |  |  |  |  |  |  | Amount Available
Cash and Cash Equivalents | n/a |  |  |  |  |  |  |  | 2,563 |
Committed Credit Facility (1) |  |  |  |  |  |  |  |  |
Revolving Credit Facility – Tranche A | June 26, 2028 |  |  |  |  |  |  |  | 3,300 |
Revolving Credit Facility – Tranche B | June 26, 2027 |  |  |  |  |  |  |  | 2,200 |
Uncommitted Demand Facilities |  |  |  |  |  |  |  |  |
Cenovus Energy Inc. (2) | n/a |  |  |  |  |  |  |  | 1,068 |
WRB (3) | n/a |  |  |  |  |  |  |  | 51 |

(1)No amounts were drawn on the committed credit facility as at June 30, 2025 (December 31, 2024 – $nil).
(2)Represents amounts available for cash draws. Our uncommitted demand facilities include $1.7 billion, of which $1.4 billion may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at June 30, 2025, there were outstanding letters of credit aggregating to $363 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).
(3)Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at June 30, 2025, US$188 million (C$256 million) of this capacity was drawn (December 31, 2024 – US$120 million (C$173 million)).

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

Base Shelf Prospectus
We have a base shelf prospectus that allows us to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, Total Debt, the Net Debt to Adjusted EBITDA ratio, the Net Debt to Adjusted Funds Flow ratio and the Net Debt to Capitalization ratio. Refer to Note 10 of the interim Consolidated Financial Statements for further details.
We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents, and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholder’s Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA ratio, as net earnings (loss) before finance costs, net, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, (gain) loss on divestiture of assets, re-measurement of contingent payments and net other (income) loss calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and are measures of our overall financial strength.

As at | June 30, 2025 |  | December 31, 2024 |  |
Net Debt to Adjusted EBITDA Ratio (times) | 0.6 |  | 0.5 |  |
Net Debt to Adjusted Funds Flow Ratio (times) | 0.7 |  | 0.6 |  |
Net Debt to Capitalization Ratio (percent) | 14 |  |  | 13 |  |  |

Our Net Debt to Adjusted EBITDA ratio and our Net Debt to Adjusted Funds Flow ratio targets are approximately 1.0 times and Net Debt at or below $4.0 billion over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices or the strengthening or weakening of the Canadian dollar relative to the U.S. dollar. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, steward working capital, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common or preferred shares for cancellation, issue new debt, or issue new shares.
Our Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio as at June 30, 2025, increased compared with December 31, 2024, as a result of lower Operating Margin and higher Net Debt. See the Operating and Financial Results section of this MD&A for more information on changes in Operating Margin and Net Debt.
Our Net Debt to Capitalization ratio as at June 30, 2025, increased compared with December 31, 2024, primarily due to higher Net Debt.
Share Capital and Stock-Based Compensation Plans
Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Our cumulative redeemable preferred shares series 1 and 2 are listed on the TSX. On March 31, 2025, and June 30, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company’s series 5 preferred shares, and 6.0 million of the Company’s series 7 preferred shares, respectively. The preferred shares were redeemed at a price of $25.00 per share, for a total of $350 million.
As at June 30, 2025, there were approximately 1,805.9 million common shares outstanding (December 31, 2024 – 1,825.0 million common shares) and 12.0 million preferred shares outstanding (December 31, 2024 – 26.0 million preferred shares).
In the fourth quarter of 2024, Cenovus established an employee benefit plan trust (the “Trust”). The Trust, through an independent trustee, acquires Cenovus’s common shares on the open market, which are held to satisfy the Company’s obligations under certain stock-based compensation plans. For the six months ended June 30, 2025, the Trust purchased 3.6 million common shares for a total of $73 million and distributed 3.8 million common shares for a total of $82 million under the employee benefit plan. As at June 30, 2025, there were 1.8 million common shares held by the Trust (December 31, 2024 – 2.0 million common shares). Refer to Note 13 of the interim Consolidated Financial Statements for further details.

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

As at June 30, 2025, there were approximately 3.2 million Cenovus Warrants outstanding (December 31, 2024 – 3.6 million). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years from the date of issue at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to Note 13 of the interim Consolidated Financial Statements for further details.
Refer to Note 15 of the interim Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows:

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

Common Share Dividends
In the three months ended June 30, 2025, we declared and paid base dividends of $364 million or $0.200 per common share (2024 – $334 million or $0.180 per common share). In the six months ended June 30, 2025, we declared and paid base dividends of $691 million or $0.380 per common share (2024 – $596 million or $0.320 per common share).
On July 30, 2025, the Board declared a third quarter base dividend of $0.200 per common share. The dividend is payable on September 29, 2025, to common shareholders of record as at September 15, 2025.
The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.
Cumulative Redeemable Preferred Share Dividends

| Three Months Ended June 30, |  | Six Months Ended June 30,
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024
Series 1 First Preferred Shares | 1 |  | 1 |  | 3 |  | 3
Series 2 First Preferred Shares | 1 |  | 1 |  | 1 |  | 1
Series 3 First Preferred Shares | — |  | 3 |  | — |  | 6
Series 5 First Preferred Shares | — |  | 3 |  | 2 |  | 5
Series 7 First Preferred Shares | 2 |  | 1 |  | 4 |  | 3
Total Preferred Share Dividends Declared and Paid | 4 |  | 9 |  | 10 |  | 18

On July 30, 2025, the Board declared a third quarter dividend on the series 1 and 2 preferred shares for a total of $2 million, payable on October 1, 2025, to preferred shareholders of record as at September 15, 2025.
The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly.
Share Repurchases
We have an NCIB program to purchase up to 127.5 million common shares from November 11, 2024, to November 10, 2025.

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Common Shares Purchased and Cancelled Under NCIB (millions of common shares) | 17.2 |  |  | 15.4 |  |  | 20.2 |  |  | 22.8 |
Weighted Average Price per Common Share ($) | 17.12 |  |  | 27.88 |  |  | 17.64 |  |  | 26.07 |
Purchase of Common Shares Under NCIB ($ millions) | 301 |  |  | 440 |  |  | 363 |  |  | 605 |

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

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

Contractual Obligations and Commitments
We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from our total commitments disclosed below. For further information, see Note 20 of the interim Consolidated Financial Statements.
Our total commitments were $26.3 billion as at June 30, 2025 (December 31, 2024 – $27.3 billion), of which $23.3 billion are for various transportation and storage commitments. Transportation commitments include $34 million that are subject to regulatory approval or were approved but are not yet in service. Terms are up to 7 years on commencement.
As at June 30, 2025, our total commitments included commitments with HMLP of $1.8 billion related to long-term transportation and storage commitments (December 31, 2024 – $1.8 billion).
As at June 30, 2025, outstanding letters of credit issued as security for performance under certain contracts totaled $363 million (December 31, 2024 – $355 million).
Legal Proceedings
We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our interim Consolidated Financial Statements.
Transactions with Related Parties
Husky Midstream Limited Partnership
The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. The Company charges HMLP for construction and management services, and incurs costs for the use of HMLP’s pipeline systems, as well as transportation and storage services.
The following table summarizes revenues and associated expenses related to HMLP:

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

RISK MANAGEMENT AND RISK FACTORS

For a full understanding of the risks that impact us, the following discussion should be read in conjunction with the Risk Management and Risk Factors section of our 2024 annual MD&A.
We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the energy industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, our business, reputation, financial condition, results of operations and cash flows, which may, without limitation, reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, respond to changes in our operating environment, repurchase our shares, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and/or may materially affect the market price of our securities.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, as well as use judgment, in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2024.
Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements. A full list of the critical judgments used in applying accounting policies and key sources of estimation uncertainty can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2024.

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CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at June 30, 2025. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at June 30, 2025.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

ADVISORY

Oil and Gas Information
Barrels of Oil Equivalent – natural gas volumes are converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Forward-looking Information
This document contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “advance”, “aim”, “allocate”, “anticipate”, “believe”, “commit”, “continue”, “could”, “deliver”, “estimate”, “expect”, “F”, “focus”, “grow”, “improve”, “invest”, “may”, “maximize”, “meet”, “mitigate”, “on track”, “objective”, “ongoing”, “opportunities”, “optimize”, “plan”, “position”, “priority”, “progress”, “strategy”, “steward”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our five strategic objectives; shareholder value and returns; safety performance; sustainability; our commitment to the Pathways Alliance foundational project; maximizing value and profitability; disciplined capital allocation; cash flow volatility and stability; price alignment and volatility management strategies; dividends; focus on cost and sustainability improvements; liquidity; our 2025 corporate guidance; realizing the full value of our integrated strategy; capitalizing on opportunities; Net Debt; allocating Excess Free Funds Flow; absolute and per share Free Funds Flow growth; our competitive, reliable downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; project execution; growing our competitive advantages while operating safely and reliably monitoring market fundamentals and optimizing run rates at our refineries; safe and reliable operations; being best-in-class operators; maintaining a strong balance sheet; costs; margins; long-term value for Cenovus; timing of completion of the West White Rose project; progressing growth projects, including the Narrows Lake tie-back to Christina Lake, the Foster Creek optimization, Lloydminster drilling program and Sunrise growth projects; our ESG focus areas and targets; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; general outlook for crude oil and refined product prices; price volatility and geopolitical risks; impact of U.S. tariffs on market benchmarks and Cenovus; Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; capitalizing on opportunities throughout the commodity price cycle; Net Debt to Adjusted EBITDA ratio; maintaining sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar, the factors that affect such outlook, and the influences and effects on Cenovus.
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast bitumen, crude oil and natural gas, NGLs, condensate and refined products prices, and light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs, projected capital investment levels, the flexibility of capital spending plans and associated sources of funding;

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the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change Indigenous relations, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions and the supply and demand for bitumen, crude oil and natural gas, NGLs, condensate and refined products, the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, third party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company’s share price and market capitalization over the long-term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the Company’s ability to use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange rate and interest rates; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue and fund future investments and development plans and dividends, including any increase thereto; our downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; realization of expected capacity to store within the Company’s oil sands reservoirs barrels not yet produced, including that the Company will be able to time production and sales of its inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and future crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, NGLs from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company’s ability to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability to complete acquisitions and divestitures, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third-party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of ESG targets and the Pathways Alliance project, the commercial viability and scalability of related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2025 guidance available on cenovus.com and as set out below; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.
2025 guidance dated July 30, 2025, and available on cenovus.com, assumes: Brent prices of US$69.00 per barrel, WTI prices of US$65.00 per barrel; WCS of US$53.50 per barrel; Differential WTI-WCS of US$11.50 per barrel; AECO natural gas prices of $2.00 per Mcf; Chicago 3-2-1 crack spread of US$18.50 per barrel; and an exchange rate of $0.72 US$/C$.
The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; the Company’s ability to successfully integrate acquired business with its own in a timely and cost effective manner; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and divestitures; the Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of ESG targets and the Pathways Alliance project and the commercial viability and scalability of related technology and products; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; the Company’s ability to integrate upstream and downstream operations to help mitigate the impact of volatility in light-heavy crude oil differentials and contribute to its net earnings; foreign exchange risk, including related to agreements denominated in foreign currencies; the Company’s continued liquidity being sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential remaining largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of the Company’s outlook for commodity prices, the impact of tariffs and responses thereto, currency and interest rates; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; the ability to complete and optimize drilling, completion, tie in and infrastructure projects; the ability of the Company to ramp-up activities at its refineries on its anticipated timelines; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the

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future; tax audits and reassessments; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and refining processes; the occurrence of unexpected events resulting in operational interruptions, including at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics and pandemics; and catastrophic events, including, but not limited to, war, adverse sea conditions, extreme weather events, natural disasters, acts of activism, vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying refining or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s business, including potential cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and the Company’s ability to attract and retain, critical and diverse talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; OPEC+ policy; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.
Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward‐looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors in the Company’s most recently filed Annual MD&A, and the risk factors described in other documents the Company files from time to time with securities regulatory authorities in Canada, available on SEDAR+ at sedarplus.ca, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Company’s website at cenovus.com.
Information on or connected to the Company’s website at cenovus.com does not form part of this MD&A unless expressly incorporated by reference herein.

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ABBREVIATIONS AND DEFINITIONS
Abbreviations
The following abbreviations and definitions are used in this document:

Crude Oil and NGLs | Natural Gas | Other
bbl | barrel | Mcf | thousand cubic feet | BOE | barrel of oil equivalent
Mbbls/d | thousand barrels per day | MMcf | million cubic feet | MBOE/d | thousand barrels of oil equivalent per day
WCS | Western Canadian Select | MMcf/d | million cubic feet per day | DD&A | depreciation, depletion and amortization
WTI | West Texas Intermediate |  |  | ESG | environmental, social and governance
|  |  |  | GHG | greenhouse gas
|  |  |  | FPSO | floating production, storage and offloading unit
|  |  |  | NCIB | normal course issuer bid
|  |  |  | AECO | Alberta Energy Company
|  |  |  | NYMEX | New York Mercantile Exchange
|  |  |  | OPEC | Organization of Petroleum Exporting Countries
|  |  |  | OPEC+ | OPEC and a group of 11 non-OPEC members
|  |  |  | USGC | U.S. Gulf Coast

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SPECIFIED FINANCIAL MEASURES
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS Accounting Standards including Operating Margin, Operating Margin by asset, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Realized Sales Price, Conventional, Offshore and Asia Pacific Per-Unit Operating Expenses, Netbacks (including the total Netback per BOE), Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture.
These measures may not be comparable to similar measures presented by other issuers. These measures are described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation, or as a substitute for, measures prepared in accordance with IFRS Accounting Standards. The definition and reconciliation, if applicable, of each specified financial measure is presented in this Advisory and may also be presented in the Operating and Financial Results section of this MD&A. Refer to the Specified Financial Measures Advisory of the relevant period’s MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow for prior period information from 2025 and 2024 that is not found below.
Non-GAAP Financial Measures and Non-GAAP Ratios
Operating Margin
Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for upstream or downstream operations are specified financial measures. These are used to provide a consistent measure of the cash-generating performance of our operations and assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending expenses, operating expenses, plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. The following tables provide a reconciliation to our interim Consolidated Financial Statements.
Operating Margin

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

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

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

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

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

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

(1)Found in Note 1 of the interim Consolidated Financial Statements.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations, in total and on a per-share basis. Adjusted Funds Flow is defined as cash from (used in) operating activities, excluding settlement of decommissioning liabilities and net change in operating non-cash working capital. Operating non-cash working capital is composed of accounts receivable and accrued revenues, income tax receivable, inventories (excluding non-cash inventory write-downs and reversals), accounts payable and accrued liabilities, and income tax payable. Adjusted Funds Flow Per Share – Basic is defined as Adjusted Funds Flow divided by the basic weighted average number of shares. Adjusted Funds Flow Per Share – Diluted is defined as Adjusted Funds Flow divided by the diluted weighted average number of shares.
Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities, excluding settlement of decommissioning liabilities and net change in operating non-cash working capital, minus capital investment.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 44

Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns and capital allocation framework. Excess Free Funds Flow is defined as Free Funds Flow minus base dividends paid on common shares, dividends paid on preferred shares, net purchases of common shares under the employee benefit plan, other uses of cash (including settlement of decommissioning liabilities and principal repayment of leases), and expenditures for acquisitions net of cash acquired, plus proceeds from, or payments related to, divestitures.

| Three Months Ended June 30, |  | Six Months Ended June 30, |  |
($ millions) | 2025 |  | 2024 |  | 2025 |  | 2024 |  |
Cash From (Used in) Operating Activities | 2,374 |  |  | 2,807 |  |  | 3,689 |  |  | 4,732 |  |  |
(Add) Deduct: |  |  |  |  |  |  |  |  |
Settlement of Decommissioning Liabilities | (68) |  |  | (48) |  |  | (104) |  |  | (96) |  |  |
Net Change in Non-Cash Working Capital | 923 |  |  | 494 |  |  | 62 |  |  | 225 |  |  |
Adjusted Funds Flow | 1,519 |  |  | 2,361 |  |  | 3,731 |  |  | 4,603 |  |  |
Capital Investment | 1,164 |  |  | 1,155 |  |  | 2,393 |  |  | 2,191 |  |  |
Free Funds Flow | 355 |  |  | 1,206 |  |  | 1,338 |  |  | 2,412 |  |  |
Add (Deduct): |  |  |  |  |  |  |  |  |
Base Dividends Paid on Common Shares | (364) |  |  | (334) |  |  | (691) |  |  | (596) |  |  |
Dividends Paid on Preferred Shares | (4) |  |  | (9) |  |  | (10) |  |  | (18) |  |  |
Purchase of Common Shares Under Employee Benefit Plan | (15) |  |  | — |  |  | (73) |  |  | — |  |  |
Settlement of Decommissioning Liabilities | (68) |  |  | (48) |  |  | (104) |  |  | (96) |  |  |
Principal Repayment of Leases | (94) |  |  | (75) |  |  | (177) |  |  | (145) |  |  |
Acquisitions, Net of Cash Acquired | (129) |  |  | (5) |  |  | (229) |  |  | (15) |  |  |
Proceeds From Divestitures | 13 |  |  | — |  |  | 13 |  |  | 25 |  |  |
Excess Free Funds Flow | (306) |  |  | 735 |  |  | 67 |  |  | 1,567 |  |  |

Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture
Gross Margin and Adjusted Gross Margin are non-GAAP financial measures that are used to evaluate the performance of our downstream operations. We define Gross Margin as revenues less purchased product and Adjusted Gross Margin as revenues less purchased product, excluding the impact of inventory holding gains or losses.
Inventory holding gains or losses reflects the difference between the cost of volumes produced at current-period costs, which is an indication of current market conditions, and the cost of volumes produced under the FIFO or weighted average cost basis as required by IFRS Accounting Standards, which generally reflects the market conditions at the time feedstock was purchased. The purchase and sale of inventories creates a timing difference that could be anywhere from several weeks to several months. This measure is an estimate of the impact of current-period costs to FIFO or weighted average cost, and assumes that all opening volumes are sold in the current period. Cenovus uses inventory holding gains or losses to analyze the performance of our assets and increase comparability with refining peers.
Adjusted Refining Margin and Adjusted Market Capture contain non-GAAP financial measures. Adjusted Refining Margin is used to evaluate our downstream operations after adjusting for inventory holding gains or losses. Adjusted Market Capture is used in our U.S. Refining segment to provide an indication of margin captured relative to what was available in the market based on widely-used benchmarks. These measures are useful to consistently measure the performance of our downstream operations.
We define Adjusted Refining Margin as Adjusted Gross Margin divided by total processed inputs and Adjusted Market Capture as Adjusted Refining Margin divided by the weighted average 3-2-1 market benchmark crack, net of RINs, expressed as a percentage. The weighted average crack spread, net of RINs, is calculated on Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.
We previously disclosed Refining Margin and Market Capture, which did not exclude the effect of inventory holding gains or losses. As of March 31, 2025, we have added Adjusted Gross Margin, and replaced our definitions of Refining Margin and Market Capture to exclude the impact of inventory holding gains or losses. We believe these changes provide more comparability and accuracy when measuring the performance of our downstream operations.
Comparative period information has been provided below for these new metrics.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 45

Canadian Refining

| Three Months Ended June 30, 2025 |  |  |  |
($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2) |  |  |  |
Revenues | 1,211 |  | 77 |  | 1,288 |  |  |  |
Purchased Product | 983 |  | 57 |  | 1,040 |  |  |  |
Gross Margin | 228 |  | 20 |  | 248 |  |  |  |
Add (Deduct): |  |  |  |  |  |  |  |  |
Inventory Holding (Gain) Loss | (12) |  | — |  | (12) |  |  |  |
Adjusted Gross Margin | 216 |  | 20 |  | 236 |  |  |  |
Total Processed Inputs (Mbbls/d) | 120.7 |  |  |  |  |  |  |  |
Adjusted Refining Margin ($/bbl) | 19.64 |  |  |  |  |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

| Three Months Ended June 30, 2024
($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2)
Revenues | 1,065 |  | 70 |  | 1,135
Purchased Product | 930 |  | 45 |  | 975
Gross Margin | 135 |  | 25 |  | 160
Add (Deduct): |  |  |  |  |
Inventory Holding (Gain) Loss | 5 |  | — |  | 5
Adjusted Gross Margin | 140 |  | 25 |  | 165
Total Processed Inputs (Mbbls/d) | 58.9 |  |  |  |
Adjusted Refining Margin ($/bbl) | 26.23 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

|  |  |  |  | Six Months Ended June 30, 2025
($ millions, except where indicated) |  |  |  |  | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2)
Revenues |  |  |  |  | 2,432 |  | 138 |  | 2,570
Purchased Product |  |  |  |  | 2,020 |  | 96 |  | 2,116
Gross Margin |  |  |  |  | 412 |  | 42 |  | 454
Add (Deduct): |  |  |  |  |  |  |  |  |
Inventory Holding (Gain) Loss |  |  |  |  | (9) |  | — |  | (9)
Adjusted Gross Margin |  |  |  |  | 403 |  | 42 |  | 445
Total Processed Inputs (Mbbls/d) |  |  |  |  | 120.1 |  |  |  |
Adjusted Refining Margin ($/bbl) |  |  |  |  | 18.50 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 46

| Six Months Ended June 30, 2024
($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2)
Revenues | 2,314 |  | 153 |  | 2,467
Purchased Product | 1,954 |  | 108 |  | 2,062
Gross Margin | 360 |  | 45 |  | 405
Add (Deduct): |  |  |  |  |
Inventory Holding (Gain) Loss | (19) |  | 1 |  | (18)
Adjusted Gross Margin | 341 |  | 46 |  | 387
Total Processed Inputs (Mbbls/d) | 83.8 |  |  |  |
Adjusted Refining Margin ($/bbl) | 22.34 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

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

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

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

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

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

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

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

| Three Months Ended June 30, |  | Six Months Ended June 30, |
($ millions, except where indicated) | 2025 |  | 2024 |  | 2025 |  | 2024 |
Revenues (1) | 6,455 |  |  | 7,615 |  |  | 12,878 |  |  | 14,516 |  |
Purchased Product (1) | 5,838 |  |  | 6,821 |  |  | 11,844 |  |  | 12,619 |  |
Gross Margin | 617 |  |  | 794 |  |  | 1,034 |  |  | 1,897 |  |
Add (Deduct): |  |  |  |  |  |  |  |
Inventory Holding (Gain) Loss | 62 |  |  | (83) |  |  | 85 |  |  | (277) |  |
Adjusted Gross Margin | 679 |  |  | 711 |  |  | 1,119 |  |  | 1,620 |  |
Total Processed Inputs (Mbbls/d) | 594.2 |  |  | 594.0 |  |  | 587.6 |  |  | 584.5 |  |
Adjusted Refining Margin ($/bbl) | 12.57 |  |  | 13.15 |  |  | 10.53 |  |  | 15.23 |  |
Operable Capacity (Mbbls/d) | 612.3 |  |  | 612.3 |  |  | 612.3 |  |  | 612.3 |  |
Operable Capacity by Regional Benchmark (percent) |  |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread Weighting | 81 |  |  | 81 |  |  | 81 |  |  | 81 |  |
Group 3 3-2-1 Crack Spread Weighting | 19 |  |  | 19 |  |  | 19 |  |  | 19 |  |
Benchmark Prices and Exchange Rate |  |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread (US$/bbl) | 21.64 |  |  | 18.76 |  |  | 17.66 |  |  | 18.10 |  |
Group 3 3-2-1 Crack Spread (US$/bbl) | 23.07 |  |  | 18.13 |  |  | 19.77 |  |  | 17.82 |  |
RINs (US$/bbl) | 6.12 |  |  | 3.39 |  |  | 5.44 |  |  | 3.53 |  |
US$ per C$1 – Average | 0.723 |  |  | 0.731 |  |  | 0.710 |  |  | 0.736 |  |
Weighted Average Crack Spread, Net of RINs ($/bbl) | 21.86 |  |  | 20.86 |  |  | 17.79 |  |  | 19.72 |  |
Adjusted Market Capture (percent) | 58 |  |  | 63 |  |  | 59 |  |  | 77 |  |

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

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 48

| Three Months Ended |  | Twelve Months Ended
($ millions, except where indicated) | December 31, 2024 |  | September 30, 2024 |  |  |  | December 31, 2024
Revenues (1) | 6,574 |  |  | 7,218 |  |  |  |  | 28,308 |
Purchased Product (1) | 6,296 |  |  | 6,854 |  |  |  |  | 25,769 |
Gross Margin | 278 |  |  | 364 |  |  |  |  | 2,539 |
Add (Deduct): |  |  |  |  |  |  |
Inventory Holding (Gain) Loss | 45 |  |  | 209 |  |  |  |  | (23) |
Adjusted Gross Margin | 323 |  |  | 573 |  |  |  |  | 2,516 |
Total Processed Inputs (Mbbls/d) | 588.4 |  |  | 568.0 |  |  |  |  | 581.4 |
Adjusted Refining Margin ($/bbl) | 5.98 |  |  | 10.97 |  |  |  |  | 11.83 |
Operable Capacity (Mbbls/d) | 612.3 |  |  | 612.3 |  |  |  |  | 612.3 |
Operable Capacity by Regional Benchmark (percent) |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread Weighting | 81 |  |  | 81 |  |  |  |  | 81 |
Group 3 3-2-1 Crack Spread Weighting | 19 |  |  | 19 |  |  |  |  | 19 |
Benchmark Prices and Exchange Rate |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread (US$/bbl) | 12.12 |  |  | 18.62 |  |  |  |  | 16.74 |
Group 3 3-2-1 Crack Spread (US$/bbl) | 12.66 |  |  | 18.95 |  |  |  |  | 16.81 |
RINs (US$/bbl) | 4.02 |  |  | 3.89 |  |  |  |  | 3.74 |
US$ per C$1 – Average | 0.715 |  |  | 0.733 |  |  |  |  | 0.730 |
Weighted Average Crack Spread, Net of RINs ($/bbl) | 11.47 |  |  | 20.18 |  |  |  |  | 17.82 |
Adjusted Market Capture (percent) | 52 |  |  | 54 |  |  |  |  | 67 |

(1)Comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.
Netback Reconciliations and Realized Sales Price
Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. Our Netback calculation is substantially aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netback is defined as gross sales less royalties, transportation and blending, and operating expenses. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold and exclude risk management activities. Condensate or butane (diluent) is blended with crude oil to transport it to market. Netback per barrel of oil equivalent contains a non-GAAP measure. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Per-unit measures are divided by sales volumes.
Realized Sales Price contains a non-GAAP measure. It includes our gross sales, purchased diluent costs and profit from optimization activities, such as cogeneration, third-party processing and trading. Conventional, Offshore and Asia Pacific Per-Unit Operating Expenses contain non-GAAP measures. As of March 31, 2025, modifications were made to our Conventional Netback to include our 30 percent equity interest in the Duvernay joint venture. These modifications resulted in minor adjustments that are captured in the netback calculation on a prospective basis. Offshore and Asia Pacific operating expenses, as used in the basis of our Netback calculations, reflect our 40 percent equity interest in the HCML joint venture. The Duvernay and HCML joint ventures are accounted for using the equity method in the interim Consolidated Financial Statements.
The following tables provide a reconciliation of Netback to Operating Margin found in our interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 49

Oil Sands

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

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

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
(2)Includes bitumen and heavy oil.
(3)Other includes construction, transportation and blending.
(4)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

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

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

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

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

(1)Includes bitumen and heavy oil.
(2)Other includes construction, transportation and blending.
(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

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

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

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
(2)Includes bitumen and heavy oil.
(3)Other includes construction, transportation and blending.
(4)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 51

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

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

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
(2)Includes bitumen and heavy oil.
(3)Other includes construction, transportation and blending.
(4)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
Conventional

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

(1)For the three months ended June 30, 2025, reported netbacks are inclusive of revenues and expenses related to the Duvernay joint venture.
(2)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.
(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 52

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

(1)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.
(2)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

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

(1)For the six months ended June 30, 2025, reported netbacks are inclusive of revenues and expenses related to the Duvernay joint venture.
(2)Other includes the reclassification of costs primarily related to third-party cogeneration, processing and transportation.
(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

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

(1)Other includes the reclassification of costs primarily related to third-party cogeneration, processing and transportation.
(2)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 53

Offshore

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

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

(1)Revenues and expenses related to the HCML joint venture.
(2)Primarily related to Offshore project expenses.
(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

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

(1)Revenues and expenses related to the HCML joint venture.
(2)Primarily related to Offshore project expenses.
(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.

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

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

(1)Revenues and expenses related to the HCML joint venture.
(2)Primarily related to Offshore project expenses.
(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
Upstream Sales Volumes (1)
The following table provides the sales volumes used to calculate Netback:

| Three Months Ended June 30, |  | Six Months Ended June 30,
(MBOE/d) | 2025 |  | 2024 |  | 2025 |  | 2024
Oil Sands (2) |  |  |  |  |  |  |
Foster Creek | 179.8 |  |  | 185.4 |  |  | 199.1 |  |  | 189.7 |
Christina Lake | 212.2 |  |  | 218.1 |  |  | 225.8 |  |  | 230.1 |
Sunrise | 49.8 |  |  | 51.0 |  |  | 49.6 |  |  | 46.6 |
Lloydminster | 124.5 |  |  | 130.0 |  |  | 126.3 |  |  | 129.2 |
Total Oil Sands | 566.3 |  |  | 584.5 |  |  | 600.8 |  |  | 595.6 |
Conventional (3) | 119.8 |  |  | 123.1 |  |  | 121.8 |  |  | 121.9 |
Offshore |  |  |  |  |  |  |
Atlantic | 7.9 |  |  | 14.8 |  |  | 11.8 |  |  | 9.4 |
Asia Pacific |  |  |  |  |  |  |
China | 37.9 |  |  | 43.5 |  |  | 39.8 |  |  | 43.6 |
Indonesia (4) | 15.9 |  |  | 14.3 |  |  | 15.6 |  |  | 14.2 |
Total Asia Pacific | 53.8 |  |  | 57.8 |  |  | 55.4 |  |  | 57.8 |
Total Offshore | 61.7 |  |  | 72.6 |  |  | 67.2 |  |  | 67.2 |

(1)Sales volumes exclude the impact of purchased condensate.
(2)Includes bitumen and heavy crude oil sales.
(3)For the three and six months ended June 30, 2025, reported sales volumes reflect Cenovus’s 30 percent equity interest in the Duvernay joint venture.
(4)Reported sales volumes reflect Cenovus’s 40 percent equity interest in the HCML joint venture.
Other Specified Financial Measures
Per-Unit Operating Expenses
Per-unit operating expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. Our upstream per-unit operating expenses are defined as total operating expenses divided by sales volumes and are part of our Netback calculation, which can be found above.
We define Canadian Refining per-unit operating expenses as total operating expenses from the Upgrader, the Lloydminster Refinery and the commercial fuels business, divided by total processed inputs. We define U.S. Refining per-unit operating expenses as operating expenses divided by total processed inputs.
Per-Unit Transportation Expenses
Per-unit transportation expenses are specified financial measures used to measure transportation expenses on a per-unit basis in our upstream segments. We define per-unit transportation expenses as the total transportation expenses divided by sales volumes. Our upstream per-unit transportation expenses are part of the transportation and blending line in our Netback calculation, which can be found above.

Cenovus Energy Inc. – Q2 2025 Management's Discussion and Analysis | 55

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

PRIOR PERIOD REVISIONS

In December 2024, it was identified that certain transactions in the U.S. Refining segment were reported on a gross basis in revenues and purchased product rather than on a net basis. As a result, revenues and purchased product were overstated for the nine months ended September 30, 2024. The prior periods were revised to reflect the change. There was no impact on net earnings (loss), segment income (loss), cash flows or financial position.
The following tables reconcile the amounts previously reported in the Consolidated Statements of Comprehensive Income (Loss) and segmented disclosures to the corresponding revised amounts:

| U.S. Refining Segment |  | Consolidated
For the three months ended June 30, 2024 | Previously Reported |  | Revisions |  | Revised Balance |  | Previously Reported |  | Revisions |  | Revised Balance
Revenues | 7,918 |  |  | (303) |  |  | 7,615 |  | 14,885 |  |  | (303) |  |  | 14,582
Purchased Product | 7,124 |  |  | (303) |  |  | 6,821 |  |  | 7,184 |  |  | (303) |  |  | 6,881 |
Transportation and Blending | — |  |  | — |  |  | — |  |  | 2,865 |  |  | — |  |  | 2,865 |
Purchased Product, Transportation and Blending | 7,124 |  |  | (303) |  |  | 6,821 |  |  | 10,049 |  |  | (303) |  |  | 9,746 |
| 794 |  |  | — |  |  | 794 |  |  | 4,836 |  |  | — |  |  | 4,836 |

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

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

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