EX-99.2 3 a2024managementsdiscussion.htm EX-99.2
Exhibit 99.2
Cenovus Energy Inc.
Management’s Discussion and Analysis (unaudited)
For the Year Ended December 31, 2024
(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the year ended December 31, 2024

OVERVIEW OF CENOVUS |  | 3
YEAR IN REVIEW |  | 3
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 |  | 28
CANADIAN REFINING |  | 28
U.S. REFINING |  | 29
CORPORATE AND ELIMINATIONS |  | 32
QUARTERLY RESULTS |  | 34
OIL AND GAS RESERVES |  | 37
LIQUIDITY AND CAPITAL RESOURCES |  | 38
RISK MANAGEMENT AND RISK FACTORS |  | 43
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES |  | 62
CONTROL ENVIRONMENT |  | 65
ADVISORY |  | 66
ABBREVIATIONS AND DEFINITIONS |  | 69
SPECIFIED FINANCIAL MEASURES |  | 70
PRIOR PERIOD REVISIONS |  | 81

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, joint arrangements, and partnership interests held directly or indirectly by, Cenovus Energy Inc.) dated February 19, 2025, should be read in conjunction with our December 31, 2024 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”). All of the information and statements contained in this MD&A are made as at February 19, 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 February 19, 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.
Cenovus holds equity ownership interests in a number of joint ventures, as classified under IFRS Accounting Standards, that are accounted for using the equity method in our Consolidated Financial Statements. Unless otherwise indicated, operational results of these joint ventures are not reflected in this MD&A. For further information, see the Advisory section of this MD&A.
Basis of Presentation
This MD&A and the Consolidated Financial Statements were prepared in Canadian dollars (which includes references to “dollar” or “$”), except where another currency is indicated, and in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”). Production volumes are presented on a before royalties basis. Refer to the Abbreviations and Definitions section for commonly used oil and gas terms.

Cenovus Energy Inc. – 2024 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.
For a description of our business segments see the Reportable Segments section of this MD&A.
Our Strategy
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five strategic objectives include: delivering top-tier safety performance and sustainability leadership; maximizing value through competitive cost structures and optimizing margins; a focus on financial discipline, including maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle; and absolute and per share free funds flow growth.
On December 12, 2024, we released our 2025 corporate guidance which focused on disciplined capital allocation in support of increasing shareholder returns over time. We will continue to be focused on controlling costs, improving the profitability of our strategic downstream business and optimizing our advantaged portfolio to deliver value for our shareholders. For further details, see the Outlook section of this MD&A and our 2025 corporate guidance dated December 11, 2024, available on our website at cenovus.com.

YEAR IN REVIEW

Overall, our 2024 results reflect strong operational performance in the upstream business, steady performance in our Canadian Refining business and improving performance in the U.S. Refining business. Constructive crude oil prices, including the narrowing of the light-heavy price differential, benefited our upstream financial results while declining market crack spreads along with the narrowing of the WTI-WCS and upgrading differentials had a significant impact on our downstream Operating Margin. In addition, we:
•Delivered safe and reliable upstream performance. Upstream production averaged 797.2 thousand BOE per day, compared with 778.7 thousand BOE per day in 2023, primarily driven by strong performance from our Oil Sands assets. Oil Sands production averaged 610.7 thousand BOE per day, our highest-ever annual production, compared with 595.4 thousand BOE per day in 2023. The increase in production is attributed to successful results from our redevelopment, sustaining, growth and optimization programs.
•Achieved Offshore milestones. We progressed the West White Rose project and are on track to deliver first oil in 2026. The project is approximately 88 percent complete and mechanical completion of the topsides and concrete gravity structure occurred in the fourth quarter. Refit work on the SeaRose floating production, storage and offloading (“FPSO”) vessel was completed and the vessel returned to the field in November. The SeaRose FPSO is on station and reconnected to the White Rose field. Production is expected to resume late February 2025.
•Advanced our Oil Sands growth projects. We achieved significant milestones on our major upstream growth projects including mechanical completion of the Narrows Lake pipeline to Christina Lake, bringing three well pads online as part of the Sunrise growth program and progressing construction of the Foster Creek optimization project, which was approximately 64 percent complete as at December 31, 2024. At our Lloydminster conventional heavy oil assets, we continue to progress our planned drilling program.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 3

•Improved U.S. Refining throughput and refined product production. Average crude oil unit throughput (or “throughput”) increased 96.7 thousand barrels per day compared with 2023, to 556.4 thousand barrels per day in 2024. Refined product production averaged 590.0 thousand barrels per day, an increase of 105.0 thousand barrels per day from 2023. The increases in throughput and refined product production were mainly driven by a full year of production at the Toledo and Superior refineries combined with improved reliability across our U.S. Refining operations.
•Safely completed significant turnarounds. In the Canadian Refining segment, we completed the largest turnaround in the asset’s history at the Lloydminster Upgrader (“Upgrader”) that ran from early May until early July. In the U.S. Refining segment, we completed a significant turnaround at the Lima Refinery as well as a turnaround at our non-operated Borger Refinery. In our upstream operations, we completed turnarounds at Christina Lake and at certain Conventional assets.
•Generated cash from operating activities of $9.2 billion. Cash from operating activities increased by $1.8 billion compared with 2023. Adjusted Funds Flow was $8.2 billion, a decrease of $639 million compared with 2023, reflecting weaker market crack spreads that impacted our downstream results, partially offset by strong upstream performance due to higher realized pricing and increased sales volumes. The Chicago 3-2-1 crack spread declined 31 percent to US$16.74 per barrel compared with 2023.
•Increased our target returns to shareholders. On achieving our Net Debt target, in the third quarter we increased target returns to shareholders, stewarding to 100 percent of Excess Free Funds Flow over time. In the year, we returned $3.2 billion to common and preferred shareholders, comprising the purchase of 55.9 million common shares for $1.4 billion through our normal course issuer bid (“NCIB”), $1.5 billion through common share base and variable dividends, $45 million through preferred share dividends and the redemption of all 10.0 million of the Company’s series 3 preferred shares at a price of $25.00 per share, for a total of $250 million.
•Raised our common share base dividend. Beginning in the second quarter, the Board approved a 29 percent increase in the base dividend to $0.720 per common share annually. On February 19, 2025, the Board declared a first quarter base dividend of $0.180 per common share.
•Upgraded credit ratings. We achieved our mid-BBB credit ratings target with all agencies, following S&P Global’s upgrade of Cenovus to BBB with a Stable outlook on March 18, 2024. This upgrade is a reflection of our debt reduction, financial policy track record and operational momentum.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 4

Summary of Annual Results

($ millions, except where indicated) |  | 2024 |  | 2023 |  | 2022
Upstream Production Volumes (1) (MBOE/d) |  | 797.2 |  |  | 778.7 |  |  | 786.2 |
Downstream Total Processed Inputs (2) (3) (Mbbls/d) |  | 678.0 |  |  | 586.8 |  |  | 513.0 |
Crude Oil Unit Throughput (2) (Mbbls/d) |  | 646.9 |  |  | 560.4 |  |  | 493.7 |
Downstream Production Volumes (Mbbls/d) |  | 693.1 |  |  | 599.2 |  |  | 525.1 |
Revenues |  | 54,277 |  |  | 52,204 |  |  | 66,897 |
Operating Margin (4) |  | 10,809 |  |  | 11,022 |  |  | 14,263 |
Operating Margin – Upstream (5) |  | 11,121 |  |  | 9,870 |  |  | 11,824 |
Operating Margin – Downstream (5) |  | (312) |  |  | 1,152 |  |  | 2,439 |
Cash From (Used In) Operating Activities |  | 9,235 |  |  | 7,388 |  |  | 11,403 |
Adjusted Funds Flow (4) |  | 8,164 |  |  | 8,803 |  |  | 10,978 |
Per Share – Basic (4) ($) |  | 4.41 |  |  | 4.64 |  |  | 5.63 |
Per Share – Diluted (4) ($) |  | 4.38 |  |  | 4.54 |  |  | 5.47 |
Capital Investment |  | 5,015 |  |  | 4,298 |  |  | 3,708 |
Free Funds Flow (4) |  | 3,149 |  |  | 4,505 |  |  | 7,270 |
Net Earnings (Loss) |  | 3,142 |  |  | 4,109 |  |  | 6,450 |
Per Share – Basic ($) |  | 1.68 |  |  | 2.15 |  |  | 3.29 |
Per Share – Diluted ($) |  | 1.67 |  |  | 2.09 |  |  | 3.20 |
Total Assets |  | 56,539 |  |  | 53,915 |  |  | 55,869 |
Total Long-Term Liabilities (4) |  | 19,408 |  |  | 18,993 |  |  | 20,259 |
Long-Term Debt, Including Current Portion |  | 7,534 |  |  | 7,108 |  |  | 8,691 |
Net Debt |  | 4,614 |  |  | 5,060 |  |  | 4,282 |
Cash Returns to Common and Preferred Shareholders |  | 3,246 |  |  | 2,798 |  |  | 3,457 |
Common Shares – Base Dividends |  | 1,255 |  |  | 990 |  |  | 682 |
Base Dividends Per Common Share ($) |  | 0.680 |  |  | 0.525 |  |  | 0.350 |
Common Shares – Variable Dividends |  | 251 |  |  | — |  |  | 219 |
Variable Dividends Per Common Share ($) |  | 0.135 |  |  | — |  |  | 0.114 |
Purchase of Common Shares Under NCIB |  | 1,445 |  |  | 1,061 |  |  | 2,530 |
Payment for Purchase of Warrants |  | — |  |  | 711 |  |  | — |
Dividends Paid on Preferred Shares |  | 45 |  |  | 36 |  |  | 26 |
Preferred Share Redemption |  | 250 |  |  | — |  |  | — |

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

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 5

OPERATING AND FINANCIAL RESULTS

Selected Operating and Financial Results — Upstream

|  |  | Year Ended December 31, |  |  |  |
|  |  |  |  |  |  |  |  | Percent Change |  |  |  |  |  |
|  |  |  |  |  | 2024 |  |  | 2023 |  |  |
Production Volumes by Segment (1) (MBOE/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  |  |  |  |  |  | 610.7 |  | 3 |  |  | 595.4 |  |  |  |
Conventional |  |  |  |  |  |  | 119.9 |  | — |  |  | 119.9 |  |  |  |
Offshore |  |  |  |  |  |  | 66.6 |  | 5 |  |  | 63.4 |  |  |  |
Total Production Volumes |  |  |  |  |  |  | 797.2 |  | 2 |  |  | 778.7 |  |  |  |
Production Volumes by Product (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bitumen (Mbbls/d) |  |  |  |  |  |  | 591.3 |  | 3 |  |  | 576.7 |  |  |  |
Heavy Crude Oil (Mbbls/d) |  |  |  |  |  |  | 17.6 |  | 5 |  |  | 16.7 |  |  |  |
Light Crude Oil (Mbbls/d) |  |  |  |  |  |  | 12.9 |  | (9) |  |  | 14.1 |  |  |  |
NGLs (Mbbls/d) |  |  |  |  |  |  | 32.0 |  | (2) |  |  | 32.5 |  |  |  |
Conventional Natural Gas (MMcf/d) |  |  |  |  |  |  | 860.2 |  | 3 |  |  | 832.6 |  |  |  |
Total Production Volumes (MBOE/d) |  |  |  |  |  |  | 797.2 |  | 2 |  |  | 778.7 |  |  |  |
Per-Unit Operating Expenses by Segment (2) ($/BOE) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  |  |  |  |  |  | 11.40 |  | (9) |  |  | 12.54 |  |  |  |
Conventional |  |  |  |  |  |  | 11.99 |  | (8) |  |  | 13.02 |  |  |  |
Offshore (3) |  |  |  |  |  |  | 19.27 |  | 12 |  |  | 17.20 |  |  |  |
Oil and Gas Reserves (MMBOE) (4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total Proved |  |  |  |  |  |  | 5,664 |  | (3) |  |  | 5,866 |  |  |  |
Probable |  |  |  |  |  |  | 2,793 |  | (2) |  |  | 2,836 |  |  |  |
Total Proved Plus Probable |  |  |  |  |  |  | 8,457 |  | (3) |  |  | 8,702 |  |  |  |

(1)Refer to the Oil Sands, Conventional or Offshore Reportable Segments section of this MD&A for a summary of production by product type by segment. Includes Cenovus’s 40 percent equity interest in Husky-CNOOC Madura Ltd. (“HCML”) joint venture, which is accounted for using the equity method in the Consolidated Financial Statements.
(2)Specified 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. Offshore Per-Unit Operating Expenses reflect Cenovus’s 40 percent equity interest in the HCML joint venture. Operating expenses for the Offshore segment, excluding Indonesia, for the year ended December 31, 2024, was $423 million (2023 – $384 million).
(4)Includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay Energy Corporation (“Duvernay”) joint venture and Cenovus’s 40 percent equity interest in the HCML joint venture.
Production
Total upstream production increased in 2024 compared with 2023 due to:
•Successful results from our redevelopment, sustaining, growth and optimization programs in our Oil Sands segment.
•A full year of production from the Terra Nova FPSO resuming production in November 2023.
•Increased production in Indonesia from the MAC field which had first gas in the fourth quarter of 2023.
The increase year-over-year is also due to lower production in 2023 in China following the temporary unplanned outage from the disconnection of the umbilical by a third-party vessel in April 2023. The production increases in 2024 were partially offset by turnaround activities in the Oil Sands and Conventional segments, and the suspension of production at the White Rose field in December 2023 for the SeaRose asset life extension (“ALE”) project in the Atlantic region.
In our Conventional segment, production volumes were consistent year-over-year. Production increased due to less well downtime in 2024 compared with 2023, partially offset by the divestiture of non-core assets. Well downtime in 2024 related to planned turnaround activity, while 2023 downtime was primarily in response to wildfire activity. In the second half of 2024, production was impacted by the deferral of new well development in response to lower natural gas benchmark prices.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 6

Per-Unit Operating Expenses
For the year ended December 31, 2024, per-unit operating expenses decreased in the Oil Sands segment, compared with 2023, mainly due to lower fuel costs as a result of significant declines in natural gas pricing and increased sales volumes. Per-unit operating expenses decreased in the Conventional segment, compared with 2023, mainly due to lower processing and gathering costs, electricity costs and workover costs, partially offset by increased repairs and maintenance costs. Per-unit operating expenses increased in the Offshore segment, compared with 2023, primarily due to higher repairs and maintenance and vessel mooring costs related to the SeaRose ALE project, and higher repairs and maintenance costs at the Terra Nova field. Overall, the Company has managed inflationary pressures through the use of long-term contracts, working with vendors and managing the timing of purchases of long-lead items.
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), total proved reserves and total proved plus probable reserves as at December 31, 2024, were approximately 5.7 billion BOE and 8.5 billion BOE, respectively. Total proved reserves and total proved plus probable reserves each decreased three percent compared with 2023.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Selected Operating and Financial Results — Downstream

|  |  | Year Ended December 31, |  |  |  |
|  |  |  |  |  |  |  |  | Percent Change |  |  |  |  |  |
|  |  |  |  |  | 2024 |  |  | 2023 |  |  |
Crude Oil Unit Throughput by Segment (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canadian Refining |  |  |  |  |  |  | 90.5 |  | (10) |  |  | 100.7 |  |  |  |
U.S. Refining |  |  |  |  |  |  | 556.4 |  | 21 |  |  | 459.7 |  |  |  |
Total Crude Oil Unit Throughput |  |  |  |  |  |  | 646.9 |  | 15 |  |  | 560.4 |  |  |  |  |
Production Volumes by Product (1) (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gasoline |  |  |  |  |  |  | 280.5 |  | 21 |  |  | 231.2 |  |  |  |
Distillates (2) |  |  |  |  |  |  | 219.9 |  | 22 |  |  | 179.9 |  |  |  |
Synthetic Crude Oil |  |  |  |  |  |  | 41.0 |  | (14) |  |  | 47.6 |  |  |  |
Asphalt |  |  |  |  |  |  | 44.0 |  | 25 |  |  | 35.2 |  |  |  |
Ethanol |  |  |  |  |  |  | 4.8 |  | (4) |  |  | 5.0 |  |  |  |
Other |  |  |  |  |  |  | 102.9 |  | 3 |  |  | 100.3 |  |  |  |
Total Production Volumes |  |  |  |  |  |  | 693.1 |  | 16 |  |  | 599.2 |  |  |  |
Per-Unit Operating Expenses by Segment (3) (4) ($/bbl) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canadian Refining |  |  |  |  |  |  | 22.56 |  | 68 |  |  | 13.40 |  |  |  |
U.S. Refining |  |  |  |  |  |  | 12.99 |  | (11) |  |  | 14.63 |  |  |  |
Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3) ($/bbl) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canadian Refining |  |  |  |  |  |  | 15.38 |  | 16 |  |  | 13.29 |  |  |  |
U.S. Refining |  |  |  |  |  |  | 11.55 |  | (18) |  |  | 14.01 |  |  |  |

(1)Refer to the Canadian Refining and U.S. Refining Reportable Segments section of this MD&A for a summary of production by product by segment.
(2)Includes diesel and jet fuel.
(3)Specified financial measure. Per-unit metrics are calculated based on total processed inputs. See the Specified Financial Measures Advisory of this MD&A.
(4)Inclusive of turnaround costs. In the Canadian Refining segment, operating expenses represent expenses associated with the Lloydminster Upgrader, the Lloydminster Refinery and the commercial fuels business.
We safely completed two significant turnarounds, as well as a turnaround at the Borger Refinery, in our refining segments in 2024. In Canada, we completed a turnaround at the Upgrader, which was the largest in its history in scope and cost, that ran from early May to early July. In the U.S., we completed a significant turnaround at the Lima Refinery that ran from early September to late October.
In 2024, total downstream throughput and refined product production increased compared with 2023. Throughput and production increased due to realizing a full year of production at the Toledo and Superior refineries, combined with improved reliability at our operated and non-operated refineries. We acquired the Toledo Refinery on February 28, 2023 (the “Toledo Acquisition”) and the Superior Refinery ramped up throughout 2023. The increases were partially offset by reduced throughput and production during the turnarounds discussed above.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 7

In 2024, per-unit operating expenses, excluding turnaround costs, increased in the Canadian Refining segment compared with 2023, primarily due to reliability projects completed during the turnaround period. Per-unit operating expenses, excluding turnaround costs, in the U.S. Refining segment decreased year-over-year primarily due to the increase in total processed inputs.
Selected Consolidated Financial Results
Revenues
Revenues increased four percent compared with 2023. Upstream revenue increased seven percent compared with 2023, primarily due to the narrowing of the WTI-WCS and condensate-WCS differentials following the start-up of the Trans Mountain Pipeline expansion project (“TMX”) and increased sales volumes. Downstream revenues increased three percent compared with 2023, primarily due to higher sales volumes in the U.S. Refining segment, partially offset by lower refined product pricing.
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.

|  |  | Year Ended December 31, |  |
($ millions) |  |  |  |  | 2024 |  | 2023 |  |
Gross Sales |  |  |  |  |  |  |  |  |
External Sales |  |  |  |  | 57,726 |  |  | 55,474 |  |  |
Intersegment Sales |  |  |  |  | 8,970 |  |  | 8,234 |  |  |
|  |  |  |  | 66,696 |  |  | 63,708 |  |  |
Royalties |  |  |  |  | (3,449) |  |  | (3,270) |  |  |
Revenues |  |  |  |  | 63,247 |  |  | 60,438 |  |  |
Expenses |  |  |  |  |  |  |  |  |
Purchased Product |  |  |  |  | 33,926 |  |  | 31,425 |  |  |
Transportation and Blending |  |  |  |  | 11,331 |  |  | 11,088 |  |  |
Operating Expenses |  |  |  |  | 7,159 |  |  | 6,891 |  |  |
Realized (Gain) Loss on Risk Management Activities |  |  |  |  | 22 |  |  | 12 |  |  |
Operating Margin |  |  |  |  | 10,809 |  |  | 11,022 |  |  |

Operating Margin by Segment
Years Ended December 31, 2024 and 2023

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Operating Margin decreased compared with 2023. The increase in revenues, as discussed above, was more than offset by:
•Lower market crack spreads impacting our U.S. Refining segment and higher heavy crude oil costs affecting both of our refining segments.
•Higher operating expenses due to turnaround activity at the Upgrader, Lima Refinery and Christina Lake assets.
•Higher transportation expenses impacting our Oil Sands segment due to higher sales volumes exported to destinations outside of Alberta. This includes transportation expenses related to our use of TMX and increased pipeline transportation rates on shipments to U.S. destinations.
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.

|  |  | Year Ended December 31, |
($ millions) |  |  |  |  | 2024 |  | 2023 |  |
Cash From (Used in) Operating Activities |  |  |  |  | 9,235 |  |  | 7,388 |  |  |
(Add) Deduct: |  |  |  |  |  |  |  |  |
Settlement of Decommissioning Liabilities |  |  |  |  | (234) |  |  | (222) |  |  |
Net Change in Non-Cash Working Capital |  |  |  |  | 1,305 |  |  | (1,193) |  |  |
Adjusted Funds Flow |  |  |  |  | 8,164 |  |  | 8,803 |  |  |

Adjusted Funds Flow was lower in 2024, compared with 2023, primarily due to an increase in current tax expense, the decrease in Operating Margin and higher long-term incentive costs paid, partially offset by a realized foreign exchange gain in 2024, compared with a realized foreign exchange loss in 2023.
Cash from operating activities increased in 2024, compared with 2023, primarily due to a working capital release, which more than offset the decrease in Adjusted Funds Flow. The net change in non-cash working capital was primarily due to a source of cash in 2024 as accounts receivables decreased, and accounts payable and taxes payable increased, compared with a use of cash in 2023 mainly caused by an income tax liability from 2022 that was paid in the first quarter of 2023.
Net Earnings (Loss)
Net earnings in 2024 was $3.1 billion (2023 – $4.1 billion). The decrease was primarily due to foreign exchange losses, higher depreciation, depletion, amortization and exploration expense, lower Operating Margin, and higher general and administrative expense. The decrease was partially offset by gains on the divestiture of non-core assets in 2024.
Net Debt

As at ($ millions) | December 31, 2024 |  |  |  | December 31, 2023 |  |  |  |
Short-Term Borrowings | 173 |  |  |  |  | 179 |  |  |  |  |
Current Portion of Long-Term Debt | 192 |  |  |  |  | — |  |  |  |  |
Long-Term Portion of Long-Term Debt | 7,342 |  |  |  |  | 7,108 |  |  |  |  |
Total Debt | 7,707 |  |  |  |  | 7,287 |  |  |  |  |
Cash and Cash Equivalents | (3,093) |  |  |  |  | (2,227) |  |  |  |  |
Net Debt | 4,614 |  |  |  |  | 5,060 |  |  |  |  |

Long-term debt increased by $426 million from December 31, 2023, primarily due to an unrealized loss of $442 million resulting from the weakening of the Canadian dollar relative to the U.S. dollar, impacting the translation of our U.S. denominated debt. Net Debt decreased by $446 million from December 31, 2023, mainly due to cash from operating activities of $9.2 billion, partially offset by capital investment of $5.0 billion, cash returns to common and preferred shareholders of $3.2 billion and the increase in long-term debt discussed above. For further details, see the Liquidity and Capital Resources section of this MD&A.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 9

Capital Investment (1)

|  |  |  |  | Year Ended December 31, |  |
($ millions) |  |  |  |  |  | 2024 |  | 2023 |  |
Upstream |  |  |  |  |  |  |  |  |  |  |
Oil Sands |  |  |  |  |  |  | 2,714 |  |  | 2,382 |  |  |
Conventional |  |  |  |  |  |  | 421 |  |  | 452 |  |  |
Offshore |  |  |  |  |  |  | 1,145 |  |  | 642 |  |  |
Total Upstream |  |  |  |  |  |  | 4,280 |  |  | 3,476 |  |  |
Downstream |  |  |  |  |  |  |  |  |  |  |
Canadian Refining |  |  |  |  |  |  | 208 |  |  | 145 |  |  |
U.S. Refining |  |  |  |  |  |  | 488 |  |  | 602 |  |  |
Total Downstream |  |  |  |  |  |  | 696 |  |  | 747 |  |  |
Corporate and Eliminations |  |  |  |  |  |  | 39 |  |  | 75 |  |  |
Total Capital Investment |  |  |  |  |  |  | 5,015 |  |  | 4,298 |  |  |

(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets and capitalized interest. Excludes capital expenditures related to the Company’s joint ventures.
Capital investment in 2024 was mainly related to:
•Sustaining, redevelopment and optimization programs in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated winter program.
•The progression of the West White Rose project and the execution of the SeaRose ALE project.
•Sustaining activities at our operated Canadian and U.S. refining assets, and refining reliability projects at our non-operated refineries.
•Growth projects in our Oil Sands segment, including the mechanical completion of the Narrows Lake pipeline to Christina Lake, the optimization project at Foster Creek, the Sunrise growth program and the progression of the planned drilling program at our Lloydminster conventional heavy oil assets.
•Drilling, completion, tie-in and infrastructure projects in the Conventional segment.
Drilling Activity

| Net Stratigraphic Test Wells and Observation Wells |  | Net Production Wells (1)
| 2024 |  | 2023 |  | 2024 |  | 2023
Foster Creek | 85 |  |  | 87 |  |  | 22 |  |  | 44 |
Christina Lake | 61 |  |  | 53 |  |  | 23 |  |  | 27 |
Sunrise | 40 |  |  | 38 |  |  | 14 |  |  | 24 |
Lloydminster Thermal | 53 |  |  | 71 |  |  | 22 |  |  | 9 |
Lloydminster Conventional Heavy Oil | 19 |  |  | 3 |  |  | 49 |  |  | 34 |
Other | — |  |  | 3 |  |  | — |  |  | — |
| 258 |  |  | 255 |  |  | 130 |  |  | 138 |

(1)Steam-assisted gravity drainage (“SAGD”) 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 progress the evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions.

| 2024 |  | 2023
(net wells) | Drilled (1) |  | Completed |  | Tied-in |  | Drilled |  | Completed |  | Tied-in
Conventional | 36 |  |  | 31 |  |  | 31 |  |  | 38 |  |  | 37 |  |  | 41 |

(1)Includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay joint venture.
In the Offshore segment, we drilled and evaluated one exploration well in China (2023 – drilled and completed one (0.4 net) development well at the MAC field in Indonesia).

Cenovus Energy Inc. – 2024 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)

(Average US$/bbl, unless otherwise indicated) | 2024 |  | Percent Change |  | 2023 |  |  |  | Q4 2024 |  |  |  | Q3 2024 |  |  |  |  |  | Q4 2023 |
Dated Brent | 80.76 |  |  | (2) |  |  | 82.62 |  |  |  |  | 74.69 |  |  |  |  | 80.18 |  |  |  |  |  |  | 84.05 |  |
WTI | 75.72 |  |  | (2) |  |  | 77.62 |  |  |  |  | 70.27 |  |  |  |  | 75.09 |  |  |  |  |  |  | 78.32 |  |
Differential Dated Brent - WTI | 5.04 |  |  | 1 |  |  | 5.00 |  |  |  |  | 4.42 |  |  |  |  | 5.09 |  |  |  |  |  |  | 5.73 |  |
WCS at Hardisty | 60.97 |  |  | 3 |  |  | 58.97 |  |  |  |  | 57.71 |  |  |  |  | 61.54 |  |  |  |  |  |  | 56.43 |  |
Differential WTI - WCS at Hardisty | 14.75 |  |  | (21) |  |  | 18.65 |  |  |  |  | 12.56 |  |  |  |  | 13.55 |  |  |  |  |  |  | 21.89 |  |
WCS at Hardisty (C$/bbl) | 83.52 |  |  | 5 |  |  | 79.59 |  |  |  |  | 80.74 |  |  |  |  | 83.95 |  |  |  |  |  |  | 76.95 |  |
WCS at Nederland | 69.69 |  |  | — |  |  | 69.74 |  |  |  |  | 65.69 |  |  |  |  | 68.51 |  |  |  |  |  |  | 71.59 |  |
Differential WTI - WCS at Nederland | 6.03 |  |  | (23) |  |  | 7.88 |  |  |  |  | 4.58 |  |  |  |  | 6.58 |  |  |  |  |  |  | 6.73 |  |
Condensate (C5 at Edmonton) | 72.94 |  |  | (5) |  |  | 76.61 |  |  |  |  | 70.66 |  |  |  |  | 71.19 |  |  |  |  |  |  | 76.24 |  |
Differential Condensate - WTI Premium/(Discount) | (2.78) |  |  | 175 |  |  | (1.01) |  |  |  |  | 0.39 |  |  |  |  | (3.90) |  |  |  |  |  |  | (2.08) |  |
Differential Condensate - WCS at Hardisty Premium/ (Discount) | 11.97 |  |  | (32) |  |  | 17.64 |  |  |  |  | 12.95 |  |  |  |  | 9.65 |  |  |  |  |  |  | 19.81 |  |
Condensate (C$/bbl) | 99.92 |  |  | (3) |  |  | 103.43 |  |  |  |  | 98.84 |  |  |  |  | 97.10 |  |  |  |  |  |  | 103.90 |  |
Synthetic at Edmonton | 75.07 |  |  | (6) |  |  | 79.61 |  |  |  |  | 71.11 |  |  |  |  | 76.41 |  |  |  |  |  |  | 78.64 |  |
Differential Synthetic - WTI Premium/(Discount) | (0.65) |  |  | (133) |  |  | 1.99 |  |  |  |  | 0.84 |  |  |  |  | 1.32 |  |  |  |  |  |  | 0.32 |  |
Synthetic at Edmonton (C$/bbl) | 102.83 |  |  | (4) |  |  | 107.47 |  |  |  |  | 99.45 |  |  |  |  | 104.22 |  |  |  |  |  |  | 107.21 |  |
Refined Product Prices |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Chicago Regular Unleaded Gasoline (“RUL”) | 89.95 |  |  | (8) |  |  | 97.86 |  |  |  |  | 78.95 |  |  |  |  | 92.29 |  |  |  |  |  |  | 83.72 |  |
Chicago Ultra-low Sulphur Diesel (“ULSD”) | 97.47 |  |  | (11) |  |  | 109.70 |  |  |  |  | 89.28 |  |  |  |  | 96.55 |  |  |  |  |  |  | 107.24 |  |
Refining Benchmarks |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread (2) | 16.74 |  |  | (31) |  |  | 24.19 |  |  |  |  | 12.12 |  |  |  |  | 18.62 |  |  |  |  |  |  | 13.24 |  |
Group 3 3-2-1 Crack Spread (2) | 16.81 |  |  | (43) |  |  | 29.66 |  |  |  |  | 12.66 |  |  |  |  | 18.95 |  |  |  |  |  |  | 18.55 |  |
Renewable Identification Numbers (“RINs”) | 3.74 |  |  | (47) |  |  | 7.04 |  |  |  |  | 4.02 |  |  |  |  | 3.89 |  |  |  |  |  |  | 4.77 |  |
Upgrading Differential (3) (C$/bbl) | 19.21 |  |  | (30) |  |  | 27.55 |  |  |  |  | 18.64 |  |  |  |  | 20.26 |  |  |  |  |  |  | 29.97 |  |
Natural Gas Prices |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AECO (4) (C$/Mcf) | 1.46 |  |  | (45) |  |  | 2.64 |  |  |  |  | 1.48 |  |  |  |  | 0.69 |  |  |  |  |  |  | 2.30 |  |
NYMEX (5) (US$/Mcf) | 2.27 |  |  | (17) |  |  | 2.74 |  |  |  |  | 2.79 |  |  |  |  | 2.16 |  |  |  |  |  |  | 2.88 |  |
Foreign Exchange Rates |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
US$ per C$1 – Average | 0.730 |  |  | (1) |  |  | 0.741 |  |  |  |  | 0.715 |  |  |  |  | 0.733 |  |  |  |  |  |  | 0.734 |  |
US$ per C$1 – End of Period | 0.695 |  |  | (8) |  |  | 0.756 |  |  |  |  | 0.695 |  |  |  |  | 0.741 |  |  |  |  |  |  | 0.756 |  |
RMB per C$1 – Average | 5.255 |  |  | — |  |  | 5.247 |  |  |  |  | 5.142 |  |  |  |  | 5.255 |  |  |  |  |  |  | 5.304 |  |

(1)These benchmark prices are not our Realized Sales Prices and represent approximate values. For our average Realized Sales Prices and realized risk management results, refer to the Netback tables in the Upstream Reportable Segments section of this MD&A.
(2)The average 3-2-1 crack spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.
(3)The upgrading differential is the difference between synthetic crude oil at Edmonton and Lloydminster Blend crude oil at Hardisty. The upgrading differential does not precisely mirror the configuration and the product output of our refineries; 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 2024, crude oil benchmark prices, Brent and WTI decreased compared with 2023. Prices were higher in the first half of 2024, compared with the first half of 2023, as geopolitical events related to Russia and Ukraine, Israel and Gaza, Iran, the Red Sea, Venezuela and Guyana added to volatility and risk premiums, but had a limited impact on physical supply and demand in global oil markets. Weaker than expected global demand and potential unwinding of OPEC+ voluntary production cuts further weighed on prices in the second half of 2024, which was partially offset by low global inventories of crude. Global supply and demand were relatively balanced through 2024 as OPEC+ policy continued to support markets through the year as plans to unwind voluntary cuts were extended through the first quarter of 2025.

Cenovus Energy Inc. – 2024 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.
The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI differential in 2024 was relatively consistent compared with 2023.
WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude, and the cost of transport. The WTI-WCS differential at Hardisty narrowed in 2024, compared with 2023, due to the start-up of TMX increasing market access for WCS crude, the impact of Saudi Arabia’s voluntary production cuts, which are weighted towards medium and heavy crude, 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 2024, the WTI-WCS at Nederland differential narrowed compared with 2023, due to the continued voluntary production cuts from OPEC+ members, including Saudi Arabia.
In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
In 2024, synthetic crude oil at Edmonton was priced at a discount to WTI, compared with a premium to WTI in 2023. The weakness in pricing relative to 2023 was a function of deep discounts in the first quarter of 2024, due to high synthetic crude oil production in Alberta, supply of light crude being above pipeline capacity on light crude pipelines and limited local storage capacity.
Crude Oil Benchmark Prices (1)
(1)Forward pricing as at January 31, 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 2024, the average Edmonton condensate benchmark traded at a greater discount to WTI compared with 2023. Weakness was influenced by low light crude oil prices in the first quarter of 2024 in Alberta, as an oversupply of light crude exceeded pipeline takeaway capacity.

Cenovus Energy Inc. – 2024 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 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 2024, refined product prices declined compared with 2023, due to high global and regional supply of refined products as a result of incremental global refining capacity additions and U.S. refineries operating at high utilization rates for most of 2024. Refinery utilization in PADD 2 remained high throughout the fourth quarter of 2024, despite lower seasonal demand for gasoline, which resulted in the Chicago 3-2-1 crack spread weakening by US$1.00/bbl relative to the fourth quarter of 2023. Average cost of RINs were also lower in 2024 compared with 2023, due to a decline in biofuel feedstock costs and increased renewable diesel production.
North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices. The strength of refining market crack spreads in the U.S. Midwest and Midcontinent generally reflects the differential between Brent and WTI benchmark prices.
Our refining margins are affected by various other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the feedstock is valued on a first in, first out (“FIFO”) accounting basis. The 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 January 31, 2025.
Natural Gas Benchmarks
In 2024, average NYMEX and AECO natural gas prices decreased compared with 2023, due to high production, high inventory levels and mild weather in the U.S. and Western Canada. AECO prices weakened further relative to NYMEX natural gas due to limited Western Canadian takeaway capacity. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.
Foreign Exchange Benchmarks
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. dollar benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported revenue. In addition to our revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. Changes in foreign exchange rates also impact the translation of our U.S. and Asia Pacific operations.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 13

In 2024, on average, the Canadian dollar weakened relative to the U.S. dollar compared with 2023, positively impacting our reported revenues. The Canadian dollar weakened relative to the U.S. dollar as at December 31, 2024, compared with December 31, 2023, resulting in unrealized foreign exchange losses on the translation of our U.S. dollar debt.
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 2024, on average, the Canadian dollar was relatively consistent with the RMB compared with 2023.
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 December 31, 2024, the Bank of Canada’s Policy Interest Rate was 3.25 percent, a decrease from 5.00 percent on December 31, 2023. On January 29, 2025, the Bank of Canada reduced the overnight rate by 25 basis points to 3.00 percent due to the easing of inflation concerns and the threat of trade tariffs.

OUTLOOK

Commodity Price Outlook
Although discussions continue regarding a potential economic arrangement between the U.S. and Canada, there remains significant uncertainty over whether tariffs, surtaxes, or other restrictive trade measures or countermeasures will be implemented. Potential measures could include, among others, increased tariffs on Canadian energy exports, restrictions on cross-border supply chains, or additional regulatory barriers that could have a significant impact on the market for crude oil, NGLs, natural gas and refined petroleum products in Canada and internationally, and could result in, among other things, a high degree of both cost and price volatility, a relative weakening of the Canadian dollar and widening differentials. We continue to monitor these developments closely; however, these matters have introduced uncertainty and volatility in the market. The scope, impact and duration of any measures implemented remain uncertain at this time.
Global crude oil prices have trended lower in 2024, compared with 2023, as OPEC+ announced its intention to end production cuts that have supported prices. OPEC+ plans to gradually unwind voluntary cuts over 18 months starting April 2025. Non-OPEC+ supply growth, led by U.S. shale, has been robust and is expected to continue to grow in 2025, though slowing U.S. drilling activity since 2023 has softened the expectations for U.S. supply growth modestly. Demand growth has continued, but has been weaker than in 2023, due to lower than expected Chinese demand growth, which has also weighed on prices. Current geopolitical risks are causing volatility in global oil prices, with any escalation causing prices to rise and any de-escalation causing prices to settle. With planned production growth expected from OPEC+ due to the unwinding of production cuts, and high Middle East spare production capacity, geopolitical tensions are not impacting global oil prices as much as they would have in an under-supplied or more balanced global oil market.
Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers and government policy playing a large role in supply and demand dynamics.
OPEC+ policy continues to remain crucial to global oil supply and demand balances, and prices. In the U.S., Trump administration policies around tariffs, trade relations, global conflicts and domestic supply will be key considerations for energy prices. Global policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shift global trade patterns. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-OPEC+ supply growth, the potential for resumed crisis in Israel and Gaza if the ceasefire breaks down including any spread to a wider conflict, developments relating to conflicts involving Iran and attacks on vessels in the Red Sea, and tensions between Venezuela and Guyana.
In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession remain a risk to the pace of demand growth.
Refined product prices have declined in 2024 compared with 2023, as a result of incremental global capacity additions, reduced RIN prices, and U.S. refineries operating at very high utilization rates. Forward curves are showing signs of refined product prices strengthening in 2025.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 14

In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
•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 stays within Canadian crude oil export capacity. As expected, the start-up of TMX in 2024 is having a narrowing impact on WTI-WCS differentials.
•We expect refined product prices will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies continue to impact demand. Refined product prices and market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America and globally.
•NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and ample natural gas in storage, although the prospect of new LNG facilities in the U.S. coming into service or ramping up in the next 12 months could increase demand and support natural gas prices on NYMEX. Weather will continue to be a key driver of demand and impact prices.
•We expect the Canadian dollar to continue to be impacted by the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, Trump administration policies toward Canada-U.S. trade, crude oil prices and emerging macro-economic factors.
Most of our upstream crude oil and downstream refined product production is exposed to movements in the WTI crude oil price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane, and is used as crude oil feedstock at our downstream refining operations. Condensate extracted from our blended crude oil is sold back to our Oil Sands operations.
Our refining capacity is focused in the U.S. Midwest, along with smaller exposures in the USGC and Alberta, exposing Cenovus to market crack spreads in these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly.
Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our refining capacity, and to a lesser degree, in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differentials, which could be subject to transportation constraints.
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, improved reliability in our downstream business, maintaining and growing our competitive advantages in our Oil Sands business and execution on our growth projects. We will continue to maintain returns to shareholders and focus on cost and sustainability improvements.
Top-tier Safety Performance
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, and aim to be best-in-class operators for each of our major assets and businesses.
Downstream Competitiveness
A competitive, reliable downstream business is essential to our integrated business. It allows us to be agile in our response to fluctuating demand for refined products and serves as a natural partial hedge in times of widening location and heavy oil differentials.
We will continue to target improved reliability of our downstream assets, leveraging our upstream expertise to maximize the long-term profitability of our assets.
Oil Sands Business
Our Oil Sands business is the backbone of our company. Maintaining and growing our competitive advantages while operating safely and reliably is critical to our company.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 15

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 growth project. We plan to continue to execute these multi-year projects on time and on budget.
We made the decision to recalibrate work on the enterprise-wide IT systems upgrades to a more fit for purpose outcome. Certain components of the project, including the replacement of Cenovus’s enterprise resource planning systems, will be put on hold as a result of continuing to focus on controlling corporate costs. Work will continue on cyber security resilience and standardization of data governance to enhance efficiency and effectiveness of the Company’s systems.
Cost Leadership
We aim to maximize shareholder value through continued focus on low cost structures and margin optimization across our business. We are focused on reducing operating, capital and general and administrative costs, realizing the full value of our integrated strategy while making decisions that support long-term value for Cenovus.
Returns to Shareholders
Maintaining a strong balance sheet with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle is a key element of Cenovus’s capital allocation framework. We plan to steward Net Debt to $4.0 billion and return 100 percent of Excess Free Funds Flow to shareholders over time. For further details, see the Liquidity and Capital Resources section of this MD&A.
Sustainability
Sustainability is central to Cenovus’s culture. We have established ambitious targets in our five environmental, social and governance (“ESG”) focus areas, and we continue to advance work to support progress against these targets.
We continue to support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal and provincial governments that provide a sufficient level of fiscal support to progress large-scale carbon capture projects, while maintaining global competitiveness. It is critical that the federal and provincial governments provide support at a level consistent with what similar large-scale carbon capture projects are receiving globally to enable Canada to achieve its greenhouse gas (“GHG”) emissions goals.
Additional information on Cenovus’s performance in safety, Indigenous reconciliation, and inclusion and diversity is available in Cenovus’s 2023 Corporate Social Responsibility report on our website at cenovus.com.
2025 Corporate Guidance
Our corporate guidance dated December 11, 2024, is available on our website at cenovus.com.
Our 2025 corporate guidance for total capital investment is between $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 and growth capital.
Optimization and growth capital will be directed mainly toward:
•Installation and commissioning of the West White Rose project.
•Progressing the optimization and the enhanced sulphur recovery projects at Foster Creek.
•Drilling new well pads at Sunrise and development drilling at our conventional heavy oil business in the Lloydminster area.
•Initiatives in our downstream business to improve safety, maintenance and reliability.
The following table shows our corporate guidance for 2025:

| Capital Investment ($ millions) |  | Production (MBOE/d) |  | Crude Oil Unit Throughput (Mbbls/d)
Upstream |  |  |  |  |
Oil Sands | 2,700 - 2,800 |  | 615 - 635 |  |
Conventional | 350 - 400 |  | 125 - 135 |  |
Offshore | 900 - 1,000 |  | 65 - 75 |  |
Upstream Total | 3,950 - 4,200 |  | 805 - 845 |  |
Downstream | 650 - 750 |  |  |  | 650 - 685
Corporate and Eliminations | Up to 50 |  |  |  |

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 16

REPORTABLE SEGMENTS

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 HCML, which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia.
Downstream Segments
•Canadian Refining, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.
•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. 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 usa ge of crude oil, nat ural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.
UPSTREAM
Oil Sands
In 2024, we:
•Delivered safe and reliable operations, including the safe execution of a turnaround at Christina Lake which was completed ahead of schedule.
•Produced 610.7 thousand BOE per day, our highest-ever annual production (2023 – 595.4 thousand BOE per day).
•Delivered successful results from our redevelopment, sustaining, growth and optimization programs.
•Generated Operating Margin of $9.8 billion, an increase of $1.6 billion compared with 2023, due to higher average Realized Sales Prices, higher sales volumes and lower fuel operating costs.
•Earned a Netback of $44.88 per BOE (2023 – $38.10 per BOE).
•Invested capital of $2.7 billion for sustaining activities and growth projects. We mechanically completed the Narrows Lake pipeline to Christina Lake and brought three well pads online as part of the Sunrise growth program.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 17

Financial Results

($ millions) |  |  |  |  | 2024 |  | 2023 |  |
Gross Sales |  |  |  |  |  |  |  |  |
External Sales |  |  |  |  | 21,857 |  |  | 20,608 |  |  |
Intersegment Sales |  |  |  |  | 6,590 |  |  | 5,584 |  |  |
|  |  |  |  | 28,447 |  |  | 26,192 |  |  |
Royalties |  |  |  |  | (3,274) |  |  | (3,059) |  |  |
Revenues |  |  |  |  | 25,173 |  |  | 23,133 |  |  |
Expenses |  |  |  |  |  |  |  |  |
Purchased Product |  |  |  |  | 1,851 |  |  | 1,457 |  |  |
Transportation and Blending |  |  |  |  | 11,000 |  |  | 10,774 |  |  |
Operating |  |  |  |  | 2,511 |  |  | 2,716 |  |  |
Realized (Gain) Loss on Risk Management |  |  |  |  | 20 |  |  | 17 |  |  |
Operating Margin |  |  |  |  | 9,791 |  |  | 8,169 |  |  |
Unrealized (Gain) Loss on Risk Management |  |  |  |  | (16) |  |  | 15 |  |  |
Depreciation, Depletion and Amortization |  |  |  |  | 3,117 |  |  | 2,993 |  |  |
Exploration Expense |  |  |  |  | 2 |  |  | 19 |  |  |
(Income) Loss from Equity-Accounted Affiliates |  |  |  |  | (14) |  |  | 6 |  |  |
Segment Income (Loss) |  |  |  |  | 6,702 |  |  | 5,136 |  |  |

Operating Margin Variance
Year Ended December 31, 2024
(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.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 18

Operating Results

|  |  |  |  | 2024 |  | 2023 |  |
Total Sales Volumes (1) (MBOE/d) |  |  |  |  | 599.5 |  |  | 589.5 |  |  |
Realized Sales Price (2) ($/BOE) |  |  |  |  | 80.20 |  |  | 73.02 |  |  |
Crude Oil Production by Asset (Mbbls/d) |  |  |  |  |  |  |  |  |
Foster Creek |  |  |  |  | 196.0 |  |  | 186.3 |  |  |
Christina Lake |  |  |  |  | 234.2 |  |  | 237.4 |  |  |
Sunrise |  |  |  |  | 49.6 |  |  | 48.9 |  |  |
Lloydminster Thermal |  |  |  |  | 111.5 |  |  | 104.1 |  |  |
Lloydminster Conventional Heavy Oil |  |  |  |  | 17.6 |  |  | 16.7 |  |  |
Total Crude Oil Production (3) (Mbbls/d) |  |  |  |  | 608.9 |  |  | 593.4 |  |  |
Natural Gas (4) (MMcf/d) |  |  |  |  | 11.1 |  |  | 11.9 |  |  |
Total Production (MBOE/d) |  |  |  |  | 610.7 |  | 595.4 |  |
Effective Royalty Rate (5) (percent) |  |  |  |  |  |  |  |  |
Foster Creek |  |  |  |  | 24.0 |  |  | 25.1 |  |  |
Christina Lake |  |  |  |  | 27.3 |  |  | 29.5 |  |  |
Sunrise |  |  |  |  | 6.1 |  |  | 6.8 |  |  |
Lloydminster (6) |  |  |  |  | 11.7 |  |  | 9.5 |  |  |
Total Effective Royalty Rate |  |  |  |  | 21.0 |  |  | 21.9 |  |  |
Transportation and Blending Expense (7) ($/BOE) |  |  |  |  | 9.00 |  |  | 8.18 |  |  |
Operating Expense (7) ($/BOE) |  |  |  |  | 11.40 |  |  | 12.54 |  |  |
Per-Unit DD&A (7) ($/BOE) |  |  |  |  | 13.49 |  |  | 12.94 |  |  |

(1)Bitumen, heavy crude oil and natural gas.
(2)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(3)Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.
(4)Conventional natural gas product type.
(5)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(6)Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets.
(7)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Revenues
Gross sales increased in 2024 compared with 2023, due to increased Realized Sales Prices as a result of the narrowing of the WTI-WCS and condensate-WCS differentials following the startup of TMX, and increased sales volumes.
Price
Our bitumen and heavy oil production must be blended with condensate to reduce its viscosity in order to transport it to market through pipelines. Within our Netback calculations, our realized bitumen and heavy oil sales price excludes the impact of purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending increases relative to the price of blended crude oil or our blend ratio increases, our realized bitumen and heavy oil sales price decreases.
Our Realized Sales Price increased in 2024, compared with 2023, mainly due to narrower WTI-WCS and condensate-WCS differentials, driven by the start-up of TMX.
In 2024, approximately 33 percent (2023 – 25 percent) of our crude oil sales volumes were sold to destinations outside of Alberta and approximately 20 percent (2023 – 20 percent) of our Oil Sands crude oil sales volumes were sold to our Canadian and U.S. downstream operations.
Cenovus makes storage and transportation decisions to use our marketing and transportation infrastructure, including storage and pipeline assets, in order to optimize product mix, delivery points, transportation commitments and customer diversification. To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 19

Production Volumes
Oil Sands crude oil production increased in 2024 compared with 2023 due to:
•Less well downtime and successful results from our sustaining and optimization programs at Foster Creek.
•Successful results from our redevelopment and optimization programs at our Lloydminster assets.
•Positive results from our sustaining, redevelopment, growth and optimization programs at Sunrise.
The increase was partially offset by turnaround activity in September 2024 at Christina Lake.
Royalties
Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Saskatchewan.
Our Alberta oil sands royalty projects (Foster Creek, Christina Lake and Sunrise) are based on government prescribed pre- and post-payout royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.
Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.
Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales revenues less diluent costs and transportation costs. Net revenues are calculated as sales revenues less diluent costs, transportation costs, and allowed operating and capital costs.
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. For Crown royalties, the pre-payout calculation is based on one percent of product revenues and the post-payout calculation is based on 20 percent of operating margin. The freehold calculation is limited to post-payout projects and is based on an eight percent rate.
In 2024, Oil Sands royalties increased compared with 2023, primarily due to higher realized pricing and sales volumes. The Oil Sands effective royalty rate decreased slightly primarily due to annual adjustments on the end-of-period filings, partially offset by higher realized prices compared with 2023.
Expenses
Transportation and Blending
In 2024, blending expenses increased $6 million compared with 2023, due to higher sales volumes partially offset by lower condensate prices.
In 2024, transportation expenses and per-unit transportation expenses increased, compared with 2023, due to higher sales volumes exported to destinations outside of Alberta, which includes transportation costs related to our use of TMX, and increased pipeline transportation rates on shipments to U.S. destinations.
Per-Unit Transportation Expenses (1)

($/BOE) |  |  |  |  | 2024 |  | 2023 |  |
Foster Creek |  |  |  |  | 13.57 |  |  | 11.98 |  |  |
Christina Lake |  |  |  |  | 6.53 |  |  | 6.69 |  |  |
Sunrise |  |  |  |  | 16.07 |  |  | 12.47 |  |  |
Lloydminster (2) |  |  |  |  | 3.95 |  |  | 3.51 |  |  |
Total Oil Sands |  |  |  |  | 9.00 |  |  | 8.18 |  |  |

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
At Foster Creek, per-unit transportation expenses increased primarily due to higher costs as a result of the start-up of TMX, partially offset by lower rail transportation costs. In 2024, we had West Coast sales of 20 percent and volumes sold to U.S. destinations of 37 percent, a decrease from 44 percent of sales to U.S. destinations in 2023.
At Christina Lake, per-unit transportation expenses decreased primarily due to lower rail costs, partially offset by increased pipeline transportation costs. In 2024, we shipped 18 percent (2023 – 18 percent) of Christina Lake volumes to U.S. destinations.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 20

At Sunrise, per-unit transportation expenses increased primarily due to the use of TMX and increased sales volumes to U.S. destinations. In 2024, sales to U.S. destinations increased to 67 percent from 50 percent in 2023. In addition, 18 percent of sales were on the West Coast due to the use of TMX in 2024.
At Lloydminster, per-unit transportation expenses increased primarily due to higher pipeline transportation rates and increased sales outside of Alberta. We shipped three percent to U.S. destinations (2023 – no sales to U.S. destinations) and approximately 55 percent of production to our Canadian Refining operations.
Operating
Primary drivers of our operating expenses in 2024 were fuel, repairs and maintenance, and workforce. Total operating expenses in 2024 decreased compared with 2023, due to lower fuel costs as a result of significant declines in AECO benchmark prices. The decreases were partially offset by higher repairs and maintenance costs and GHG compliance costs. We have experienced some inflationary pressures on our costs; however, we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.
Per-Unit Operating Expenses (1)

($/BOE) |  |  |  |  |  |  | 2024 |  | Percent Change |  | 2023 |  |  |  |
Foster Creek |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  |  |  |  |  | 2.10 |  |  | (40) |  |  | 3.48 |  |  |  |  |
Non-Fuel |  |  |  |  |  |  | 7.77 |  |  | (2) |  |  | 7.96 |  |  |  |  |
Total |  |  |  |  |  |  | 9.87 |  |  | (14) |  |  | 11.44 |  |  |  |  |
Christina Lake |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  |  |  |  |  | 2.09 |  |  | (30) |  |  | 2.98 |  |  |  |  |
Non-Fuel |  |  |  |  |  |  | 6.54 |  |  | 18 |  |  | 5.54 |  |  |  |  |
Total |  |  |  |  |  |  | 8.63 |  |  | 1 |  |  | 8.52 |  |  |  |  |
Sunrise |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  |  |  |  |  | 2.89 |  |  | (40) |  |  | 4.78 |  |  |  |  |
Non-Fuel |  |  |  |  |  |  | 11.47 |  |  | (6) |  |  | 12.24 |  |  |  |  |
Total |  |  |  |  |  |  | 14.36 |  |  | (16) |  |  | 17.02 |  |  |  |  |
Lloydminster (2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  |  |  |  |  | 2.74 |  |  | (40) |  |  | 4.54 |  |  |  |  |
Non-Fuel |  |  |  |  |  |  | 14.78 |  |  | (6) |  |  | 15.78 |  |  |  |  |
Total |  |  |  |  |  |  | 17.52 |  |  | (14) |  |  | 20.32 |  |  |  |  |
Total Oil Sands |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  |  |  |  |  |  | 2.30 |  |  | (36) |  |  | 3.60 |  |  |  |  |
Non-Fuel |  |  |  |  |  |  | 9.10 |  |  | 2 |  |  | 8.94 |  |  |  |  |
Total |  |  |  |  |  |  | 11.40 |  |  | (9) |  |  | 12.54 |  |  |  |  |

(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
Per-unit fuel expenses decreased overall due to significantly lower natural gas prices, as discussed above.
Foster Creek per-unit non-fuel expenses slightly decreased in 2024, compared with 2023, due to lower electricity costs and increased sales volumes, partially offset by increased workover activity and GHG compliance costs.
Christina Lake per-unit non-fuel expenses increased in 2024, compared with 2023, due to higher turnaround activity, workover activity and GHG compliance costs.
Sunrise per-unit non-fuel expenses decreased in 2024, compared with 2023, due to increased sales volumes and lower electricity costs, partially offset by increased repairs and maintenance costs.
Lloydminster per-unit non-fuel expenses decreased in 2024, compared with 2023, due to increased sales volumes combined with lower chemical costs and workover activity, partially offset by increased GHG compliance costs.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 21

Netback (1)

($/BOE) |  |  |  |  | 2024 |  | 2023 |  |
Sales Price |  |  |  |  | 80.20 |  |  | 73.02 |  |  |
Royalties |  |  |  |  | 14.92 |  |  | 14.20 |  |  |
Transportation and Blending |  |  |  |  | 9.00 |  |  | 8.18 |  |  |
Operating Expenses |  |  |  |  | 11.40 |  |  | 12.54 |  |  |
Netback |  |  |  |  | 44.88 |  |  | 38.10 |  |  |

(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
Conventional
In 2024, we:
•Delivered safe and reliable operations, including safely executing turnarounds.
•Produced 119.9 thousand BOE per day (2023 – 119.9 thousand BOE per day).
•Generated Operating Margin of $291 million, a decrease of $292 million from 2023, primarily due to lower natural gas benchmark prices.
•Averaged a Netback of $6.48 per BOE (2023 – $12.02 per BOE).
•Invested capital of $421 million with a continued focus on drilling, completion, tie-in and infrastructure projects.
Financial Results

($ millions) |  |  |  |  | 2024 |  | 2023 |  |
Gross Sales |  |  |  |  |  |  |  |  |
External Sales |  |  |  |  | 1,211 |  |  | 1,488 |  |  |
Intersegment Sales |  |  |  |  | 1,848 |  |  | 1,785 |  |  |
|  |  |  |  | 3,059 |  |  | 3,273 |  |  |
Royalties |  |  |  |  | (76) |  |  | (112) |  |  |
Revenues |  |  |  |  | 2,983 |  |  | 3,161 |  |  |
Expenses |  |  |  |  |  |  |  |  |
Purchased Product |  |  |  |  | 1,823 |  |  | 1,695 |  |  |
Transportation and Blending |  |  |  |  | 320 |  |  | 298 |  |  |
Operating |  |  |  |  | 555 |  |  | 590 |  |  |
Realized (Gain) Loss on Risk Management |  |  |  |  | (6) |  |  | (5) |  |  |
Operating Margin |  |  |  |  | 291 |  |  | 583 |  |  |
Unrealized (Gain) Loss on Risk Management |  |  |  |  | 4 |  |  | (19) |  |  |
Depreciation, Depletion and Amortization |  |  |  |  | 442 |  |  | 386 |  |  |
Exploration Expense |  |  |  |  | 1 |  |  | 6 |  |  |
(Income) Loss From Equity-Accounted Affiliates |  |  |  |  | 2 |  |  | — |  |  |
Segment Income (Loss) |  |  |  |  | (158) |  |  | 210 |  |  |

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 22

Operating Margin Variance
Year Ended December 31, 2024
(1)Changes to price include the impact of realized risk management gains and losses.
(2)Reflects Operating Margin from processing facilities.
Operating Results

|  |  |  |  | 2024 |  | 2023 |  |
Total Sales Volumes (MBOE/d) |  |  |  |  | 119.9 |  |  | 119.9 |  |  |
Realized Sales Price (1) ($/BOE) |  |  |  |  | 25.18 |  |  | 31.76 |  |  |
Light Crude Oil ($/bbl) |  |  |  |  | 92.68 |  |  | 101.34 |  |  |
NGLs ($/bbl) |  |  |  |  | 54.62 |  |  | 48.25 |  |  |
Conventional Natural Gas ($/Mcf) |  |  |  |  | 2.51 |  |  | 3.91 |  |  |
Production by Product |  |  |  |  |  |  |  |  |
Light Crude Oil (Mbbls/d) |  |  |  |  | 4.9 |  |  | 5.9 |  |  |
NGLs (Mbbls/d) |  |  |  |  | 21.0 |  |  | 21.7 |  |  |
Conventional Natural Gas (MMcf/d) |  |  |  |  | 563.8 |  |  | 554.1 |  |  |
Total Production (MBOE/d) |  |  |  |  | 119.9 |  |  | 119.9 |  |  |
Conventional Natural Gas Production (percentage of total) |  |  |  |  | 78 |  |  | 77 |  |  |
Crude Oil and NGLs Production (percentage of total) |  |  |  |  | 22 |  |  | 23 |  |  |
Effective Royalty Rate (2) (percent) |  |  |  |  | 10.3 |  |  | 10.8 |  |  |
Transportation Expense (3) ($/BOE) |  |  |  |  | 4.98 |  |  | 4.16 |  |  |
Operating Expense (3) ($/BOE) |  |  |  |  | 11.99 |  |  | 13.02 |  |  |
Per-Unit DD&A (3) ($/BOE) |  |  |  |  | 9.90 |  |  | 8.76 |  |  |

(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Revenues
Gross sales decreased in 2024 compared with 2023, due to decreased benchmark pricing.
Price
Our total Realized Sales Price decreased in 2024, compared with 2023, primarily due to lower natural gas benchmark prices. For the year ended December 31, 2024, the AECO natural gas benchmark price declined 45 percent compared with 2023.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 23

Production Volumes
Production volumes were consistent in 2024, compared with 2023. In 2024, production increased due to less well downtime compared with 2023, partially offset by the divestiture of non-core assets. Well downtime in 2024 related to planned turnaround activity in the third quarter, while 2023 downtime was primarily in response to wildfire activity. In the second half of 2024, production was impacted by the deferral of new well development in response to lower natural gas benchmark prices.
Royalties
The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties decreased in 2024, compared with 2023, primarily due to lower natural gas benchmark prices.
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 2024, transportation expenses and per-unit transportation expenses increased primarily due to increased pipeline transportation rates, compared with 2023.
Operating
Primary drivers of operating expenses in 2024 were repairs and maintenance, workforce and property tax costs. Total operating expense and per-unit operating costs decreased compared with 2023, primarily due to lower processing and gathering costs, electricity costs and workover costs, partially offset by increased repairs and maintenance costs driven by higher turnaround activity.
In 2024, we completed five turnarounds in our Conventional segment and incurred $40 million in turnaround costs (2023 – $9 million). Per-unit operating expenses excluding turnaround costs were $11.08 per BOE (2023 – $12.82 per BOE).
Netback (1)

($/BOE) |  |  |  |  | 2024 |  | 2023 |  |
Sales Price |  |  |  |  | 25.18 |  |  | 31.76 |  |  |
Royalties |  |  |  |  | 1.73 |  |  | 2.56 |  |  |
Transportation and Blending |  |  |  |  | 4.98 |  |  | 4.16 |  |  |
Operating Expenses |  |  |  |  | 11.99 |  |  | 13.02 |  |  |
Netback |  |  |  |  | 6.48 |  |  | 12.02 |  |  |

(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
Offshore
In 2024, we:
•Delivered safe and reliable operations.
•Produced 66.6 thousand BOE per day of light crude oil, NGLs and natural gas (2023 – 63.4 thousand BOE per day).
•Generated Operating Margin of $1.0 billion, a decrease of $79 million from 2023, primarily due to lower Realized Sales Price and increased operating expenses.
•Averaged a Netback of $52.38 per BOE (2023 – $56.48 per BOE).
•Invested capital of $1.1 billion, mainly related to the progression of the West White Rose project and the execution of the SeaRose ALE project.
In late December 2023, we suspended production at the White Rose field as we prepared for the SeaRose ALE project. Refit work that commenced in the first quarter of 2024 was completed and the vessel returned to the field in November. The SeaRose FPSO is on station and reconnected to the White Rose field. Production is expected to resume late February 2025.
We have made significant progress on the West White Rose project and we are on track to deliver first oil in 2026. The project is approximately 88 percent complete and mechanical completion of the topsides and concrete gravity structure occurred in the fourth quarter. The focus in 2025 will be on installation and commissioning of the platform as we prepare to transition the project from construction to operations. Since our decision in 2022 to restart the project, we have invested approximately $1.6 billion.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 24

Financial Results

| 2024 |  | 2023
($ millions) | Atlantic |  | Asia Pacific |  | Offshore |  | Atlantic |  | Asia Pacific |  | Offshore
Gross Sales |  |  |  |  |  |  |  |  |  |  |
External Sales | 322 |  | 1,250 |  | 1,572 |  | 400 |  | 1,217 |  | 1,617
Intersegment Sales | — |  | — |  | — |  | — |  | — |  | —
| 322 |  | 1,250 |  | 1,572 |  | 400 |  | 1,217 |  | 1,617
Royalties | (2) |  | (97) |  | (99) |  | (15) |  | (84) |  | (99)
Revenues | 320 |  | 1,153 |  | 1,473 |  | 385 |  | 1,133 |  | 1,518
Expenses |  |  |  |  |  |  |  |  |  |  |
Transportation and Blending | 11 |  | — |  | 11 |  | 16 |  | — |  | 16
Operating | 290 |  | 133 |  | 423 |  | 262 |  | 122 |  | 384
Operating Margin (1) | 19 |  | 1,020 |  | 1,039 |  | 107 |  | 1,011 |  | 1,118
Depreciation, Depletion and Amortization |  |  |  |  | 563 |  |  |  |  |  | 487
Exploration Expense |  |  |  |  | 66 |  |  |  |  |  | 17
(Income) Loss from Equity-Accounted Affiliates |  |  |  |  | (53) |  |  |  |  |  | (57)
Segment Income (Loss) |  |  |  |  | 463 |  |  |  |  |  | 671

(1)Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Specified Financial Measures Advisory of this MD&A.
Operating Margin Variance
Year Ended December 31, 2024

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 25

Operating Results

|  |  |  |  | 2024 |  | 2023
Sales Volumes |  |  |  |  |  |  |
Atlantic (Mbbls/d) |  |  |  |  | 8.0 |  | 9.6
Asia Pacific (MBOE/d) |  |  |  |  |  |  |
China |  |  |  |  | 42.6 |  | 40.5
Indonesia (1) |  |  |  |  | 16.0 |  | 14.7
Total Asia Pacific |  |  |  |  | 58.6 |  | 55.2
Total Sales Volumes (MBOE/d) |  |  |  |  | 66.6 |  | 64.8 |
Realized Sales Price (1) (2) ($/BOE) |  |  |  |  | 78.40 |  |  | 81.63
Atlantic - Light Crude Oil ($/bbl) |  |  |  |  | 109.58 |  |  | 113.74
Asia Pacific (1) ($/BOE) |  |  |  |  | 74.13 |  |  | 76.04
NGLs ($/bbl) |  |  |  |  | 97.59 |  |  | 99.73
Conventional Natural Gas ($/Mcf) |  |  |  |  | 11.45 |  |  | 11.71
Production by Product |  |  |  |  |  |  |
Atlantic – Light Crude Oil (Mbbls/d) |  |  |  |  | 8.0 |  | 8.2
Asia Pacific (1) |  |  |  |  |  |  |
NGLs (Mbbls/d) |  |  |  |  | 11.0 |  | 10.8
Conventional Natural Gas (MMcf/d) |  |  |  |  | 285.3 |  | 266.6
Total Asia Pacific (MBOE/d) |  |  |  |  | 58.6 |  | 55.2
Total Production (MBOE/d) |  |  |  |  | 66.6 |  | 63.4
Effective Royalty Rate (3) (percent) |  |  |  |  |  |  |
Atlantic |  |  |  |  | 0.7 |  |  | 3.7 |
Asia Pacific (1) |  |  |  |  | 9.5 |  |  | 10.3 |
Operating Expense (2) ($/BOE) |  |  |  |  | 19.27 |  |  | 17.20
Atlantic (4) |  |  |  |  | 97.70 |  |  | 67.93
Asia Pacific (1) (2) |  |  |  |  | 8.52 |  |  | 8.37
Per-Unit DD&A (4) ($/BOE) |  |  |  |  | 22.33 |  |  | 25.57

(1)Reported sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 40 percent equity interest in the HCML joint venture. The HCML joint venture is accounted for using the equity method in the Consolidated Financial Statements.
(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 2024, compared with 2023, due to a decrease in Realized Sales Price resulting from lower Brent benchmark pricing, partially offset by an increase in sales volumes in China.
Price
Our Atlantic Realized Sales Price on light crude oil decreased in 2024, compared with 2023, 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 decreased in 2024, compared with 2023, primarily due to the suspension of production at the White Rose field in December 2023 for the SeaRose ALE project, partially offset by resuming production at the Terra Nova field in November 2023. Light crude oil production from the White Rose and Terra Nova fields are offloaded from the SeaRose and Terra Nova FPSOs, 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 increased in 2024, compared with 2023, due to less well downtime in China and higher production from the MAC field in Indonesia that came online in September 2023. In 2023, well downtime was due to the temporary unplanned outage that occurred in the second quarter of 2023, related to the disconnection of the umbilical by a third-party vessel.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 26

Royalties
For the year ended December 31, 2024, Atlantic royalties and the effective royalty rate decreased compared with 2023. The decreases were due to suspended production at the White Rose field for all of 2024, which has a higher effective royalty rate. All production in 2024 was at the Terra Nova field with a lower effective royalty rate.
Royalty rates in Asia Pacific are governed by production-sharing contracts, in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for Asia Pacific for 2024 declined compared with 2023, primarily due to a production bonus paid to the Government of Indonesia for achieving a production milestone in the first quarter of 2023, partially offset by a consumption tax implemented in China in June 2023 and in effect for the full year of 2024.
Expenses
Transportation
Transportation expenses include the costs of transporting crude oil from the Terra Nova FPSO and SeaRose FPSO vessels to onshore terminals via tankers, as well as storage costs. Transportation expenses for the year ended December 31, 2024, were $11 million (2023 – $16 million).
Operating
Primary drivers of our Atlantic operating expenses in 2024 were repairs and maintenance, costs related to vessels and air services, and workforce. Operating expenses increased compared with 2023, primarily due to higher repairs and maintenance and vessel mooring costs related to the SeaRose ALE project, and higher repairs and maintenance costs at the Terra Nova field. Per-unit operating expenses increased in 2024 compared with 2023, mainly due to the same factors discussed above and lower sales volumes.
Primary drivers of our China operating expenses in 2024 were repairs and maintenance, workforce costs and insurance. For the year ended December 31, 2024, operating expenses increased compared with 2023, primarily due to higher insurance costs, workforce, and repairs and maintenance costs. Per-unit operating expenses increased compared with 2023, mainly due to the factors discussed above, partially offset by higher sales volumes.
For the year ended December 31, 2024, Indonesia per-unit operating expenses increased compared with 2023, due to increased repairs and maintenance costs and workforce costs, partially offset by higher sales volumes.
Netbacks (1)

| 2024
($/BOE, except where indicated) | Atlantic ($/bbl) |  | China | Indonesia | Total Offshore (2)
Sales Price |  | 109.58 |  |  | 80.26 |  |  | 57.82 |  |  | 78.40 |
Royalties |  | 0.72 |  |  | 6.19 |  |  | 9.32 |  |  | 6.29 |
Transportation and Blending |  | 3.81 |  |  | — |  |  | — |  |  | 0.46 |
Operating Expenses |  | 97.70 |  |  | 7.61 |  |  | 10.93 |  |  | 19.27 |
Netback |  | 7.35 |  |  | 66.46 |  |  | 37.57 |  |  | 52.38 |

| 2023
($/BOE, except where indicated) | Atlantic ($/bbl) |  | China | Indonesia | Total Offshore (2)
Sales Price |  | 113.74 |  |  | 82.14 |  |  | 59.16 |  |  | 81.63 |
Royalties |  | 4.24 |  |  | 5.68 |  |  | 13.75 |  |  | 7.29 |
Transportation and Blending |  | 4.44 |  |  | — |  |  | — |  |  | 0.66 |
Operating Expenses |  | 67.93 |  |  | 7.51 |  |  | 10.76 |  |  | 17.20 |
Netback |  | 37.13 |  |  | 68.95 |  |  | 34.65 |  |  | 56.48 |

(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Reported sales volumes and associated per-unit values reflect Cenovus’s 40 percent equity interest in the HCML joint venture. The HCML joint venture is accounted for using the equity method in the Consolidated Financial Statements.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 27

DOWNSTREAM
Canadian Refining
In 2024, we:
•Delivered safe and reliable operations.
•Safely completed the largest turnaround in the Upgrader’s history, which commenced in May and ramped up to full operations in July.
•Achieved crude unit utilization of 84 percent with throughput of 90.5 thousand barrels per day (2023 – 93 percent and 100.7 thousand barrels per day, respectively).
•Incurred per-unit operating expenses excluding turnaround costs of $15.38 per barrel (2023 – $13.29 per barrel).
•Recorded an Operating Margin shortfall of $80 million, a decrease of $755 million from 2023, mainly due to lower production volumes due to the turnaround and lower commodity prices.
•Invested capital of $208 million, primarily focused on sustaining activities.
Financial and Operating Results

($ millions, except where indicated) |  |  |  |  | 2024 |  | 2023
Gross Sales |  |  |  |  |  |  |
External Sales |  |  |  |  | 4,787 |  |  | 5,385 |
Intersegment Sales |  |  |  |  | 523 |  |  | 848 |
Revenues |  |  |  |  | 5,310 |  |  | 6,233 |
Purchased Product |  |  |  |  | 4,483 |  |  | 4,919 |
Gross Margin (1) |  |  |  |  | 827 |  |  | 1,314 |
Expenses |  |  |  |  |  |  |
Operating |  |  |  |  | 907 |  |  | 639 |
Operating Margin |  |  |  |  | (80) |  |  | 675 |
Depreciation, Depletion and Amortization |  |  |  |  | 185 |  |  | 185 |
Segment Income (Loss) |  |  |  |  | (265) |  |  | 490 |
Operable Capacity (2) (Mbbls/d) |  |  |  |  | 108.0 |  |  | 108.0 |
Total Processed Inputs (3) (Mbbls/d) |  |  |  |  | 96.6 |  |  | 107.1 |
Crude Oil Unit Throughput (Mbbls/d) |  |  |  |  | 90.5 |  |  | 100.7 |
Crude Unit Utilization (4) (percent) |  |  |  |  | 84 |  |  | 93 |
Total Production (Mbbls/d) |  |  |  |  | 103.1 |  |  | 114.2 |
Synthetic Crude Oil |  |  |  |  | 41.0 |  |  | 47.6 |
Asphalt |  |  |  |  | 15.7 |  |  | 15.4 |
Diesel |  |  |  |  | 10.8 |  |  | 12.9 |
Other |  |  |  |  | 30.8 |  |  | 33.3 |
Ethanol |  |  |  |  | 4.8 |  |  | 5.0 |
Refining Margin (1) ($/bbl) |  |  |  |  | 20.82 |  |  | 30.13 |

(1)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader, commercial fuels business and the Lloydminster Refinery for the year ended December 31, 2024, were $5.0 billion (2023 – $5.8 billion).
(2)Operable capacity is the capacity based on throughput barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. We previously reported crude oil name plate capacity. See the Abbreviations and Definitions section of this MD&A.
(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.
(4)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.
In 2024, throughput and production were lower at our Canadian Refining assets compared with 2023, primarily due to the planned turnaround at the Upgrader that ran from early May to early July and the ramp-up to full operations that followed.
Revenues, Gross Margin and Refining Margin
The Upgrader processes blended heavy crude oil and bitumen into high-value synthetic crude oil and low-sulphur diesel. Revenues are dependent on the sales price of synthetic crude oil and 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.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 28

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.
The Upgrader and Lloydminster Refinery source crude oil feedstock from our Oil Sands segment. In 2024, approximately 12 percent of total crude oil sales volumes from our Oil Sands assets were sold to our Canadian Refining segment (2023 – 13 percent).
Revenues decreased compared with 2023, due to decreased synthetic crude oil and diesel benchmark prices and lower production, as discussed above. Gross Margin and per-barrel Refining Margin decreased compared with 2023, due to lower sales prices, lower production and higher feedstock costs.
Operating Expenses
The following table and discussion represent operating expenses associated with the Upgrader, the Lloydminster Refinery and the commercial fuels business.

($ millions, except where indicated) |  |  |  |  | 2024 |  | 2023
Operating Expenses - Upgrading and Refining |  |  |  |  | 798 |  |  | 524 |
Operating Expenses – Excluding Turnaround Costs |  |  |  |  | 544 |  |  | 520 |
Operating Expenses – Turnaround Costs |  |  |  |  | 254 |  |  | 4 |
Per-Unit Operating Expenses (1) ($/bbl) |  |  |  |  | 22.56 |  |  | 13.40 |
Per-Unit Operating Expenses – Excluding Turnaround Costs (1) |  |  |  |  | 15.38 |  |  | 13.29 |
Per-Unit Operating Expenses – Turnaround Costs (1) |  |  |  |  | 7.18 |  |  | 0.11 |

(1)Specified financial measure. Per-unit metrics are calculated on total processed inputs. Changes in metrics from prior periods have been re-presented. See the Specified Financial Measures Advisory of this MD&A.
Primary drivers of operating expenses were turnaround costs, workforce costs, and repairs and maintenance. In 2024, operating expenses excluding turnaround costs increased compared with 2023, primarily due to projects related to reliability that occurred during the turnaround period at the Upgrader. The increase in operating expenses, combined with decreased total processed inputs, resulted in increased per-unit operating expenses compared with 2023.
U.S. Refining
In 2024, we:
•Delivered safe operations.
•Safely completed a significant turnaround at the Lima Refinery that ran from early September until late October.
•Achieved crude unit utilization of 91 percent (2023 – 78 percent) and increased throughput to 556.4 thousand barrels per day compared with 459.7 thousand barrels per day in 2023.
•Achieved per-unit operating expenses excluding turnaround costs of $11.55 per barrel (2023 – $14.01 per barrel).
•Recorded an Operating Margin shortfall of $232 million, a decrease of $709 million from 2023. The decrease was primarily due to lower market crack spreads year-over-year with a sharp decline in the fourth quarter, a narrower WTI-WCS differential at Hardisty and the impact of the turnaround at the Lima Refinery, partially offset by the lower cost of RINs.
•Invested capital of $488 million, primarily focused on sustaining activities at our operated assets and refining reliability projects at our non-operated assets.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 29

Financial and Operating Results

($ millions, except where indicated) |  |  |  |  | 2024 |  | 2023
Gross Sales |  |  |  |  |  |  |
External Sales |  |  |  |  | 28,299 |  |  | 26,376 |
Intersegment Sales |  |  |  |  | 9 |  |  | 17 |
Revenues |  |  |  |  | 28,308 |  |  | 26,393 |
Purchased Product |  |  |  |  | 25,769 |  |  | 23,354 |
Gross Margin (1) |  |  |  |  | 2,539 |  |  | 3,039 |
Expenses |  |  |  |  |  |  |
Operating |  |  |  |  | 2,763 |  |  | 2,562 |
Realized (Gain) Loss on Risk Management |  |  |  |  | 8 |  |  | — |
Operating Margin |  |  |  |  | (232) |  |  | 477 |
Unrealized (Gain) Loss on Risk Management |  |  |  |  | 8 |  |  | (17) |
Depreciation, Depletion and Amortization |  |  |  |  | 462 |  |  | 486 |
Segment Income (Loss) |  |  |  |  | (702) |  |  | 8 |
Operable Capacity (2) (Mbbls/d) |  |  |  |  | 612.3 |  |  | 612.3 |
Total Processed Inputs (3) (Mbbls/d) |  |  |  |  | 581.4 |  |  | 479.7 |
Crude Oil Unit Throughput (Mbbls/d) |  |  |  |  | 556.4 |  |  | 459.7 |
Heavy Crude Oil |  |  |  |  | 219.6 |  |  | 173.9 |
Light/Medium Crude Oil |  |  |  |  | 336.8 |  |  | 285.8 |
Crude Unit Utilization (4) (5) (percent) |  |  |  |  | 91 |  |  | 78 |
Total Refined Product Production (Mbbls/d) |  |  |  |  | 590.0 |  |  | 485.0 |
Gasoline |  |  |  |  | 280.5 |  |  | 231.2 |
Distillates (6) |  |  |  |  | 209.1 |  |  | 167.0 |
Asphalt |  |  |  |  | 28.3 |  |  | 19.8 |
Other |  |  |  |  | 72.1 |  |  | 67.0 |
Refining Margin (1) ($/bbl) |  |  |  |  | 11.93 |  |  | 17.36 |
Weighted Average Crack Spread, Net of RINs (7) (US$/bbl) |  |  |  |  | 13.01 |  |  | 18.15 |
Weighted Average Crack Spread, Net of RINs (7) (C$/bbl) |  |  |  |  | 17.82 |  |  | 24.49 |
Market Capture (1) (5) (8) (percent) |  |  |  |  | 67 |  |  | 71 |

(1)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Operable capacity is the capacity based on throughput barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. We previously reported crude oil name plate capacity. See the Abbreviations and Definitions section of this MD&A.
(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.
(4)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.
(5)The Superior Refinery’s operable capacity is included in the metrics effective April 1, 2023. The Toledo Refinery includes a weighted average operable capacity in the metrics, as full ownership of the Toledo Refinery was acquired on February 28, 2023.
(6)Includes diesel and jet fuel.
(7)Weighted average crack spread, net of RINs is calculated as Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs. Average foreign exchange rates in the period are used to convert to Canadian dollars.
(8)The definition of Market Capture is Refining Margin divided by the weighted average crack spread, net of RINs, expressed as a percentage.
Throughput and refined product production increased in 2024, compared with 2023, primarily due to full operations from the Toledo Acquisition and the ramp-up of the Superior Refinery in 2023, combined with improved reliability across our U.S. Refining operations. The increases were partially offset by the turnaround at the Lima Refinery and unplanned outages at our refineries throughout the year. We were able to partially mitigate the impact of the Lima Refinery turnaround on production by processing Lima intermediate products at our Toledo Refinery, allowing the Lima Refinery’s crude unit to continue operations. In addition, we completed a turnaround at the non-operated Borger Refinery in 2024, compared with two turnarounds in 2023.
Revenues
Revenues increased in 2024, compared with 2023, due to higher sales volumes. The increase was partially offset by declines in benchmark gasoline and diesel prices of eight percent and 11 percent, respectively, compared with 2023.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 30

Gross Margin and Market Capture
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. While market crack spreads are an indicator of margin from processing crude oil into refined products, the refining realized crack spread, which is the 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; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the refineries; and the cost of feedstock. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued on a FIFO accounting basis.
Gross Margin decreased 16 percent in 2024 compared with 2023, primarily due to lower market crack spreads and the 21 percent narrower WTI-WCS differential at Hardisty due to the start-up of TMX, which increased the cost of heavy crude entering our refineries. The Chicago 3-2-1 crack spread decreased 31 percent and the Group 3 3-2-1 crack spread decreased 43 percent, compared with 2023. These factors, combined with the increase in total processed inputs compared with 2023, also decreased our per-barrel Refining Margin.
Market Capture is the Refining Margin, calculated on a FIFO basis of accounting, generated as a percentage of the weighted average market crack spread, net of RINs. The Chicago and Group 3 3-2-1 market crack spreads are used to calculate Market Capture, with a heavier weighting towards Chicago 3-2-1.
In 2024, Market Capture decreased compared with 2023, primarily due to the narrowing of the WTI-WCS differential at Hardisty, as discussed above.
Operating Expenses

($ millions, except where indicated) |  |  |  |  | 2024 |  | 2023
Operating Expenses |  |  |  |  | 2,763 |  |  | 2,562 |
Operating Expenses – Excluding Turnaround Costs |  |  |  |  | 2,457 |  |  | 2,454 |
Operating Expenses – Turnaround Costs |  |  |  |  | 306 |  |  | 108 |
Per-Unit Operating Expenses (1) ($/bbl) |  |  |  |  | 12.99 |  |  | 14.63 |
Per-Unit Operating Expenses – Excluding Turnaround Costs (1) |  |  |  |  | 11.55 |  |  | 14.01 |
Per-Unit Operating Expenses – Turnaround Costs (1) |  |  |  |  | 1.44 |  |  | 0.62 |

(1)Specified financial measure. Per-unit metrics are calculated on total processed inputs. Changes in metrics from prior periods have been re-presented. See the Specified Financial Measures Advisory of this MD&A.
Primary drivers of operating expenses were repairs and maintenance, workforce and turnaround costs. In 2024, operating expenses increased mainly due to the significant turnaround at the Lima Refinery. In 2023, turnarounds were completed at the non-operated Wood River and Borger refineries. The increase in operating expenses was also due to obtaining full ownership of the Toledo Refinery in 2023. Per-unit operating expenses decreased primarily due to higher total processed inputs, partially offset by higher operating expenses, as discussed above.
Operating expenses excluding turnaround costs were relatively consistent compared with 2023, primarily due to the Toledo Acquisition, as discussed above, offset by a decrease in repairs and maintenance expenses following the completion of commissioning and start-up activities at the Toledo and Superior refineries in 2023. Per-unit operating expenses excluding turnaround costs decreased primarily due to higher total processed inputs.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 31

CORPORATE AND ELIMINATIONS
Financial Results

($ millions) |  |  |  |  | 2024 |  | 2023
Realized (Gain) Loss on Risk Management |  |  |  |  | 24 |  |  | (3) |
Unrealized (Gain) Loss on Risk Management |  |  |  |  | 16 |  |  | 73 |
Depreciation, Depletion and Amortization |  |  |  |  | 102 |  |  | 107 |
General and Administrative |  |  |  |  | 794 |  |  | 688 |
Finance Costs, Net (1) |  |  |  |  | 514 |  |  | 538 |
Integration, Transaction and Other Costs |  |  |  |  | 166 |  |  | 85 |
Foreign Exchange (Gain) Loss, Net |  |  |  |  | 462 |  |  | (67) |
(Gain) Loss on Divestiture of Assets (1) |  |  |  |  | (119) |  |  | 20 |
Re-measurement of Contingent Payments |  |  |  |  | 30 |  |  | 59 |
Other (Income) Loss, Net |  |  |  |  | (55) |  |  | (63) |

(1)Revised presentation as of January 1, 2024. Refer to Note 4 of the Consolidated Financial Statements for further detail.
General and Administrative
Primary drivers of our general and administrative expenses in 2024 were workforce costs and information technology related costs. The increase in general and administrative expenses was primarily due to higher information technology and software costs, and higher people costs.
Finance Costs, Net
Net finance costs were lower compared with 2023, primarily due to lower interest expenses on long-term debt and higher interest income in 2024, partially offset by the discount on the redemption of long-term debt from the purchase of US$1.0 billion of unsecured notes in 2023. 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 2024 was 4.5 percent (2023 – 4.7 percent).
Integration, Transaction and Other Costs
In 2024, we incurred costs of $166 million, primarily related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. We are recalibrating work on the previously announced enterprise-wide IT systems upgrades to a more fit for purpose outcome and have deferred the enterprise-wide upgrades post 2025.
In 2023, we incurred transaction and integration costs of $85 million, primarily related to the Toledo Acquisition.
Foreign Exchange (Gain) Loss, Net

($ millions) |  |  |  |  | 2024 |  | 2023
Unrealized Foreign Exchange (Gain) Loss |  |  |  |  | 550 |  |  | (210) |
Realized Foreign Exchange (Gain) Loss |  |  |  |  | (88) |  |  | 143 |
|  |  |  |  | 462 |  |  | (67) |

Unrealized foreign exchange gains and losses were primarily due to the translation of U.S. denominated debt. In 2024, realized foreign exchange gains were primarily related to working capital. In 2023, realized foreign exchange losses were primarily related to the purchase of U.S. denominated notes. As at December 31, 2024, the Canadian dollar was eight percent weaker relative to the U.S. dollar at December 31, 2023.
(Gain) Loss on Divestiture of Assets
The Company closed a transaction with Athabasca Oil Corporation to create the jointly-controlled Duvernay, in which we hold a 30 percent equity interest and is accounted for using the equity method in the Consolidated Financial Statements. We recorded a before-tax gain of $65 million on the transaction.
The Company also closed the sale of non-core assets in its Conventional segment for net proceeds of $39 million and recorded a before-tax gain of $51 million.
In 2023, we recorded a non-cash revaluation loss of $34 million as part of the Toledo Acquisition.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 32

Re-measurement of Contingent Payments
On August 31, 2024, the variable payment obligation associated with the transaction with BP Canada Energy Group ULC to purchase the remaining 50 percent interest in Sunrise Oil Sands Partnership ended, and the final payment was made in October 2024. We recorded a non-cash remeasurement loss of $30 million associated with this payment in 2024 (2023 – $59 million).
Income Taxes

($ millions) |  |  |  |  | 2024 |  | 2023
Current Tax |  |  |  |  |  |  |
Canada |  |  |  |  | 1,141 |  |  | 1,041 |
United States |  |  |  |  | 9 |  |  | (109) |
Asia Pacific |  |  |  |  | 214 |  |  | 224 |
Other International |  |  |  |  | 39 |  |  | 25 |
Total Current Tax Expense (Recovery) |  |  |  |  | 1,403 |  |  | 1,181 |
Deferred Tax Expense (Recovery) |  |  |  |  | (474) |  |  | (250) |
|  |  |  |  | 929 |  |  | 931 |

For the year ended December 31, 2024, we recorded current tax expense related to operations in all jurisdictions in which we operate. The increase in total current tax expense was primarily due to a current tax recovery in the U.S. in 2023. The effective tax rate for 2024 was 22.8 percent (2023 – 18.5 percent). The higher effective tax rate in 2024 is primarily due to non-taxable foreign exchange losses on long-term debt compared with non-taxable foreign exchange gains in 2023, paired with lower U.S. basis recognition.
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.
In June 2024, the Global Minimum Tax Act was enacted in Canada to implement the new global minimum tax framework (“Pillar Two”), which is to be applied retroactively to fiscal periods beginning on or after December 31, 2023. The Company is subject to Pillar Two and has applied the mandatory temporary exemption of IAS 12, “Income Taxes” and in turn, has not recognized the impacts of Pillar Two in the deferred income tax calculation.
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.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 33

QUARTERLY RESULTS

|  |  |  |  |  |  | 2024 |  | 2023 |
($ millions, except where indicated) |  |  |  |  |  |  |  |  |  |  |  |  | Q4 | Q3 | Q2 | Q1 |  | Q4 | Q3 | Q2 | Q1 |  |  |  |
Average Commodity Prices (1) (US$/bbl) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dated Brent |  |  |  |  |  |  |  |  |  |  |  |  | 74.69 |  | 80.18 |  | 84.94 |  | 83.24 |  |  | 84.05 |  | 86.76 |  | 78.39 |  | 81.27 |  |  |  |  |
WTI |  |  |  |  |  |  |  |  |  |  |  |  | 70.27 |  | 75.09 |  | 80.57 |  | 76.96 |  |  | 78.32 |  | 82.26 |  | 73.78 |  | 76.13 |  |  |  |  |
WCS at Hardisty |  |  |  |  |  |  |  |  |  |  |  |  | 57.71 |  | 61.54 |  | 66.96 |  | 57.65 |  |  | 56.43 |  | 69.35 |  | 58.74 |  | 51.36 |  |  |  |  |
Differential WTI-WCS at Hardisty |  |  |  |  |  |  |  |  |  |  |  |  | 12.56 |  | 13.55 |  | 13.61 |  | 19.31 |  |  | 21.89 |  | 12.91 |  | 15.04 |  | 24.77 |  |  |  |  |
Chicago 3-2-1 Crack Spread (2) |  |  |  |  |  |  |  |  |  |  |  |  | 12.12 |  | 18.62 |  | 18.76 |  | 17.45 |  |  | 13.24 |  | 26.06 |  | 28.57 |  | 28.88 |  |  |  |  |
Group 3 3-2-1 Crack Spread (2) |  |  |  |  |  |  |  |  |  |  |  |  | 12.66 |  | 18.95 |  | 18.13 |  | 17.50 |  |  | 18.55 |  | 36.96 |  | 31.78 |  | 31.35 |  |  |  |  |
RINs |  |  |  |  |  |  |  |  |  |  |  |  | 4.02 |  | 3.89 |  | 3.39 |  | 3.68 |  |  | 4.77 |  | 7.42 |  | 7.72 |  | 8.20 |  |  |  |  |
Upstream Production Volumes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bitumen (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  | 608.6 |  | 569.6 |  | 591.7 |  | 595.4 |  |  | 595.1 |  | 586.0 |  | 554.6 |  | 570.7 |  |  |  |  |
Heavy Crude Oil (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  | 18.0 |  | 16.3 |  | 18.1 |  | 17.9 |  |  | 17.5 |  | 15.6 |  | 17.0 |  | 16.8 |  |  |  |  |
Light Crude Oil (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  | 12.3 |  | 13.6 |  | 13.5 |  | 12.5 |  |  | 15.8 |  | 15.2 |  | 10.1 |  | 15.3 |  |  |  |  |
NGLs (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  | 31.7 |  | 31.0 |  | 33.0 |  | 32.4 |  |  | 34.2 |  | 35.6 |  | 26.7 |  | 33.4 |  |  |  |  |
Conventional Natural Gas (MMcf/d) |  |  |  |  |  |  |  |  |  |  |  |  | 873.3 |  | 844.6 |  | 867.2 |  | 855.8 |  |  | 876.3 |  | 867.4 |  | 729.4 |  | 857.0 |  |  |  |  |
Total Production Volumes (MBOE/d) |  |  |  |  |  |  |  |  |  |  |  |  | 816.0 |  | 771.3 |  | 800.8 |  | 800.9 |  |  | 808.6 |  | 797.0 |  | 729.9 |  | 779.0 |  |  |  |  |
Downstream Total Processed Inputs (3) (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  | 700.5 |  | 674.4 |  | 652.9 |  | 683.8 |  |  | 605.7 |  | 691.3 |  | 566.9 |  | 480.7 |  |  |  |  |
Crude Oil Unit Throughput (3) (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  | 666.7 |  | 642.9 |  | 622.7 |  | 655.2 |  |  | 579.1 |  | 664.3 |  | 537.8 |  | 457.9 |  |  |  |  |
Downstream Production Volumes (3) (Mbbls/d) |  |  |  |  |  |  |  |  |  |  |  |  | 722.6 |  | 685.2 |  | 659.5 |  | 702.1 |  |  | 627.4 |  | 706.0 |  | 571.9 |  | 487.7 |  |  |  |  |
Revenues (4) |  |  |  |  |  |  |  |  |  |  |  |  | 12,813 |  | 13,819 |  | 14,582 |  | 13,063 |  |  | 13,134 |  | 14,577 |  | 12,231 |  | 12,262 |  |  |  |  |
Operating Margin (5) |  |  |  |  |  |  |  |  |  |  |  |  | 2,274 |  | 2,408 |  | 2,936 |  | 3,191 |  |  | 2,151 |  | 4,369 |  | 2,400 |  | 2,102 |  |  |  |  |
Operating Margin – Upstream (6) |  |  |  |  |  |  |  |  |  |  |  |  | 2,670 |  | 2,731 |  | 3,089 |  | 2,631 |  |  | 2,455 |  | 3,447 |  | 2,257 |  | 1,711 |  |  |  |  |
Operating Margin – Downstream (6) |  |  |  |  |  |  |  |  |  |  |  |  | (396) |  | (323) |  | (153) |  | 560 |  |  | (304) |  | 922 |  | 143 |  | 391 |  |  |  |  |
Cash From (Used in) Operating Activities |  |  |  |  |  |  |  |  |  |  |  |  | 2,029 |  | 2,474 |  | 2,807 |  | 1,925 |  |  | 2,946 |  | 2,738 |  | 1,990 |  | (286) |  |  |  |  |
Adjusted Funds Flow (5) |  |  |  |  |  |  |  |  |  |  |  |  | 1,601 |  | 1,960 |  | 2,361 |  | 2,242 |  |  | 2,062 |  | 3,447 |  | 1,899 |  | 1,395 |  |  |  |  |
Per Share – Basic (5) ($) |  |  |  |  |  |  |  |  |  |  |  |  | 0.88 |  | 1.06 |  | 1.27 |  | 1.20 |  |  | 1.10 |  | 1.82 |  | 1.00 |  | 0.73 |  |  |  |  |
Per Share – Diluted (5) ($) |  |  |  |  |  |  |  |  |  |  |  |  | 0.87 |  | 1.05 |  | 1.26 |  | 1.19 |  |  | 1.08 |  | 1.81 |  | 0.98 |  | 0.71 |  |  |  |  |
Capital Investment |  |  |  |  |  |  |  |  |  |  |  |  | 1,478 |  | 1,346 |  | 1,155 |  | 1,036 |  |  | 1,170 |  | 1,025 |  | 1,002 |  | 1,101 |  |  |  |  |
Free Funds Flow (5) |  |  |  |  |  |  |  |  |  |  |  |  | 123 |  | 614 |  | 1,206 |  | 1,206 |  |  | 892 |  | 2,422 |  | 897 |  | 294 |  |  |  |  |
Excess Free Funds Flow (5) |  |  |  |  |  |  |  |  |  |  |  |  | (416) |  | 146 |  | 735 |  | 832 |  |  | 471 |  | 1,989 |  | 505 |  | (499) |  |  |  |  |
Net Earnings (Loss) |  |  |  |  |  |  |  |  |  |  |  |  | 146 |  | 820 |  | 1,000 |  | 1,176 |  |  | 743 |  | 1,864 |  | 866 |  | 636 |  |  |  |  |
Per Share – Basic ($) |  |  |  |  |  |  |  |  |  |  |  |  | 0.08 |  | 0.44 |  | 0.53 |  | 0.62 |  |  | 0.39 |  | 0.98 |  | 0.45 |  | 0.33 |  |  |  |  |
Per Share – Diluted ($) |  |  |  |  |  |  |  |  |  |  |  |  | 0.07 |  | 0.42 |  | 0.53 |  | 0.62 |  |  | 0.32 |  | 0.97 |  | 0.44 |  | 0.31 |  |  |  |  |
Total Assets |  |  |  |  |  |  |  |  |  |  |  |  | 56,539 |  | 54,680 |  | 56,000 |  | 54,994 |  |  | 53,915 |  | 54,427 |  | 53,747 |  | 54,000 |  |  |  |  |
Long-Term Debt, Including Current Portion |  |  |  |  |  |  |  |  |  |  |  |  | 7,534 |  | 7,199 |  | 7,275 |  | 7,227 |  |  | 7,108 |  | 7,224 |  | 8,534 |  | 8,681 |  |  |  |  |
Net Debt |  |  |  |  |  |  |  |  |  |  |  |  | 4,614 |  | 4,196 |  | 4,258 |  | 4,827 |  |  | 5,060 |  | 5,976 |  | 6,367 |  | 6,632 |  |  |  |  |
Cash Returns to Common and Preferred Shareholders |  |  |  |  |  |  |  |  |  |  |  |  | 706 |  | 1,070 |  | 1,034 |  | 436 |  |  | 731 |  | 1,225 |  | 584 |  | 258 |  |  |  |  |
Common Shares – Base Dividends |  |  |  |  |  |  |  |  |  |  |  |  | 330 |  | 329 |  | 334 |  | 262 |  |  | 261 |  | 264 |  | 265 |  | 200 |  |  |  |  |
Base Dividends Per Common Share ($) |  |  |  |  |  |  |  |  |  |  |  |  | 0.180 |  | 0.180 |  | 0.180 |  | 0.140 |  |  | 0.140 |  | 0.140 |  | 0.140 |  | 0.105 |  |  |  |  |
Common Shares – Variable Dividends |  |  |  |  |  |  |  |  |  |  |  |  | — |  | — |  | 251 |  | — |  |  | — |  | — |  | — |  | — |  |  |  |  |
Variable Dividends Per Common Share ($) |  |  |  |  |  |  |  |  |  |  |  |  | — |  | — |  | 0.135 |  | — |  |  | — |  | — |  | — |  | — |  |  |  |  |
Purchase of Common Shares Under NCIB |  |  |  |  |  |  |  |  |  |  |  |  | 108 |  | 732 |  | 440 |  | 165 |  |  | 350 |  | 361 |  | 310 |  | 40 |  |  |  |  |
Payment for Purchase of Warrants |  |  |  |  |  |  |  |  |  |  |  |  | — |  | — |  | — |  | — |  |  | 111 |  | 600 |  | — |  | — |  |  |  |  |
Dividends Paid on Preferred Shares |  |  |  |  |  |  |  |  |  |  |  |  | 18 |  | 9 |  | 9 |  | 9 |  |  | 9 |  | — |  | 9 |  | 18 |  |  |  |  |
Preferred Share Redemption |  |  |  |  |  |  |  |  |  |  |  |  | 250 |  | — |  | — |  | — |  |  | — |  | — |  | — |  | — |  |  |  |  |

(1)These benchmark prices are not our Realized Sales Prices and represent approximate values. For our average Realized Sales Prices and realized risk management results, refer to the Netback tables in the Upstream section of this MD&A.
(2)The average 3-2-1 crack spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.
(3)Represents Cenovus’s net interest in refining operations.
(4)2024 comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A.
(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. – 2024 Management's Discussion and Analysis | 34

Our results for the fourth quarter reflect strong operational performance in the upstream business and improved performance from our refining operations compared with the third quarter of 2024. Our U.S. Refining financial results were significantly impacted by declining market crack spreads. Total Operating Margin for the quarter was $2.3 billion, comprising $2.7 billion in the upstream and an Operating Margin shortfall of $396 million in the downstream (third quarter of 2024 Operating Margin – $2.4 billion).
•Upstream production averaged 816.0 thousand BOE per day, an increase of 44.7 thousand BOE per day from the third quarter of 2024, due to the completion of the Christina Lake turnaround in September and positive post-turnaround impacts.
•Downstream throughput increased four percent from the third quarter of 2024 to 666.7 thousand barrels per day, largely driven by improved reliability in the U.S. Refining segment and the completion of the turnaround at the Lima Refinery in October, partially offset by some economic run cuts as market crack spreads weakened.
•Benchmark market crack spreads declined significantly in the fourth quarter of 2024. The Chicago 3-2-1 crack spread and the Group 3 3-2-1 crack spread fell 35 percent and 33 percent, respectively, from the third quarter of 2024 to US$12.12 and US$12.66 per barrel. Net of RINs, Chicago market crack spreads in the fourth quarter averaged US$8.10 per barrel, compared with US$14.73 per barrel in the third quarter of 2024.
•We mechanically completed the Narrows Lake pipeline to Christina Lake. The pipeline will commence steam injection in the spring and the project remains on track for first oil mid-2025.
•We progressed the West White Rose project and mechanical completion of the topsides and concrete gravity structure occurred in the fourth quarter. The project is on track to deliver first oil in 2026.
•Refit work that commenced in the first quarter of 2024 on the SeaRose FPSO was completed and the vessel returned to the field in November.
•Cash from operating activities fell to $2.0 billion from $2.5 billion in the third quarter of 2024, and Adjusted Funds Flow decreased to $1.6 billion from $2.0 billion in the third quarter, primarily due to higher cash taxes and lower Operating Margin.
•We returned $438 million to common shareholders through the base dividend and share buybacks of $108 million.
Fourth Quarter 2024 Results Compared with the Fourth Quarter 2023
The summary below compares financial and operating results for the three months ended December 31, 2024, compared with the same period in 2023.
Upstream Production Volumes
Total upstream production increased 7.4 thousand BOE per day in the fourth quarter of 2024 compared with 2023, primarily due to:
•Successful results from redevelopment wells and positive post-turnaround impacts at our Christina Lake asset.
•Increased production at the fully operational MAC field that came online in September 2023, combined with higher buyer nominations and increased condensate lifting in our Indonesia operations.
The increases were partially offset by less new well development and the divestiture of non-core assets in the first and third quarters of 2024 in our Conventional segment.
Downstream Refining Throughput and Production
Canadian Refining operations were strong in the fourth quarter with crude unit utilization of 97 percent (2023 – 93 percent). Throughput increased 4.1 thousand barrels per day to 104.4 thousand barrels per day and production increased 5.1 thousand barrels per day to 118.4 thousand barrels per day compared with 2023.
U.S. Refining throughput increased 83.5 thousand barrels per day to 562.3 thousand barrels per day and total refined product production increased 90.1 thousand barrels per day to 604.2 thousand barrels per day compared with 2023, primarily due to lower maintenance activity in 2024, compared with a turnaround at the non-operated Borger Refinery in 2023. The increases were partially offset by the turnaround at the Lima Refinery, which ended in late October. We were able to partially mitigate the impact of the turnaround at the Lima Refinery by processing intermediate products at our Toledo Refinery, which allowed the Lima Refinery’s crude unit to continue operations.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 35

Operating Margin
Three Months Ended December 31, 2024 and 2023
Operating Margin was $2.3 billion in the fourth quarter of 2024, compared with $2.2 billion in the fourth quarter of 2023. The increase was primarily due to higher Realized Sales Prices in our Oil Sands segment driven by the narrower WTI-WCS differential. The increase was partially offset by lower Gross Margin in the Canadian Refining segment as a result of lower refined product pricing and lower sales volumes in our Offshore segment. Operating Margin in the U.S. Refining segment decreased due to lower market crack spreads and higher operating expenses.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash from operating activities decreased $917 million to $2.0 billion in the fourth quarter of 2024, compared with the fourth quarter of 2023, primarily due to changes in non-cash working capital and higher cash taxes. The net change in non-cash working capital was a source of cash of $492 million in 2024, primarily due to increases in accounts payable and taxes payable, combined with a decrease in accounts receivable, partially offset by increased inventories. In 2023, the $949 million source of cash was primarily due to lower accounts receivable and inventories, partially offset by lower accounts payable, all driven by decreasing commodity prices during the period.
Adjusted Funds Flow decreased to $1.6 billion in the fourth quarter of 2024, compared with $2.1 billion in 2023, primarily due to higher cash taxes.
Net Earnings (Loss)
Net earnings were $146 million in the fourth quarter of 2024 compared with $743 million in the fourth quarter of 2023. The decrease was primarily due to foreign exchange losses of $381 million in 2024 compared with gains of $74 million and higher general and administrative expenses, mainly driven by higher people costs compared with 2023.
Capital Investment
Capital investment increased to $1.5 billion in the fourth quarter of 2024, compared with $1.2 billion in the fourth quarter of 2023, as we continued our upstream growth projects and downstream sustaining work.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 36

OIL AND GAS RESERVES

As at December 31, 2024 (before royalties) (1) (2) | Bitumen (3) (MMbbls) |  | Light and Medium Oil (MMbbls) |  | NGLs (MMbbls) |  | Conventional Natural Gas (4) (Bcf) |  | Total (MMBOE)
Total Proved | 5,179 |  |  | 91 |  |  | 69 |  |  | 1,950 |  |  | 5,664 |
Probable | 2,500 |  |  | 77 |  |  | 37 |  |  | 1,071 |  |  | 2,793 |
Total Proved Plus Probable | 7,679 |  |  | 168 |  |  | 107 |  |  | 3,021 |  |  | 8,457 |

As at December 31, 2023 (before royalties) (1) (2) | Bitumen (3) (MMbbls) |  | Light and Medium Oil (MMbbls) |  | NGLs (MMbbls) |  | Conventional Natural Gas (4) (Bcf) |  | Total (MMBOE)
Total Proved | 5,411 |  |  | 38 |  |  | 74 |  |  | 2,062 |  |  | 5,866 |
Probable | 2,487 |  |  | 125 |  |  | 40 |  |  | 1,100 |  |  | 2,836 |
Total Proved Plus Probable | 7,899 |  |  | 163 |  |  | 114 |  |  | 3,162 |  |  | 8,702 |

(1)Totals may not sum due to rounding.
(2)Includes values attributable to Cenovus’s 40 percent equity interest in the HCML joint venture. 2024 includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay joint venture.
(3)Includes heavy crude oil that is not material.
(4)Includes shale gas that is not material.
The following developments occurred in 2024 compared with 2023:
•Bitumen gross total proved and gross total proved plus probable reserves decreased by 232 million barrels and 220 million barrels, respectively. The changes were due to current year production and negative technical revisions resulting from recovery factor changes at Christina Lake and Foster Creek, and negative technical revisions resulting from updates to the Sunrise and Lloydminster thermal development plans. These reductions were partially offset by extensions due to continuing development of, and updates to development plans for, the Oil Sands segment, and technical revisions due to improvements to recovery performance at Sunrise and Lloydminster thermal.
•Light and medium oil gross total proved and gross total proved plus probable reserves increased by 53 million barrels and five million barrels, respectively. The changes were due to extensions as a result of continuing development of the West White Rose project and the acquisition of the equity interest in Duvernay. These increases were partially offset by current year production and dispositions in the Conventional segment.
•NGLs gross total proved and gross total proved plus probable reserves decreased by five million barrels and seven million barrels, respectively. The changes were due to current year production, negative technical revisions due to updates to the Conventional segment development plans and dispositions in the Conventional segment. These reductions were partially offset by extensions due to updates to the Conventional segment development plans, technical revisions due to improvements to recovery performance for the Conventional segment and the Asia Pacific region, and the acquisition of the equity interest in Duvernay.
•Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 112 billion cubic feet and 141 billion cubic feet, respectively. The changes were due to current year production, negative technical revisions due to updates to the Conventional segment development plans and dispositions in the Conventional segment. These reductions were partially offset by extensions due to updates to the Conventional segment development plans, technical revisions due to increases to original natural gas in place volumes for the Asia Pacific region and the acquisition of the equity interest in Duvernay.
The reserves data is presented as at December 31, 2024, using an average of the forecast prices, inflation and exchange rates (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast is dated January 1, 2025. Comparative information as at December 31, 2023, uses the January 1, 2024, Average Forecast.
Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities” is contained in our AIF for the year ended December 31, 2024. Our AIF is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in the Risk Management and Risk Factors section and the Advisory section of this MD&A.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 37

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. This includes draws on our committed credit facility, draws on our uncommitted demand facilities and other corporate and financial opportunities, which provide timely access to funding to supplement cash flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Ratings, Morningstar DBRS and Fitch Ratings. In the first quarter of 2024, we received a rating upgrade from S&P Global to BBB with a Stable outlook. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.

($ millions) |  |  |  |  | 2024 |  | 2023
Cash From (Used In) |  |  |  |  |  |  |
Operating Activities |  |  |  |  | 9,235 |  |  | 7,388 |
Investing Activities |  |  |  |  | (5,126) |  |  | (5,295) |
Net Cash Provided (Used) Before Financing Activities |  |  |  |  | 4,109 |  |  | 2,093 |
Financing Activities |  |  |  |  | (3,505) |  |  | (4,313) |
Effect of Foreign Exchange on Cash and Cash Equivalents |  |  |  |  | 262 |  |  | (77) |
Increase (Decrease) in Cash and Cash Equivalents |  |  |  |  | 866 |  |  | (2,297) |
|  |  |  |  | December 31, |  | December 31,
As at ($ millions) |  |  |  |  | 2024 |  | 2023
Cash and Cash Equivalents |  |  |  |  | 3,093 |  |  | 2,227 |
Total Debt |  |  |  |  | 7,707 |  |  | 7,287 |

Cash From (Used in) Operating Activities
In 2024, cash from operating activities increased compared with 2023, primarily due to a working capital release, partially offset by lower Operating Margin. Non-cash working capital was a source of cash of $1.3 billion in 2024, due to lower accounts receivable, higher accounts payable and higher taxes payable, partially offset by higher inventories. In 2023, changes in non-cash working capital was a use of cash of $1.2 billion, primarily driven by the payment of the December 31, 2022, income tax liability that occurred in the first quarter of 2023.
Cash From (Used in) Investing Activities
Cash used in investing activities decreased in 2024 compared with 2023, primarily due to the Toledo Acquisition in the first quarter of 2023, partially offset by a planned increase in capital investment in 2024.
Cash From (Used in) Financing Activities
Cash used in financing activities decreased in 2024 compared with 2023. The decrease was primarily due to the purchase of US$1.0 billion of unsecured notes in the third quarter of 2023. The decrease was partially offset by returns to common shareholders of $3.0 billion (2023 – $2.8 billion) and the redemption of $250 million of preferred shares.
Working Capital
Working capital as at December 31, 2024, was $3.1 billion (December 31, 2023 – $3.5 billion). The decrease in working capital was driven by an increase in accounts payable combined with a decrease in accounts receivable, partially offset by an increase in cash and inventories.
We anticipate that we will continue to meet our payment obligations as they come due.
Returns to Shareholders Target
Maintaining a strong balance sheet, with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle, is a key element of Cenovus’s capital allocation framework. Our Net Debt target is $4.0 billion and represents a Net Debt to Adjusted Funds Flow ratio target of approximately 1.0 times at the bottom of the commodity pricing cycle, which we believe is approximately US$45.00 per barrel.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 38

On achieving our Net Debt target, in the third quarter we increased target returns to shareholders, stewarding to 100 percent of Excess Free Funds Flow over time while maintaining 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 December 31, |  | Twelve Months Ended December 31,
($ millions) | 2024 |  | 2023 |  | 2024 |  | 2023
Excess Free Funds Flow (1) | (416) |  |  | 471 |  |  | 1,297 |  |  | 2,466 |
Target Return (2) | (416) |  |  | 236 |  |  | 514 |  |  | 1,233 |
Shareholder Returns by way of: |  |  |  |  |  |  |
Purchase of Common Shares Under NCIB | 108 |  |  | 350 |  |  | 1,445 |  |  | 1,061 |
Payment for Purchase of Warrants | — |  |  | 111 |  |  | — |  |  | 711 |
Variable Dividends Paid | — |  |  | — |  |  | 251 |  |  | — |
Preferred Share Redemption | 250 |  |  | — |  |  | 250 |  |  | — |
Total | 358 |  |  | 461 |  |  | 1,946 |  |  | 1,772 |
Return in (Excess)/Short of Target | (774) |  |  | (225) |  |  | (1,432) |  |  | (539) |

(1)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)The target return for the year ended December 31, 2024, includes 100 percent of Excess Free Funds Flow in the third and fourth quarters of 2024 and 50 percent of Excess Free Funds Flow in the first and second quarters of 2024. The target return for 2023 was 50 percent of Excess Free Funds Flow.
Short-Term Borrowings
There were no direct borrowings on our uncommitted demand facilities as at December 31, 2024, or December 31, 2023. As at December 31, 2024, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$120 million (C$173 million) (December 31, 2023 – US$135 million (C$179 million)).
Long-Term Debt, Including Current Portion
Long-term debt, including the current portion, as at December 31, 2024, was $7.5 billion (December 31, 2023 – $7.1 billion). The increase was due to the weakening of the Canadian dollar relative to the U.S. dollar, impacting the translation of our U.S. denominated debt. We hold U.S. dollar denominated unsecured notes of US$3.8 billion (C$5.5 billion) (December 31, 2023 – US$3.8 billion (C$5.0 billion)) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2023 – $2.0 billion).
As at December 31, 2024, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
The following sources of liquidity are available as at December 31, 2024:

($ millions) | Maturity |  |  |  |  |  |  |  | Amount Available
Cash and Cash Equivalents | n/a |  |  |  |  |  |  |  | 3,093 |
Committed Credit Facility |  |  |  |  |  |  |  |  |
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. (1) | n/a |  |  |  |  |  |  |  | 1,072 |
WRB (2) | n/a |  |  |  |  |  |  |  | 151 |

(1)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 December 31, 2024, there were outstanding letters of credit aggregating to $355 million (December 31, 2023 – $364 million) and no direct borrowings (December 31, 2023 – $nil).
(2)Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at December 31, 2024, US$120 million (C$173 million) of this capacity was drawn (December 31, 2023 – US$135 million (C$179 million)).
On June 26, 2024, Cenovus renewed its existing committed credit facility to extend the maturity dates by more than one year. As at December 31, 2024, no amount was drawn on the credit facility (December 31, 2023 – $nil).
Under 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.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 39

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 22 of the Consolidated Financial Statements for further details.
We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents, and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholder’s Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA ratio, as net earnings (loss) before finance costs, net, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, (gain) loss on divestiture of assets, re-measurement of contingent payments and 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 | December 31, 2024 |  | December 31, 2023 |  |
Net Debt to Adjusted EBITDA Ratio (times) | 0.5 |  | 0.5 |  |
Net Debt to Adjusted Funds Flow Ratio (times) | 0.6 |  | 0.6 |  |
Net Debt to Capitalization Ratio (percent) | 13 |  |  | 15 |  |  |

Our Net Debt to Adjusted Funds Flow ratio and our Net Debt to Adjusted EBITDA 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 December 31, 2024, were consistent with December 31, 2023, as a result of lower Net Debt partially offset by lower Operating Margin. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt.
Our Net Debt to Capitalization ratio as at December 31, 2024, decreased compared with December 31, 2023, primarily due to comprehensive income of $4.2 billion partially offset by returns to shareholders and lower 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, 2, 5 and 7 are listed on the TSX. On December 31, 2024, Cenovus exercised its right to redeem all 10.0 million of the Company’s series 3 preferred shares at a price of $25.00 per share, for a total of $250 million.
As at December 31, 2024, there were approximately 1,825.0 million common shares outstanding (December 31, 2023 – 1,871.9 million common shares) and 26.0 million preferred shares outstanding (December 31, 2023 – 36.0 million preferred shares). Refer to Note 27 of the Consolidated Financial Statements for further details. In 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. As at December 31, 2024, there were 2.0 million common shares held by the Trust.
As at December 31, 2024, there were approximately 3.6 million Cenovus Warrants outstanding (December 31, 2023 – 7.6 million Cenovus Warrants). 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 27 of the Consolidated Financial Statements for further details.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 40

Refer to Note 29 of the Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows:

As at February 14, 2025 | Units Outstanding (thousands) |  | Units Exercisable (thousands)
Common Shares | 1,823,629 |  | n/a
Cenovus Warrants | 3,631 |  | n/a
Series 1 First Preferred Shares | 10,740 |  | n/a
Series 2 First Preferred Shares | 1,260 |  | n/a
Series 5 First Preferred Shares | 8,000 |  | n/a
Series 7 First Preferred Shares | 6,000 |  | n/a
Stock Options | 8,890 |  | 4,999
Other Stock-Based Compensation Plans | 17,094 |  | 1,792

Common Share Dividends
In 2024, we paid base dividends of $1.3 billion or $0.680 per common share (2023 – $990 million or $0.525 per common share) and variable dividends of $251 million or $0.135 per common share (2023 – $nil).
On February 19, 2025, the Board declared a first quarter base dividend of $0.180 per common share. The dividend is payable on March 31, 2025, to common shareholders of record as at March 14, 2025.
The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.
Cumulative Redeemable Preferred Share Dividends
For the year ended December 31, 2024, dividends of $45 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (2023 – $36 million).
On February 19, 2025, the Board declared a first quarter dividend on the series 1, 2, 5 and 7 preferred shares for a total of $6 million, payable on March 31, 2025, to preferred shareholders of record as at March 14, 2025.
The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly.
Share Repurchases
We had an NCIB program to purchase up to 133.2 million common shares from November 9, 2023, to November 8, 2024.
On November 7, 2024, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 127.5 million common shares during the period from November 11, 2024, to November 10, 2025.

|  |  |  |  | 2024 |  | 2023
Common Shares Purchased and Cancelled Under NCIB (millions of common shares) |  |  |  |  | 55.9 |  |  | 43.6 |
Weighted Average Price per Common Share ($) |  |  |  |  | 25.38 |  |  | 24.32 |
Purchase of Common Shares Under NCIB ($ millions) |  |  |  |  | 1,445 |  |  | 1,061 |

From January 1, 2025, to February 14, 2025, the Company purchased an additional 1.5 million common shares for $32 million. As at February 14, 2025, the Company can further purchase up to 124.9 million common shares under the NCIB.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 41

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 35 to the Consolidated Financial Statements.

As at December 31, 2024 |  |  |  |  |  |  |  |  |  |  |  |  |
($ millions) | 1 Year |  | 2 Years |  | 3 Years |  | 4 Years |  | 5 Years |  | Thereafter |  | Total
Commitments |  |  |  |  |  |  |  |  |  |  |  |  |
Transportation and Storage (1) (2) | 2,122 |  | 1,947 |  | 1,921 |  | 1,904 |  | 1,815 |  | 14,551 |  | 24,260
Product Purchases | 14 |  | — |  | — |  | — |  | — |  | — |  | 14
Real Estate | 63 |  | 63 |  | 61 |  | 59 |  | 63 |  | 532 |  | 841
Obligation to Fund HCML | 104 |  | 105 |  | 98 |  | 56 |  | 44 |  | 105 |  | 512
Other Long-Term Commitments | 411 |  | 191 |  | 187 |  | 158 |  | 117 |  | 589 |  | 1,653
Total Commitments | 2,714 |  | 2,306 |  | 2,267 |  | 2,177 |  | 2,039 |  | 15,777 |  | 27,280
Long-Term Debt (Principal and Interest) | 526 |  | 324 |  | 1,586 |  | 1,502 |  | 487 |  | 7,286 |  | 11,711
Decommissioning Liabilities | 203 |  | 289 |  | 286 |  | 283 |  | 318 |  | 6,301 |  | 7,680
Lease Liabilities (Principal and Interest) (3) | 538 |  | 446 |  | 378 |  | 339 |  | 306 |  | 2,606 |  | 4,613
Total Commitments and Obligations | 3,981 |  | 3,365 |  | 4,517 |  | 4,301 |  | 3,150 |  | 31,970 |  | 51,284

(1)Includes transportation commitments that are subject to regulatory approval or were approved but are not yet in service of $854 million (December 31, 2023 – $13.0 billion). Terms are up to 20 years on commencement.
(2)As at December 31, 2024, includes $1.8 billion related to transportation and storage commitments with HMLP (December 31, 2023 – $2.1 billion).
(3)Lease contracts related to office space, a pipeline, storage tanks, railcars, refining equipment, vessels, a natural gas processing plant, caverns, fleet vehicles, our commercial fuels network and other field equipment.
As at December 31, 2024, outstanding letters of credit issued as security for performance under certain contracts totaled $355 million (December 31, 2023 – $364 million).
Legal Proceedings
We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements.
Transactions with Related Parties
Husky Midstream Limited Partnership
Cenovus holds a 35 percent interest in HMLP. As the operator of the assets held by HMLP, we provide management services for which we recover shared service costs in accordance with our profit-sharing agreement. We are also the contractor for HMLP and construct its assets on a cost recovery basis with certain restrictions. For the year ended December 31, 2024, we charged HMLP $155 million for construction and management services (2023 – $160 million). We pay an access fee to HMLP for the use of its pipeline systems that are used by our blending business. We also pay HMLP for transportation and storage services. Access fees and transportation and storage services are based on contractually agreed rates with HMLP. For the year ended December 31, 2024, we incurred costs of $278 million for the use of HMLP’s pipeline systems, as well as for transportation and storage services (2023 – $295 million).
For the year ended December 31, 2024, the Company received $65 million of distributions from HMLP (2023 – $56 million) and paid $51 million in contributions (2023 – $62 million).
Husky-CNOOC Madura Ltd.
Cenovus holds a 40 percent equity interest in the jointly-controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture is recorded in (income) loss from equity-accounted affiliates.
For the year ended December 31, 2024, the Company received $107 million of distributions from HCML (2023 – $93 million) and paid $nil in contributions (2023 – $35 million).

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 42

RISK MANAGEMENT AND RISK FACTORS

Risk Governance
Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of our risks and is integrated with the Cenovus Operations Integrity Management System (“COIMS”). In addition, we continuously monitor our risk profile as well as industry best practices. The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Our risk management framework contains the key attributes recommended by the International Organization for Standardization (“ISO”) in its ISO 31000 – Risk Management Guidelines. The results of our ERM program are documented in consolidated risk reports presented to our Board as well as through regular updates.
Risk Factors
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 following discussion describes the financial, operational, regulatory, environmental, reputational, climate-change related and other risks to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks, have a material impact on, among other things, our business, financial condition, results of operations, cash flows, reputation, ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, ability to respond to changes in our operating environment, access to capital, cost of borrowing, access to liquidity, ability to fund share repurchases, dividend payments and/or business plans, fulfill our obligations and/or the market price of our securities. These factors should be considered when investing in securities of Cenovus.
Financial Risk
Commodity Prices
Our financial performance is significantly dependent on prevailing commodity prices. Prices for crude oil, refined products, natural gas, NGLs and other related products are impacted by a number of factors, including, but not limited to: global and regional supply of, and demand for, these commodities; the ability of producers and governments to replace reduced supply; processing and export capacity; export restrictions; domestic and global economic conditions; inflation and changes to interest rates; the impact of tariffs and responses thereto (including by governments, our trade partners and customers), which may include, without limitation, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S. or other measures; central bank policies; market competitiveness; the actions of OPEC and other oil exporting nations, including, but not limited to, compliance or non-compliance with quotas agreed upon by OPEC members and decisions by OPEC not to impose production quotas on its members; developments related to the market for these commodities; inventory levels of these commodities; seasonal trends; refinery availability; current and potential future environmental laws and regulations; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; prices and availability of alternate sources of energy; actions of domestic or foreign governments or regulatory bodies; enforcement of government or environmental laws and regulations; shifts or changes in governmental policy in the jurisdictions in which we conduct our business operations, development or exploration, or elsewhere; public sentiment towards the use of non-renewable resources; political instability and social conditions in countries producing these commodities; market access constraints and transportation restrictions or interruptions; terrorist threats; technological developments; economic sanctions; outbreak of a pandemic, or war or other international or regional conflict and any related government action or military exercise; the occurrence of natural disasters; and weather conditions.
The focus on the timing and pace of the transition to a lower-carbon economy and resulting trends will likely continue to affect global energy demand and usage, including the composition of the types of energy generally used by industry and individual consumers. Under certain aggressive low-carbon scenarios, potential demand erosion could contribute to commodity price fluctuations and structural commodity price declines. However, it is not currently possible to predict the timelines for, and precise effects of, the transition to a lower-carbon economy.
The financial performance of our oil sands operations could also be impacted by discounted or reduced commodity prices for our oil sands production relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell products to domestic and international markets, and the quality of crude oil produced. Of particular importance to us are condensate cost and supply, and the price differentials between bitumen and both light to medium crude oil and heavy crude oil. Bitumen is more expensive for refineries to process and therefore generally trades at a discount to the market price for light to medium crude oil and heavy crude oil which, along with higher condensate costs, can adversely affect our financial condition.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 43

The financial performance of our refining operations is impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to factors such as, but not limited to, access to price advantaged crude oil; incremental capacity at existing refineries; global and regional demand for refined products; and seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact on our business, results of operations, cash flows and financial condition.
All of these factors are beyond our control and can result in a high degree of both cost and price volatility.
Fluctuations in the commodity prices, associated price differentials, and refining margins may impact our financial condition, results of operations, cash flows, growth, access to capital, cost of borrowing, ability to meet guidance targets, the value of our assets, the level of shareholder returns and our ability to meet guidance targets, and maintain our business and fund projects. A substantial decline in these commodity prices or an extended period of low commodity prices may result in: an inability to meet all our financial obligations as they come due; a delay or cancellation of existing or future drilling, development or construction programs; curtailment in production; unutilized long-term transportation commitments; and/or low utilization levels at our refineries.
The commodity price risks noted above, as well as other risks such as market access constraints and transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully described herein, may have a material impact on our business, financial condition, results of operations, cash flows and reputation, and may be considered indicators of impairment. Another potential indicator of impairment is the comparison of the carrying value of our assets to our market capitalization.
As discussed in this MD&A, we conduct an assessment, at each reporting date, of the carrying value of our assets in accordance with IFRS Accounting Standards. If crude oil, refined product, natural gas and NGL prices decline significantly and remain at low levels for an extended period, or if the costs to develop such resources significantly increase, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.
Risks Associated with Uncertainty Surrounding Recently Announced U.S. Tariffs on Canada and Potential Retaliatory Measures
On February 1, 2025, President Trump signed an executive order (the “Executive Order”) imposing a 25 percent tariff on all goods originating in Canada and imported into the U.S. and a 10 percent tariff on “energy and energy resources” from Canada, effective on February 4, 2025. The Executive Order also states that, if Canada introduces retaliatory measures, such as through the imposition of import duties on U.S. exports to Canada (or other similar measures), the U.S. tariffs may be increased or expanded. In response, the Government of Canada imposed 25 percent tariffs on $155.0 billion in goods imported from the U.S., coming into effect in two phases starting on February 4, 2025. Provincial governments across Canada have also responded to the U.S. tariffs, in some cases introducing their own retaliatory measures. On February 3, 2025, Canada and the U.S. agreed to delay the imposition of their respective tariffs on imported goods for 30 days. President Trump has also suggested that a new economic deal may be structured with Canada, though the scope and terms of such a deal, if any, are unknown.
Although discussions continue regarding a potential economic arrangement between the two countries, there remains significant uncertainty over whether tariffs, surtaxes, or other restrictive trade measures or countermeasures will ultimately be implemented and, if so, the scope, impact, and duration of any such measures. Potential measures could include, among others, increased tariffs on Canadian energy exports, restrictions on cross-border supply chains, or additional regulatory barriers that could impact our ability to access international markets and conduct business efficiently.
Restrictive trade measures or countermeasures, if implemented for any period of time, could have a significant impact on the market for crude oil, NGLs, natural gas and refined petroleum products in Canada and internationally and could result in, among other things, a high degree of both cost and price volatility, a relative weakening of the Canadian dollar, widening differentials, and decreased demand for our products and services. Any or all of such effects may have a material adverse impact on our business, results of operations and financial condition.
Additionally, retaliatory measures imposed on our products could reduce our ability to compete in the global market. We also rely on the importation of specialized equipment, raw materials and technology from various global suppliers. Any increase in tariffs on these goods could lead to higher costs for these essential inputs, thereby having a negative effect on our financial position and cash flows.
Risks Associated with Financial Risk Management Activities
Our Board-approved Market Risk Management Policy allows Management to use approved derivative financial instruments as needed, within authorized limits, to help mitigate the impact of changes in crude oil and condensate prices and differentials, NGL and natural gas spreads, basis and prices, electricity prices, refined product and crack spread margins, as well as fluctuations in foreign exchange and interest rates. We may also use derivative instruments in various operational markets to help optimize our supply costs or sales of our production, or fixed-price commitments for the purchase or sale of crude oil, refined products, natural gas, NGLs and other related products.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 44

Notwithstanding the anticipated benefits of undertaking these risk management activities, the use thereof may expose us to risks which may cause significant loss, including risks related to: changes in the valuation of the risk management instrument being poorly correlated to the change in the valuation of the underlying exposures; change in price of the underlying commodity or market value of the instrument; lack of market liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the unenforceability of contracts; and any inability to fulfill our delivery obligations related to the underlying physical transaction. These financial instruments may also limit the benefit to us of commodity prices, interest or foreign exchange rates change.
For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 32, 33 and 36 of the Consolidated Financial Statements.
Impact of Financial Risk Management Activities
Cenovus may employ various price alignment and volatility management strategies, including financial risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.
Transactions typically span across numerous time periods. As such, these transactions reside across both realized and unrealized risk management. As the financial contracts settle, they will flow from unrealized to realized risk management gains and losses.
The discussion below summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the price fluctuations identified below are a reasonable measure of volatility. The impact of the below on the Company’s open risk management positions could result in an unrealized gain (loss) impacting earnings before income tax as follows:

As at December 31, 2024 | Sensitivity Range | Increase |  | Decrease
Crude Oil and Condensate Commodity Price | ± US$10.00/bbl Applied to WTI, Condensate and Related Hedges | — |  | —
Crude Oil and Condensate Differential Price (1) | ± US$2.50/bbl Applied to Differential Hedges Tied to Production | 20 |  | (20)
WCS (Hardisty) Differential Price | ± US$2.50/bbl Applied to WCS Differential Hedges Tied to Production | (6) |  | 6
Refined Products Commodity Price | ± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges | (3) |  | 3
Natural Gas Commodity Price | ± US$0.50/Mcf Applied to Natural Gas Hedges Tied to Production | — |  | —
Natural Gas Basis Price | ± US$0.25/Mcf Applied to Natural Gas Basis Hedges | 1 |  | (1)
Power Commodity Price | ± C$10.00/MWh (2) Applied to Power Hedges | 46 |  | (46)
U.S. to Canadian Dollar Exchange Rate | ± $0.05 in the U.S. to Canadian Dollar Exchange Rate | 24 |  | (28)

(1)Excluding WCS at Hardisty.
(2)One thousand kilowatts of electricity per hour (“MWh”).
For further information on our risk management positions, see Notes 32 and 33 of the Consolidated Financial Statements.
Credit, Liquidity and Availability of Future Financing
The future development of our business may be dependent on our ability to access external capital, including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn or significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations or investor or lender policy or sentiment, may impede our ability to secure and maintain cost-effective financing.
Our ability to access capital and secure insurance coverage, at reasonable costs, or at all, may be adversely affected in the event that investors, insurers, or other relevant stakeholders adopt more restrictive decarbonization policies, we fail to achieve our GHG emissions reduction goals, or it is perceived that our GHG emissions reduction goals are insufficient or will not be achieved.
An inability to access capital on terms acceptable to us, or at all, could affect our ability to make future capital expenditures, to maintain desirable financial ratios and to meet our financial obligations as they come due, potentially resulting in a material adverse effect on our business, financial condition, results of operations, cash flows, ability to comply with various financial and operating covenants, credit ratings and reputation.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, regulatory, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, we may take actions such as: reducing or suspending share repurchases and/or dividends; reducing or delaying business activities, investments or capital expenditures; selling assets; restructuring or refinancing our debt; or seeking additional capital that could have less favourable terms.

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We are required to comply with various financial and operating covenants under our credit facility and the indentures governing our debt securities. Non-compliance with these covenants may lead to restrictions on access to capital or accelerated repayment.
Credit Ratings
A downgrade in any of our credit ratings, particularly a downgrade below investment grade ratings, a negative change in the Company's credit ratings outlook, or the withdrawal of a rating by a rating agency, could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital, and our business relationships with counterparties, operating partners and suppliers. Credit ratings are based on our financial and operational strength and several factors not entirely within our control, including, but not limited to, conditions affecting the crude oil, natural gas, NGL and refining industry generally, industry risks associated with the transition to a lower-carbon economy, government policies and the general state of the economy.
If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post additional collateral in the form of cash, letters of credit or other financial instruments to establish or maintain business arrangements. Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated.
Exposure to Counterparties
In the normal course of business, we enter contractual relationships with suppliers, partners, lenders, customers and other counterparties. If such parties do not fulfill their contractual obligations on a timely basis or at all, we may suffer financial losses or delays to our development plans, or we may have to forego other opportunities, all of which could materially impact our business, results of operations and financial condition.
Foreign Exchange Rates
Cenovus’s revenues are predominantly based on U.S. dollar benchmark prices, and a significant portion of our long-term debt and interest expense is denominated in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. Fluctuations in foreign exchange rates, particularly the U.S./Canadian dollar and RMB/Canadian dollar, may affect our results and could have a material adverse effect on our cash flows and financial condition.
Interest Rates
Interest rate fluctuations may have a material adverse impact on Cenovus’s results upon the refinancing of maturing long-term debt or when new debt financing is required. We are also exposed to changing interest rates on existing credit facilities that may be used to support our liquidity needs. Changes in interest rates can also impact how certain liabilities are recorded. These factors could impact Cenovus’s financial results.
Dividend Payments and Purchase of Securities
The payment of dividends, whether base, variable or preferred, the continuation of our dividend reinvestment plan and any potential purchase by Cenovus of our securities is at the discretion of our Board and is dependent upon, among other things, financial performance, debt covenants, satisfying solvency tests, our ability to meet financial obligations as they come due, working capital requirements, future tax obligations, future capital requirements, commodity prices and other risks identified in the Risk Management and Risk Factors section of this MD&A. Specifically, in connection with Cenovus’s capital allocation framework, the Company will target returns to shareholders and steward to Net Debt of $4.0 billion, as described in this MD&A. The frequency and amount of variable dividend payments, if any, may vary significantly over time as a result of our Net Debt and Excess Free Funds Flow, amount of share buybacks and other factors inherent with our capital allocation framework from time to time, including Management’s discretion to accelerate, defer or reallocate any Excess Free Funds Flow to shareholder returns between quarters. Our Net Debt and Excess Free Funds Flow may vary from time to time as a result of, among other things, our business plans, results of operations, financial condition and impact of any of the risks identified in the Risk Management and Risk Factors section of this MD&A. The Company can provide no assurance that it will continue to pay base or variable dividends or authorize share buybacks at the current rate or at all as the capital allocation framework, and any share repurchases and payment of dividends thereunder, remains at the discretion of our Board and is dependent on, among other things, the factors described above. Further, the individual or aggregate amount of base or variable dividends, if any, paid by Cenovus from time to time may result in adjustments to the exercise price and the exchange basis (the number of common shares received for each Cenovus Warrant exercised) of the Cenovus Warrants under the terms of the indenture governing the Cenovus Warrants. Such adjustments may impact the value received by Cenovus upon the exercise of Cenovus Warrants and may result in additional issuances of common shares on the exercise of Cenovus Warrants which may have a further dilutive effect on the ownership interest of shareholders of Cenovus and on Cenovus’s earnings per share.

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Disclosure Controls and Procedures (“DC&P”) and Internal Control Over Financial Reporting (“ICFR”)
Based on their inherent limitations, DC&P and ICFR may not prevent or detect misstatements, and even those controls determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on our business, financial condition, results of operations, cash flows and reputation.
Operational Risk
Operational Considerations (Safety, Environment and Reliability)
Our operations are subject to risks generally affecting the oil and gas, and refining industries and normally incidental to: (i) the storing, transporting, processing and marketing of crude oil, refined products, natural gas, NGLs and other related products; (ii) the drilling and completion of onshore and offshore crude oil and natural gas wells; (iii) the operation and development of crude oil and natural gas properties; (iv) the operation of refineries, terminals, pipelines and other transportation and distribution facilities in or regional evacuation alerts or orders issued by provincial or regional authorities over the jurisdictions in which we conduct operations, development or exploration, including at facilities operated by our partners or third-parties; and (v) the development and operation of projects relating to our GHG emissions reduction goals, including carbon capture, utilization and storage projects. These risks include, but are not limited to: the effects of government actions, laws or regulations, policies and initiatives, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration; encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; flooding; geologic activity arising from fracking or carbon capture, utilization and storage projects; explosions; blowouts; loss of containment; gaseous leaks; power outages; migration of harmful substances into water systems; releases or spills, including releases or spills from offshore operations, shipping vessels or other marine transport incidents; aviation, railcar or road transportation incidents; iceberg incidents; accidents or damage caused by third parties or otherwise occurring in the operation of our business; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or operate within established operating parameters; adverse weather conditions; corrosion; pollution; freeze-ups and other similar events; the breakdown or failure of equipment, pipelines, facilities, wells and projects; the breakdown or failure of operational and information technology and systems and processes, any compromise thereof or released data; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; failure to maintain adequate supplies of spare parts; operator error; shortages of skilled labour; labour disputes and strikes; disputes with owners or operators of interconnected facilities and carriers; planned or unplanned operational disruptions or apportionment on third-party systems or refineries, which may prevent the full utilization of such party’s facilities and pipelines; spills at truck terminals and hubs; spills associated with the loading and unloading of potentially harmful substances; loss of product; unavailability of feedstock; price and quality of feedstock; epidemics or pandemics; protests, blockades or other acts of activism; geopolitical factors, war, vandalism or terrorism, or other regional or international conflict; other catastrophic events, including, but not limited to, adverse sea conditions, extreme weather events, wildfires and natural disasters and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites.
Climate change may result in an increased level of operational risk requiring increased or additional mitigation measures. Systemic climatic changes or extreme climatic conditions may increase our exposure to, and magnitude of, the impact of physical climate risks, such as floods, drought, wildfires, earthquakes, hurricanes, typhoons, storms, extreme temperatures and other extreme weather events or natural disasters. Severe weather conditions may result in an operational incident with the potential to result in spills, asset damage and production, refining disruption or safety and reliability of operations.
If any such risks materialize, they may: interrupt operations; impair our ability to achieve our ESG goals, including our GHG emissions reduction goals; cause loss of life or personal injury; result in loss of or damage to equipment, property, operational and information technology and control systems and data, which may result in reduced revenue from reduced capacity or business interruption, or increased costs related to asset repair; cause environmental damage that may include polluting water, land or air; cause reputational damage; and may result in regulatory action, fines, penalties, civil suits or criminal or regulatory charges against us, any of which may have a material adverse effect on our business, financial condition, results of operations, cash flows and reputation.
We maintain a comprehensive insurance program in respect of our assets and operations. However, not all potential occurrences and disruptions in respect of our assets or operations are insured or are insurable, and we cannot guarantee that our insurance coverage will be available or sufficient to fully cover any claims that may arise from such occurrences or disruptions. The occurrence of an event that is not fully covered by our insurance program could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Market Access Constraints and Transportation Restrictions
Our production is transported through, and our refineries are reliant on, various pipelines and terminals, as well as rail, marine and truck networks, to transport feedstock and refined products to and from third-party, or Cenovus, owned and/or operated, facilities. The impacts of tariffs (and any responses thereto, including, without limitation, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S. or other measures) or disruptions in, or restricted availability of, pipeline, terminal, marine, rail or truck transport systems could limit the ability to deliver production volumes and adversely affect commodity prices, sales volumes and/or the prices received for our products, projected production growth, upstream or refining operations and cash flows. These interruptions and restrictions may be caused or intensified by, among other things, the inability of the pipeline or marine, rail or truck networks to operate, or may be related to capacity constraints if supply into the system exceeds the infrastructure capacity. There can be no certainty that third-party pipeline projects for new or expanded capacity will be approved or constructed or that such projects would provide sufficient transportation capacity.
There is no certainty that rail, marine and truck transport and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, our rail, marine and truck shipments may be impacted by service delays, labour disputes or strikes, shortages of skilled labour, inclement weather, vessel, railcar or truck availability, geopolitical factors, war, terrorism, or other international or regional conflict, or other rail, marine or truck transport incidents and could adversely impact sales volumes or the price received for product, or impact our reputation or result in legal liability, loss of life or personal injury, loss of equipment or property or environmental damage. In addition, rail, marine and trucking laws and regulations are constantly being reviewed to ensure the safe operation of the supply chain. Should regulations change, the costs of complying with those regulations will likely be passed on to shippers and may adversely affect our ability to transport by rail, marine or truck transport or the economics associated with such transportation. Finally, planned or unplanned shutdowns, outages or closures of our refineries or third-party systems or refineries may limit our ability to deliver product with negative implications on our business, financial condition, results of operations and cash flows.
Reserves Replacement and Reserve Estimates
If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves. Exploring for, developing or acquiring reserves is capital intensive. To the extent our cash flow is insufficient to fund capital expenditures and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and expand our crude oil and natural gas reserves will be impaired. In addition, we may be unable to find and develop or acquire additional reserves to replace our crude oil and natural gas production at acceptable costs.
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and associated future net cash flows and revenue are based on a number of variable factors and assumptions including, but not limited to: geological and engineering estimates; product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes, and environmental and emissions-related laws and regulations and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary materially from estimates.
All of such estimates are uncertain, and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, taxes, and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material.
Estimates with respect to reserves that may be developed and produced in the future are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based on production history will result in variations, which may be material, in the estimated reserves.
The production rate of oil and gas properties tends to decline as reserves are depleted while the associated operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce crude oil, refined products, natural gas, NGLs and other related products; drilling success; completing long-lead time capital intensive projects on budget and on schedule; and the application of successful exploitation techniques on mature properties. Our business, reputation, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves.

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Cost Management and Inflation
Development, operating and construction costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies, including those related to our GHG emissions reduction goals; inflationary price pressure; changes in regulatory compliance costs; scheduling delays; interruptions to existing market access infrastructure; failure to maintain quality construction and manufacturing standards; equipment limitations, including the cost or availability of oil and gas field equipment; commodity prices; higher steam-oil ratios in our Oil Sands operations; changing government or environmental policies, laws and regulations; supply chain disruptions, including force majeure; and access to skilled labour and critical third-party services. Such higher costs may not be fully offset through corresponding increases in commodity prices and other sources of funding. Inflation and any governmental response thereto, such as the imposition of higher interest rates or wage controls, our inability to manage costs, or our inability to secure equipment, materials, skilled labour or third-party services necessary to our business activities for the expected price, on the expected timeline, or at all, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Technology, Information Systems and Data Privacy
We rely heavily on technology, including operating technology and information technology, to effectively operate our business. This includes on-premise systems (such as networks, computer hardware and software), telecommunications systems, mobile applications, cloud services and other technology systems, networks and services, including systems using artificial intelligence. Some systems and services are provided by third-parties. In the event we are unable to access, use, rely upon, adequately secure, upgrade and take other steps to maintain or improve the efficiency, resiliency and efficacy of such systems and services, the operation of such systems and services could be interrupted, resulting in operational interruptions or the loss, corruption or release of data.
In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary information, business information and personal data. Despite our security measures, our technology systems, infrastructure and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties), disruptions from staff or third-party error, malfeasance, natural disasters, acts of state or industrial espionage, activism, terrorism, war, regional or international conflict, or the geopolitical landscape. These risks also include, but are not limited to, cyber-related fraud or attacks such as attempts to circumvent electronic communications controls, attempts to impersonate internal personnel or business partners to divert payments and financial assets to accounts controlled by the perpetrators, or attempts to introduce ransomware into one or more systems or services to extract a payment, preventing access to systems, among others.
Any such incident, breach, or disruption of our internal or our third-party service providers’ technology systems or services, or other vendor technology systems and services (including where a threat actor is successful in bypassing our cyber-security measures and business process controls), could result in loss or the exposure of internal, confidential, business, financial, proprietary, personal or other sensitive data.
The rapid emergence and continuous evolution of generative artificial intelligence tools may exacerbate the Company’s technology, information systems and data privacy-related risks due to its potential for user misuse, biased decision-making or unauthorized exposure of Cenovus’s sensitive data.
Cyber incidents, privacy or security breaches or irresponsible use of technology or data, including through the irresponsible use of or reliance upon artificial intelligence tools, could result in business interruption, theft or misuse of confidential information, financial losses, remediation and recovery costs, legal claims or proceedings, liability under laws that govern data, its processing, or the decisions that may arise from same (including laws related to the use of artificial intelligence, cybersecurity, data collection and protection and privacy), regulatory penalties or fines (if such penalties or fines are authorized under the relevant legislation), operational disruption, site shut-down, leaks or other negative consequences, including damage to our reputation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The regulation of the use of technology is rapidly evolving across many of the jurisdictions in which we conduct operations, development or exploration, creating a complex legal and regulatory framework, including existing and proposed laws and regulations that govern data, data processing and related tools, data transfers, artificial intelligence, data collection and protection and privacy. These laws and regulations impose obligations on companies that process personal data and provide additional rights of actions and remedies to individuals whose personal data is in the Company’s control.
Failure to comply with laws and regulatory standards governing cybersecurity, data collection and protection and privacy, including the misuse of or failure to adequately secure and protect personal data, that impact the use of artificial intelligence, could result in, without limitation; criminal, administrative and civil liabilities proceedings against the Company by governmental entities or others; imposition of severe fines and penalties (if such fines and penalties are authorized under the relevant legislation); damage to our reputation and credibility; and may have a negative impact on our financial condition, results of operations and cash flows. Compliance with continuously evolving legislation may also result in increased operating costs.

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Competition
We compete with other producers, refiners and marketers in all aspects, including access to capital, the exploration and development of new and existing sources of supply, the acquisition of crude oil and natural gas interests, and the refining, distribution and marketing of oil and gas products. Competitors may have lower operating/capital costs or higher quality resource inventory than Cenovus does, may develop and implement technologies and business practices which are superior to those we employ, and/or may assemble portfolios that generate stronger financial returns than Cenovus does, reducing our ability to compete. The crude oil, natural gas, NGL and refining industry also competes with other industries in supplying energy, fuel and related products to consumers, including renewable energy sources which may become more prevalent in the future. We may not be able to compete successfully against current and future competitors, and competitive pressures could have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows.
Project Execution
We manage a variety of growth and optimization projects across our global portfolio of assets. In addition, we have a number of other projects in various stages of planning and development, including maintenance and turnaround projects, and projects related to our GHG emissions reduction goals. The wide range of risks associated with project development and execution, as well as the commissioning and integration of new facilities with existing assets, can impact the economic viability of our projects. These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory approvals; our ability to obtain favourable contract terms or to be granted access within land-use agreements; our ability to access, implement and use operational and information technologies and data, including improvements thereto; risks relating to schedule, contractor performance, engineering and design, transportation and installation of project components, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of supply chain disruptions; the impact of general economic, business and market conditions including inflationary pressures; the impact of weather conditions; risk related to the accuracy of project cost estimates; our ability to finance capital expenditures and expenses on a cost effective basis; our ability to identify or complete strategic transactions; and the effect of changing government laws and regulations, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration; and public expectations in relation to the impacts of oil and gas operations on the environment and those associated with GHG emissions abatement initiatives. The commissioning and integration of new infrastructure and facilities within our existing asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could affect our safety and environmental record and have a material adverse effect on our financial condition, results of operations, cash flows and reputation.
Joint Ventures and Partnerships
Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures and we are, at times, dependent upon our partners for the successful execution and operation of various projects and assets, their management of operational issues and their reporting. In addition, certain of our projects under development, including those related to our GHG emissions reduction goals, are expected to be constructed and operated in collaboration with third parties. Therefore, our results of operations, cash flows and progress towards our GHG emissions reduction goals may be affected by the actions of third-party operators or partners in areas where our ability to control and manage risks may be reduced.
Our partners may have objectives and interests that either do not align with, or may conflict with, our interests. No assurance can be provided that our future demands or expectations relating to such assets and projects will be satisfactorily met in a timely manner or at all. If a dispute with a partner or partners were to occur over the development and operation of a project, or if a partner or partners were unable to fund their contractual share of the capital expenditures, a project could be delayed, and we could be partially or totally liable for our partner’s or partners’ share of the project. Should one of our partners become insolvent, we may similarly be directed by applicable regulators to carry out obligations on behalf of our partner or partners and may not be able to obtain reimbursement for these costs. Failure to manage these partner risks could have a material adverse effect on our business, financial condition, results of operations, progress towards our GHG emissions reduction goals, reputation and cash flows.
Existing and Emerging Technologies
Current technologies used for the recovery of bitumen are energy intensive, including SAGD which requires significant consumption of natural gas in the production of steam used in the recovery process. The amount of steam required in the recovery process varies and therefore impacts costs. The performance of the reservoir affects the timing and levels of production using SAGD technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial condition, results of operations and cash flows. In addition, we depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business goals including our ESG goals. Limitations related to the development, adoption and success of these technologies or the development of disruptive technologies could have a negative impact on our long-term business resilience.

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Governmental Policy
Shifts in government policy by new or existing administrations in jurisdictions in which we conduct operations, development or exploration or elsewhere can impact our operations and ability to grow our business. Restrictions on fossil fuel-based energy use, cross-border economic activity (including the imposition of tariffs by foreign governments impacting our business and any governmental responses thereto, including, without limitation, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S. or other measures), and development of new infrastructure can impact our opportunities for continued growth.
We are committed to working with all levels of government in the jurisdictions in which we conduct business operations, development or exploration to ensure we remain competitive, risks are understood and mitigation strategies are implemented; however, we cannot guarantee the outcomes of changes in government policy which may adversely affect our business, results of operations, financial condition or reputation.
Regulatory Risk
The crude oil, natural gas, NGL and refining industry in general and our operations in particular are subject to regulation and intervention under various levels of legislation in the countries in which we operate, seek to develop or explore. Regulated areas of our operations include, but are not limited to: land tenure; permitting of projects; royalties; taxes (including income taxes and tariffs); government fees; production rates; environmental protection; occupational and process safety management; protection of certain species or lands; cumulative effects and/or impacts from all types of industrial development; environmental plans, laws and regulations; the reduction of GHG and other emissions; the export of crude oil, refined products, natural gas, NGLs and other related products; the transportation of crude oil, refined products, natural gas, NGLs and other related products by pipeline, rail, marine or truck transport; generation, handling, storage, transportation, treatment and disposal of hazardous substances; the awarding, acquisition and maintenance of exploration, development and production rights; the imposition of specific drilling obligations; control over the development, abandonment, remediation and reclamation of fields (including restrictions on production) and/or facilities; and possible expropriation or cancellation of contract rights. See “Environmental Plans and Regulations Risks” below. Any changes to applicable regulatory regimes, including the implementation of new laws or regulations or enforcement initiatives, repeal of any existing laws or regulations, or the modification or changed interpretation of existing laws or regulations, could impact our existing and planned projects requiring increased capital investment, operating expenses or compliance costs, which could adversely impact our financial condition, results of operations, cash flows and reputation.
Regulatory Approvals
Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that we will be able to obtain, and maintain on acceptable conditions, or at all, all necessary licences, permits and other approvals required to conduct activities (including, without limitation, certain exploration, development and operating activities) related to our projects. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder consultation, Indigenous consultation (including consensus seeking, collaboration or consent), environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; environmental and habitat assessments; and other commitments or obligations. The failure to obtain applicable regulatory approvals or satisfy any conditions on a timely basis or satisfactory terms could result in increased costs, project delays and may limit Cenovus’s ability to develop or expand proposed projects efficiently or at all.
Decommissioning
We are subject to oil and gas asset decommissioning, abandonment, remediation and reclamation (“Decommissioning”) liabilities for our operations, development and exploration, including those imposed by regulation under various levels of legislation in the jurisdictions in which we conduct operations, development or exploration.
We maintain estimates of our Decommissioning liabilities; however, it is possible that these costs may change materially before Decommissioning due to regulatory changes, technological changes, ecological risks, acceleration of Decommissioning timelines and inflation, among other variables.
We have an ongoing environmental monitoring program of owned and leased retail locations, and former owned or leased retail locations where we have retained environmental liability, and perform remediation where required to comply with contractual and legal obligations. The costs of such remediation may not be determinable due to the unknown timing and extent of corrective actions that may be required.

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The impact on our business of any legislative, regulatory or policy decisions relating to the Decommissioning liability regulatory regimes in the jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated and may be affected by changes in governmental policy, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration. Any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and could materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows.
Royalty Regimes
Our cash flows may be directly affected by changes to royalty and mineral tax regimes. The governments of the jurisdictions where we have producing assets receive royalties on the production of hydrocarbons from lands in which they respectively own the mineral rights and which we produce under agreement with each respective government. Government regulation of royalties and mineral tax is subject to change for a number of reasons, including, among other things, political factors. In Canada, there are certain provincial mineral taxes payable on hydrocarbon production from lands other than Crown lands. The potential for changes in the royalty and mineral tax regimes applicable in the jurisdictions in which we conduct operations, development or exploration, or changes to how existing royalty and mineral tax regimes are interpreted and applied by the applicable governments, creates uncertainty relating to the ability to accurately estimate future royalty rates or mineral taxes and could have a significant impact on our business, financial condition, results of operations and cash flows. An increase in the royalty rates or mineral taxes in jurisdictions where we have producing assets would reduce our earnings and could make, in the respective jurisdiction, future capital expenditures or existing operations uneconomic and may reduce the value of our associated assets.
Indigenous Land and Rights Claims
Opposition by Indigenous people and communities to our Company, operations, activities, development or exploration, or disagreements between Indigenous communities, or between Indigenous people and governments, in the jurisdictions in which we conduct operations, development or exploration may adversely impact our reputation and our relationships with host governments, local communities and other Indigenous communities. Other impacts may include diversion of Management’s time and resources, increased legal, regulatory and other advisory expenses, and impeding our ability to explore, develop and continue to operate projects.
In Canada, Aboriginal and/or treaty rights held by Indigenous people are protected under the Constitution. Impacts to these Indigenous and/or treaty rights must be considered, in particular, in areas where Cenovus operates on Crown lands.
The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect the asserted or proven Indigenous rights or affect treaty rights and, in certain circumstances, accommodate their interests. In some jurisdictions, the Crown delegates consultation responsibilities to proponents. The fulfillment of the duty to consult Indigenous people, and any associated accommodations, may adversely affect our ability to, or increase the timeline to, obtain or renew permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals. Failure to adequately consult can lead to project delays, legal challenges, or damage to our reputation.
In addition, the Canadian federal government, the British Columbia provincial government and the Northwest Territories territorial government have passed legislation which requires such governments to take all necessary measures to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). The means and timelines associated with UNDRIP’s implementation by governments is ongoing and, in some instances, uncertain: additional processes have been and are expected to continue to be created, or legislation amended or introduced associated with project development and operations, further increasing uncertainty with respect to project regulatory approval timelines and requirements.
Climate Change-Related Risks
There is international concern regarding climate change and a significant focus on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, non-governmental organizations (“NGOs”), environmental and governance organizations, rating agencies, institutional investors, social and environmental activists, shareholders and individuals are seeking to implement, among other things, regulatory and policy changes, changes in investment patterns, and modifications in energy consumption habits and trends which, individually and collectively, are intended to, or have the effect of, accelerating the reduction in the global consumption of fossil fuel-based energy, the conversion of energy usage to less carbon-intensive forms and the general migration of energy usage away from fossil fuel-based forms of energy. A transition to a lower carbon economy could increase the demand for lower emissions and alternative energy sources. Changes in customer behaviour related to reduced energy consumption could impact Cenovus’s customers and in turn, the demand for Cenovus’s services. Transition to a lower carbon economy could also pose a risk to Cenovus if it is unable to diversify its operations on pace with such a transition.

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Climate change and its associated impacts may increase our exposure to, and magnitude of, each of the risks identified in the Risk Management and Risk Factors section of this MD&A. Overall, we are not able to estimate at this time the degree to which climate change-related regulatory, climatic conditions and climate-related transition risks could impact our business, financial condition and results of operations. Our business, financial condition, results of operations, cash flows, reputation, regulatory approvals, access to capital and insurance, cost of borrowing, ability to fund dividend payments and/or business plans may, in particular, without limitation, be adversely impacted as a result of climate change and its associated impacts.
Climate Change Regulations
We operate in several jurisdictions that regulate or have proposed to regulate GHG emissions, often with a view to transitioning to a lower-carbon economy. Some of these regulations are in effect, while others remain in various phases of review, discussion or implementation. Uncertainties exist relating to the timing and effects of these emerging regulations and other contemplated legislation, including how they may be harmonized, making it difficult to accurately determine the cost impacts and changes which may occur as a result of change in governmental policy, including as a result of new or existing administrations in the jurisdictions in which we conduct operations, development or exploration. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations, regulatory approvals and cash flows, which cannot be reliably or accurately estimated at this time.
The Government of Canada, under the Canadian Net-Zero Emissions Accountability Act, aims to reduce GHGs emissions by 40 percent to 45 percent below 2005 levels by 2030 and 45 percent to 50 percent by 2035. These targets are part of Canada's broader strategy to achieve net-zero emissions by 2050. Specific plans are not available, but the government is attempting to meet these targets through a number of measures including its economy wide price on carbon or carbon tax. The carbon tax will increase to $170/tonne CO2e by 2030, with the 2025 rate set at $95/tonne CO2e. To the extent a province's carbon pricing system does not meet the federal stringency requirements, the federal “backstop” regulations apply. Most of our Canadian-based large emitting facilities operate in jurisdictions where provincial carbon pricing regulations apply to industry. In British Columbia, the provincial carbon pricing system applies in full. In Alberta, Saskatchewan and Newfoundland and Labrador, the provincial carbon pricing systems apply in part. These provincial programs are expected to continue to meet the federal stringency requirements such that the federal backstop regulations do not apply.
In November 2024, the Government of Canada released its draft Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations under the Canadian Environmental Protection Act, 1999. As currently drafted, the regulations would come into force in 2026 with the first three-year compliance period beginning January 1, 2030. The regulation would apply to, among other things, all direct GHG emissions from upstream oil and gas facilities, including offshore facilities and bitumen upgraders. For the 2030-2032 compliance period, facilities will be required to reduce industry-wide emissions by 27 percent from 2026 levels. Under the proposed regime, facilities that emit more than the allowances allocated under the distribution rate formula would have some flexibility to cover up to 20 percent of their compliance obligations through a combination of payments into a decarbonization fund and federally recognized offset credits. Further allowances could be purchased from other operators, provided there is sufficient supply. Environment and Climate Change Canada has not provided substantive details regarding the cap level beyond 2032.
The Government of Canada has also implemented regulations to reduce methane emissions from the crude oil and natural gas sector. The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (“Methane Regulation”) are designed to achieve a 40 percent to 45 percent reduction from 2012 levels by 2025 through both requirements for fugitive equipment leaks and venting from well completion and compressors (which came into force on January 1, 2020), and restrictions on facility production venting restrictions and venting limits for pneumatic equipment (which came into force on January 1, 2023). In December 2023, the Government of Canada published draft amendments to the Methane Regulation to facilitate achieving an additional target to reduce oil and gas methane emissions by at least 75 percent below 2012 levels by 2030. The proposed regulatory amendments relate to venting, flaring, hydrocarbon gas destruction equipment and fugitive emissions, and would come into force between 2027 and 2030.
In the U.S., the Renewable Fuel Standard (“RFS”) was created to reduce GHG emissions and risks from that program are described below. Additionally, the federal Environmental Protection Agency (“EPA”) has and may continue to promulgate regulations concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program (“GHGRP”) requires any facility releasing more than 25,000 tonnes of CO2e emissions per year to report those emissions on an annual basis. In addition to reporting direct CO2e emissions, the GHGRP requires refineries to estimate the CO2e emissions from the potential subsequent combustion of the refinery’s products. The U.S. has a 2030 target to reduce GHG emissions by 50 percent to 52 percent from 2005 levels. It is expected that this target will be met largely through clean energy incentives introduced under the Inflation Reduction Act as opposed to regulatory measures.

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Changes in environmental and emissions regulation by governmental authorities could result in changes to facility design and operating requirements, potentially increasing the cost of construction, operation and abandonment. Other possible effects from emerging regulations may also include, but are not limited to: increased compliance costs; penalties; permitting delays; general shift away from fossil fuel-based energy; and substantial costs to generate or purchase emission credits or allowances, any of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be available on an economic basis, required emissions reductions may not be technically or economically feasible to implement, in whole or in part, and failure to have access to resources or technology to meet emissions reduction requirements or other compliance mechanisms may have a material adverse effect on our business resulting in, among other things, fines, permitting delays, penalties, shutting in production and the suspension of operations.
The extent and magnitude of any adverse impacts of current or additional programs or regulations cannot be reliably or accurately estimated at this time, in part because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the timeframes for compliance. Consequently, no assurances can be given that the effect of future climate change regulations will not be significant to us.
Clean Fuel Regulations
In Canada, the Clean Fuel Regulations came into force in June 2022. The aim of this regulation is to lower the GHG emissions from various liquid fossil fuels by requiring producers or importers of gasoline, diesel, kerosene and light and heavy fuel oils (“Primary Suppliers”) to lower the carbon intensity of such fuels. The regulation sets a baseline carbon intensity for each type of liquid fossil fuel, against which the Primary Suppliers must make annual carbon intensity reductions. The regulation could result in the negative consequences noted above under “Climate Change Regulations”, including increased compliance costs, increased operating costs and capital expenditures.
Low Carbon Fuel Standards
Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian provinces and territories, the Canadian federal government and members of the European Union regulating carbon fuel standards could result in increased compliance costs and a potential reduction in revenue. Existing and proposed regulations may negatively affect the marketing of our bitumen, crude oil or refined products (diesel and ethanol), and may require us to purchase low carbon fuel compliance credits in order to ensure compliance and support sales within such jurisdictions. These regulations have the potential to impact our business, financial condition, results of operations and cash flows.
Renewable Fuel Standards
Our U.S. Refining operations are subject to various laws and regulations that impose stringent and costly requirements. The EPA has implemented the RFS program which mandates that a certain volume of renewable fuels replace or reduce the quantity of certain petroleum-based transportation fuels sold or introduced in the U.S.
Cenovus and our refinery operating partners comply with the RFS by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market, where prices fluctuate. We cannot predict the future prices of RINs and renewable fuel blend stocks, and the costs to obtain the necessary RINs and blend stocks could be material. Our financial position, results of operations and cash flows may be materially impacted if we are required to pay significantly higher prices for RINs or blend stocks to comply with the RFS mandated standards.
Clean Electricity Regulations
In December 2024, the Government of Canada released final Clean Electricity Regulations intended to accelerate progress towards a near-zero power generation sector in Canada. The regulations will impose a limit on total emissions based on a stringent carbon intensity threshold and generation unit capacity and will come into effect on the latter of January 1, 2035 or 25 years after a facility’s commissioning date. The full extent of any adverse impacts of these regulations cannot be reliably or accurately estimated at this time.
Light-Duty Vehicle Greenhouse Gas Emission Standards
In March 2024, the U.S. EPA announced new, more stringent final standards to further reduce GHGs from light-duty to medium-duty vehicles starting with model year 2027. The new rule builds upon existing federal GHG emissions standards established in 2021 for passenger cars and light trucks for Model Years 2023 through 2026. The impact these standards may have on the future demand (and corresponding price levels) for our products is unknown and dependent upon a number of factors, including the outcome of legal challenges to the standards and the potential for EPA to reconsider them under the Trump administration. In addition, the Canadian federal government has published proposed regulated sales targets for electric vehicles.

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Climate Scenarios and Assumptions
We integrate the potential impact of climate change and GHG regulations, and the cost of carbon at various price levels into our business planning processes. To mitigate uncertainty surrounding future emissions regulation, we evaluate our development plans under a range of carbon-constrained scenarios. We have considered a number of globally recognized scenarios in our strategic planning for several years and conduct ongoing assessments of both public and private scenarios. Although Management believes that our climate-related estimates are reasonable, aligned with current, pending and potential future regulations, and informed by these external climate scenarios, they are based on numerous assumptions that, if false, may have a material adverse effect on our business, financial condition and results of operations. Specifically, climate-related estimates influence our financial planning and investment decisions. Since we plan and evaluate opportunities partially on the basis of climate-related estimates, variations between actual outcomes and our expectations may have a material adverse effect on our business, financial condition, results of operations, reputation and cash flows.
Labour Relations
We depend on unionized labour for the operation of certain facilities and may be subject to employee relations and labour disputes, which could disrupt operations at such facilities. As of December 31, 2024, approximately 11 percent of our employees were represented by unions under collective bargaining agreements, which includes just over 46 percent of our U.S. workforce. At unionized worksites, there is risk that strikes or work stoppages could occur. Any strike or work stoppage may have a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows.
In the event of a labour dispute, strike or work stoppage, mitigation and emergency operation plans may involve significant additional expenditures to ensure continuity of operations. In addition, we may not be able to renew or renegotiate collective bargaining agreements on satisfactory terms, or at all, and a failure to do so may increase our costs. Any renegotiation of our existing collective bargaining agreements may result in terms that are less favourable to us, which may materially and adversely affect our financial condition, results of operations and cash flows.
Moreover, future unionization efforts of Cenovus’s non-represented workforce or changes in legislation and regulations may result in labour shortages, higher labour costs, as well as wage, benefit, and other employment consequences, especially during critical maintenance and construction periods, all of which may have a material adverse effect on our safety and reliability performance, reputation, results of operations and cash flows and may limit our operational flexibility.
Leadership and Talent
Our success is dependent upon our leadership capabilities and the quality and competency of our workforce. If we are unable to attract and retain key personnel and critical and diverse talent with the necessary behaviours, leadership skills, and professional and technical competencies to drive our desired organizational and safety culture, it could have a material adverse effect on our business, safety performance, financial condition, results of operations and reputation. Failure to manage human resources risks may lead to financial and/or reputational loss, including loss arising from activity that is inconsistent with applicable employment laws.
Security and Terrorist Threats
Security threats and terrorist activities may impact our personnel, or those of partners, customers, and suppliers, which could result in injury, loss of life, extortion, hostage situations and/or kidnapping or unlawful confinement, destruction or damage to property of Cenovus or others, impact to the environment and business interruption. A security threat or terrorist attack targeted at a facility, terminal, pipeline, rail or trucking network, office or offshore vessel/installation owned or operated by Cenovus or any of our systems, services, infrastructure, market access routes, or partnerships could result in the interruption or cessation of key elements of our operations. The risk profile for security and terrorist threats may vary based on geography, international developments and geopolitical risk levels, and the outcomes of such incidents could have a material adverse effect on our business, financial condition, results of operations, cash flows and reputation.
International Developments and Geopolitical Risk
We are exposed to the financial and operational risks associated with operating in the Asia Pacific region. Our business includes both operated and non-operated assets in the South China Sea, and requires cooperation agreements with our partner China National Offshore Oil Corporation or its subsidiaries (collectively, “CNOOC”). Additionally, the Asia Pacific business includes non-operated assets offshore in the Indonesia Madura Straights as operated by HCML, whereby CNOOC is the operator of HCML.
Political developments impacting international trade, particularly between Canada and the U.S., the U.S. and China, Canada and China, and EU and China, including military exercises, trade disputes, new or increased tariffs, retaliatory tariffs, export taxes on Cenovus’s products, restrictions on exports to the U.S., sanctions and other measures, may negatively impact markets and cause weaker macroeconomic conditions or drive political or national sentiment, weakening demand for crude oil, refined products, natural gas, NGLs and other related products, which could materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows.

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We may be affected by changes to bilateral relationships, the frameworks and global norms that govern international trade and other geopolitical developments. This includes acute shocks (such as civil unrest or sanctions) and chronic stresses (such as political or business disputes, and other forms of conflict, including military conflict) that may pose longer-term threats to our business. Unilateral action by, or changes in relations between, countries in which we operate, including the U.S. and China, and such countries’ approaches to multilateralism and trade protectionism can impact our ability to access markets, technology, talent and capital. Disruptions or unanticipated changes of this nature may affect our ability to sell our products for optimum value or access inputs required for effective operations and have the potential to adversely affect our financial condition.
Increased tensions between the U.S. and China caused by military exercises around, or conflict involving, Taiwan and the South China Sea could lead to geopolitical uncertainty in the area, which may negatively impact our China business and operations, including by requiring us to curtail or suspend operations and reduce or shut in production, and ultimately affect our financial condition.
Moreover, our operations may be materially adversely affected by political, economic or social instability or events, including the renegotiation or nullification of agreements and treaties, the imposition of onerous regulations, embargoes, sanctions, and fiscal policy, changes in laws governing existing operations, financial constraints, including currency restrictions and exchange rate fluctuations, unreasonable taxation and the behaviour of international public officials, joint venture partners or third-party representatives. Specifically, our Asia Pacific assets expose us to the effects of the changing U.S.-China, Canada-China and EU-China relations.
In response to foreign sanctions, China has enacted multiple blocking laws intended to diminish the effectiveness and impact of foreign trade sanctions. Specifically, China has enacted regulations granting itself the ability to unilaterally nullify the effects of certain foreign restrictions that are deemed to be unjustified to Chinese nationals and entities. Additionally, China enacted the Anti-Foreign Sanctions Law which grants the right to take corresponding countermeasures if a foreign country violates international law and basic norms of international relations or adopts discriminatory restrictive measures against Chinese nationals and entities and interferes in China's internal affairs. The language of the Anti-Foreign Sanctions Law is very broad, and beyond the laws themselves, little guidance has been provided regarding how the blocking laws will be enforced by the Chinese government and effectuated through the private rights of action created by these laws. The breadth and lack of specificity of such laws create additional risk and uncertainty for foreign companies operating in China, as they may result in conflicting rules and regulations in home and host countries.
Although formal export restrictions imposed against China and Chinese entities (including the placement of CNOOC on the U.S. Department of Commerce’s Entity List) have not had a material impact on our business activities in Asia thus far, increased export restrictions on China and Chinese entities may limit the range of certain supplies to our operations in Asia and have an adverse effect on operational efficiency, results of operations, financial condition or reputation.
It is possible that additional related actions taken by the U.S. (and its trading partners and allies), Canada, China and other nations may limit or restrict foreign companies' ability to participate in projects and operate in certain sectors of the Chinese economy, including the energy sector. The nature, extent and magnitude of the effect of dynamic trade relations cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, and results of operations, cash flows and reputation.
U.S. and Canadian sanctions and trade controls related to China do not currently prevent or significantly impair our offshore operations in Asia, but they could do so in the future, particularly if U.S. sanctions and trade controls against CNOOC were to be expanded. We cannot accurately predict the implementation of U.S. or Canadian policy affecting any current or future activities by CNOOC, Cenovus's other international partners or Cenovus. Similarly, we cannot accurately predict whether U.S. restrictions will be further tightened or the impact of government action on Cenovus's offshore operations in Asia. It is possible that the U.S. or Canadian government may subject CNOOC or Cenovus's other international partners to restrictions or sanctions that may adversely impact our offshore operations in Asia.
In addition, to the extent there are business disputes or legal claims involving our business in China, there is the potential for Cenovus personnel to be subject to an entry/exit ban in China. Moreover, it is possible that, as a result of our partnership with CNOOC, we may be subject to negative media attention which may affect investors’ perception of Cenovus in Canada, the U.S. and globally, and which may negatively affect our share price and reputation.
Geopolitical events, such as a shift in the relationship, an escalation or imposition of sanctions, tariffs or other trade tensions between the U.S. and China, and Canada and China, may affect the supply, demand and price of crude oil, refined products, natural gas, NGLs and other related products and therefore our financial condition. The timing, extent and fallout of the ongoing tensions between the U.S. and China, as well as Canada and China, remain uncertain and the impact on our business is unknown.

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Shifts in global power relations may also introduce greater uncertainty with respect to issues requiring global co-ordination (such as climate change, trade agreements, tax regulation, freedom of navigation and technology regulation), as well as raise questions on the efficacy of and trust in international institutions, including those that underpin international trade. These types of changes may cause restrictions or impose costs on our business and may inhibit our future opportunities or affect our financial condition.
Our financial condition, operations and business may be adversely affected by any of the foregoing risks associated with international relations and specifically those risks arising from evolving U.S.-China, Canada-China and EU-China relations. The nature, extent and magnitude of the effect of dynamic trade relations on us cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, results of operations, cash flows and reputation.
Litigation and Claims
From time to time, we may receive demands or be involved in disputes, regulatory orders, investigations or proceedings, arbitrations and/or litigation (“Claims”) arising out of, or related to, our business, operations and/or contractual relationships. Claims may be material. Due to the nature of our business and operations, we may be subject to various types of Claims including, but not limited to, failure to comply with applicable laws and regulations such as those related to health and safety, climate change, competition, public statements and marketing, the environment, including environmental claims, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, derivative actions, patent infringement, privacy, employment, human rights, labour relations, personal injury and other Claims.
In recent years there has been an increase in climate change-related demands, disputes and litigation in various jurisdictions including the U.S. and Canada. While many of the climate change-related actions are in preliminary stages of litigation, and in some cases assert novel or untested causes of action, there can be no assurance that legal, societal, scientific and political developments will not increase the likelihood of successful climate change-related litigation against energy producers, like Cenovus. We may be subject to adverse publicity associated with such matters, which may negatively affect public perception and our reputation, regardless of whether we are ultimately found responsible.
We may be required to incur substantial expenses and devote significant resources in respect of any such Claims. In addition, any such Claims could result in unfavourable judgments, decisions, fines, sanctions, penalties, monetary damages, temporary or permanent suspensions of operations or restrictions on our business. The outcome of any such Claims can be difficult to assess or quantify and may have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows.
Environmental Plans and Regulations Risks
All phases of our operations are subject to environmental regulation, oversight and enforcement pursuant to a variety of laws and regulations imposed by various levels of governments in the jurisdictions in which we conduct operations, development or exploration, including land management plans, laws and regulations. Compliance with applicable regulations may result in approval delays for projects, critical licences and permits, stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, litigation, increased capital and operating expenses, increased compliance costs and increased costs for closure, controls/limits on land and resource access, reclamation, and ecological restoration. Third-party NGOs, citizen activist groups and Indigenous communities can also influence environmental laws and regulations in the jurisdictions in which we conduct our operations, development or exploration, including the U.S. and Canada. We anticipate that further changes in environmental legislation will occur, which may result in approval delays for projects, critical licences and permits, stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, increased compliance costs and increased costs for closure, controls on land and resource access, reclamation, and ecological restoration. The complexities of changes in environmental laws and regulations make it difficult to predict the potential future impact to our business.
U.S. environmental and health and safety regulations and their aggressive enforcement from regulators present challenges and risks to our U.S. operations. These risks can arise if new emissions standards, water quality standards, occupational or process safety management requirements, or regulation of emerging contaminants are finalized or the government develops new interpretations that can increase compliance costs, require capital projects, lengthen project implementation times, and have an adverse effect on our business, financial condition, results of operations and cash flows. For example, in July 2024, U.S. regulators designated certain per- and poly-fluoroalkyl substances (“PFAS”) as hazardous substances, which could lead to additional cleanup liability at U.S. sites.

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Canadian Species at Risk Act
The Canadian federal Species at Risk Act (“SARA”) and associated agreements, as well as provincial regulation regarding threatened or endangered species and their habitat, may limit the pace and the amount of development or activity in areas identified as critical habitat for species of concern, such as woodland caribou or Leach’s Storm-Petrel. The extent and magnitude of any potential adverse impacts of legislation on project development and operations (which may include precluding further development or modification of existing operations) are very difficult to predict, as uncertainty exists as to whether jurisdictional plans and actions undertaken (at the regional/provincial level) will be sufficient to support the recovery of listed species. Similarly, uncertainty exists with respect to the outcome of litigation that could be initiated under SARA.
Canadian Federal Air Quality Management System
The Multi-Sector Air Pollutants Regulations (“MSAPRs”), issued under the Canadian Environmental Protection Act, 1999, seek to protect the environment and health of Canadians by setting mandatory, nationally consistent air pollutant emission standards. The MSAPRs are aimed at equipment-specific Base-Level Industrial Emissions Requirements (“BLIERs”). Nitrogen oxide BLIERs from our non-utility boilers, heaters and stationary engines are regulated in accordance with specified performance standards. We anticipate that the MSAPRs will result in adverse impacts to Cenovus including, but not limited to, capital investment required to retrofit existing equipment and increased operating costs.
Canadian Ambient Air Quality Standards (“CAAQS”) for nitrogen dioxide, sulphur dioxide, fine particulate matter and ozone were introduced as part of a national Air Quality Management System. Provinces may implement the CAAQS at the regional air zone level and air zone management actions may include more stringent emissions standards applicable to industrial sources from approval holders in regions where we operate that may result in adverse impacts including, but not limited to, capital investment to retrofit existing facilities and increased operating costs.
Review of Environmental and Regulatory Processes
Increased or evolving environmental assessment obligations imposed by various levels of governments in the jurisdictions in which we conduct operations, development or exploration may create risk of increased costs, project development delays and an increased number of conditions. The regulatory frameworks within the jurisdictions where we conduct operations, development or exploration are constantly evolving and may become more onerous or costly, which may impede our ability to economically develop our resources. The extent and magnitude of any adverse impacts of changes to such regulatory frameworks on project development and operations cannot be estimated at this time.
Water Regulation
We utilize fresh water in certain operations, which is obtained in accordance with respective jurisdictions’ regulations, including through water licences. If water fees increase, the terms of water licences change or there are restrictions in the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial condition. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to licences. There is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted, or granted on favourable terms. This may adversely affect our business, including the ability to operate our assets and execute development plans.
Our U.S. refineries are subject to water discharge requirements that necessitate treatment of wastewater prior to discharging. Non-compliance with these requirements can lead to enforcement actions by regulators including issuance of fines, orders to upgrade treatment plants and suspension of operations. Federal and state regulators in the U.S. are currently addressing PFAS in water discharge permits by requiring installation of additional wastewater treatment units and requiring monitoring of PFAS in discharges.
Hydraulic Fracturing
Legislative and regulatory initiatives have been introduced related to stakeholder claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources, and are increasing the frequency of seismic activity. New laws, regulations or permitting requirements regarding hydraulic fracturing may lead to limitations or restrictions to oil and gas development activities, operational delays, increased compliance costs, restrictions to freshwater usage, additional operating requirements or increased third-party or governmental claims, resulting in increased cost of doing business as well as impacting the amount of natural gas and oil that we are ultimately able to produce from our reserves.
Cenovus ESG Focus Areas and Goals
We have established ambitious targets in our five ESG focus areas and continue to allocate resources and progress tangible plans to meet these targets. To achieve these goals and to respond to changing market demand, we may incur additional costs and invest in new technologies and innovation. It is possible that the benefits of these investments may be less than we expect, which may have an adverse effect on our business, financial condition and reputation.

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Generally, our ESG goals depend significantly on our ability to execute our current business strategy, which can be impacted by the numerous risks and uncertainties associated with our business and the industry in which we operate, as outlined in the Risk Management and Risk Factors section of this MD&A. Investors and stakeholders increasingly compare companies based on ESG-related performance, including climate-related performance. Failure to achieve our ESG goals, or a perception among key stakeholders that our ESG goals are insufficient or unattainable, could adversely affect our reputation and our ability to attract capital and insurance coverage.
There is also a risk that some or all of the expected benefits and opportunities of achieving the various ESG goals may fail to materialize, may cost more to achieve than we expect or may not occur within the anticipated time periods. In addition, there is a risk that the actions we take in implementing targets and ambitions relating to our ESG focus areas may, among other things, increase our capital expenditures and thereby impair our ability to invest in other aspects of our business, which could have a negative impact on our future operating and financial results.
Climate and GHG Emissions Reduction Goals
Our ability to meet our GHG emissions reduction goals is subject to numerous risks and uncertainties and our actions taken in implementing such goals may also expose us to certain additional and/or heightened litigation, financial and operational risks. A reduction in GHG emissions relies on, among other things, our ability to develop, access and implement commercially viable and scalable emissions reduction strategies, and related technology and products. If we are unable to implement these strategies and technologies as planned without negatively impacting our expected operations or cost structure, or such strategies or technologies do not perform as expected, we may be unable to meet our GHG emissions reduction goals on the planned timeline, or at all.
Furthermore, our longer-term goals are inherently less certain due to the longer timeframe and certain factors outside of our control, including the commercial application of future technologies that may be necessary for us to achieve such goals, and the cooperation and actions of third parties, including Pathways Alliance. The Pathways Alliance’s proposed carbon capture and storage project is of particular importance, and if this project is delayed or does not proceed, Cenovus’s ability to achieve its GHG reduction goals and ambitions will be delayed and may not be achieved.
In addition, achieving our GHG emissions reduction goals relies on the existence of a favourable and stable regulatory framework that includes, among other things, support from various levels of government, including financial support and shared capital cost commitments, which may not develop in a manner consistent with our expectations, or at all. Achieving our GHG emissions reduction goals will also require capital expenditures and Company resources, with the potential that actual costs may differ from our original estimates and the differences may be material. Furthermore, the cost of investing in emissions-reduction technologies, and the resulting change in the deployment of resources and focus, could have a negative impact on our business, financial condition, results of operations and cash flows.
Water Stewardship Targets
Our ability to meet our water stewardship targets will depend on the commercial viability and scalability of relevant water reduction strategies, and related steam and water usage technology and products. There are risks associated with relying largely or partly on new technologies, the incorporation of such technologies into new or existing operations and acceptance of new technologies in the market. In the event we are unable to effectively deploy the necessary technologies, or such strategies or technologies do not perform as expected, progress toward our targets could be interrupted, delayed or abandoned.
Biodiversity Targets
Our ability to meet our biodiversity targets is subject to various operational, environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on us. See “Decommissioning” above. In addition, an increase in operating costs, changes to market conditions and access to additional capital, if needed, could result in our inability to fund, and ultimately meet, our biodiversity targets on the current timelines, or at all. In some cases, meeting our biodiversity targets has operational implications for reduced operational footprint and accelerated abandonment, reclamation and restoration.
Indigenous Reconciliation Targets
A failure or delay in achieving our Indigenous reconciliation targets or continuing to advance Indigenous reconciliation initiatives, may adversely affect our relationship with neighbouring Indigenous businesses and communities, and our reputation. If we are unable to maintain a positive relationship with Indigenous communities near our operations, our progress and ability to develop and operate projects in line with our current business and operational strategies may be adversely impacted.
Inclusion and Diversity Targets
Inclusion and valuing the diversity of our staff play a critical role in strengthening our business performance and culture. A failure or delay in achieving our inclusion and diversity targets, or a failure in our ability to maintain targets once met, could have a material adverse effect on our recruitment activities and reputation with our stakeholders.

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Reputation Risk
We rely on our reputation to build and maintain positive relationships with investors and other stakeholders, to recruit and retain staff and to be a credible, trusted company. Any actions we take that influence public or key stakeholder opinions have the potential to impact our reputation, which may adversely affect our share price, development plans and ability to continue operations.
Development of fossil fuel-based energy, and oil sands in particular, has received considerable attention on the subjects of environmental impact, climate change, GHG emissions and Indigenous reconciliation. Concerns about oil sands may, directly or indirectly, impair the profitability of our current oil sands projects and the viability of future oil sands projects, by creating significant regulatory, economic and operating uncertainty. Increased public opposition to, and stigmatization of, the oil and gas sector, and in particular the oil sands industry, could lead to constrained access to insurance, liquidity and capital and changes in demand for our products, which may adversely impact our business, financial condition or results of operations.
Shareholder activism has been increasing in the crude oil, natural gas, NGL and refining industry, and investors may from time to time attempt to effect changes to our business, governance, or reporting practices with respect to climate change or otherwise, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our Board, Management and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of our business. In the event such activist shareholders are successful, Cenovus may be required to incur costs and dedicate time to adopting new practices. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in significant fluctuation in the market price of our securities.
Other Risks
Dilutive Effect
We are authorized to issue, among other classes of shares, an unlimited number of common shares for consideration and on terms and conditions as established by our Board without the approval of our shareholders in certain instances. Any future issuances of Cenovus common shares or other securities exercisable or convertible into, or exchangeable for, Cenovus common shares may result in dilution to present and prospective Cenovus shareholders. The issuance of additional Cenovus common shares upon exercise, from time to time, of securities convertible into Cenovus common shares, including equity awards granted to our directors and officers, will have a further dilutive effect on the ownership interest of shareholders of Cenovus. Such dilutive effect on Cenovus's earnings per share could adversely affect the market price of Cenovus common shares and the value of our shareholders' investments.
Risks Relating to Acquisitions and Dispositions
We have completed, and may complete in the future, acquisitions and dispositions for various strategic reasons. We may not be able to complete such transactions on favourable terms, on a timely basis, or at all. The integration of acquired assets and operations may result in the disruption of business and may divert Management’s focus and resources from other strategic opportunities and operational matters during the process, which may result in increased costs and adversely affect our ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires assessments of their characteristics which are inexact and inherently uncertain and, as such, the acquired assets may not produce or operate as expected, may not have the anticipated benefits or synergies and may be subject to increased costs and liabilities. Further, we may not be able to obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition.
Various factors could materially affect our ability to dispose of assets in the future and may also reduce the proceeds or value realized from such dispositions. We may also retain certain liabilities or agree to indemnification obligations in a sale transaction, which may be difficult to quantify at the time of the transaction and could ultimately be material.
Should any of the risks associated with acquisitions or dispositions materialize, they could have an adverse effect on our business, financial condition or reputation.
Risks Related to Significant Shareholders of Cenovus
The sale into the market of Cenovus common shares held by significant shareholders of Cenovus, Hutchison Whampoa Europe Investments S.à r.l. (“Hutchison”), L.F. Investments S.à r.l. (“L.F. Investments”), and Capital World Investors (“Capital World”, together with Hutchison and L.F. Investments, the “Significant Shareholders”) or market perception regarding any intention of the Significant Shareholders to sell Cenovus common shares, could adversely affect market prices for our common shares. While Hutchison and L.F. Investments are each subject to certain voting covenants pursuant to the terms of a standstill agreement they each entered into with Cenovus, the Significant Shareholders may be able to impact certain matters requiring Cenovus shareholder approval.

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Market for Cenovus Warrants
There can be no assurance that an active public market for Cenovus Warrants will be sustained. If such a market is sustained, the market price of the Cenovus Warrants may be adversely affected by similar factors as those impacting the market price of Cenovus common shares. In addition, the market price of Cenovus common shares will significantly affect the market price of Cenovus Warrants which may result in significant volatility in the market price of the Cenovus Warrants and may negatively impact the value of the Cenovus Warrants.
Tax Laws
Income tax laws and regulations and other laws and government incentive programs (such as Canadian Carbon Capture Utilization and Storage Investment Tax Credits) may in the future be changed or interpreted in a manner that adversely affects us, our financial results, our ability to achieve our GHG emissions reduction goals and our shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s detriment or to the detriment of our shareholders. Further, as there are usually a number of tax matters under review, income taxes are subject to measurement uncertainty. In addition, all of our tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and our shareholders.
The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration related to the Base Erosion and Profit Shifting (“BEPS”) project of the Organization for Economic Co-operation and Development. Although the timing and methods of implementation vary, numerous countries including Canada have responded to the BEPS project by implementing, or proposing to implement, changes to tax laws and tax treaties at a rapid pace. These changes may increase our cost of tax compliance and affect our business, financial condition and results of operations in a manner that is difficult to quantify. We will continue to monitor and assess potential adverse impacts on our global tax situation as a result of the BEPS project.
Pandemic Risk
Pandemics, epidemics or outbreaks, remain a risk for the Company, and the ultimate impact of a pandemic is highly uncertain and subject to change. A pandemic and the corresponding measures we take to protect the health and safety of our staff, and the continuity of our business may result in new legal challenges and disputes, including, but not limited to, litigation involving contract parties or employees and class action claims. Actions taken by various levels of government and health authorities in the event of a pandemic, epidemic or outbreak may result in a reduction in the demand for, and prices of, commodities that are closely linked to our financial performance and may negatively impact our business, results of operations and financial condition, and reputation.
Fighting Against Forced Labour and Child Labour in Supply Chains Act
The Fighting Against Forced Labour and Child Labour in Supply Chains Act requires Cenovus to publish an annual report on steps taken to assess and mitigate the risk of forced or child labour in its business and supply chains. Further, the customs tariff prohibits importing goods made in whole or in part with forced labour, child labour and prison labour. Increased scrutiny on forced or child labour in Canadian markets and supply chains, along with measures by us, our suppliers, other businesses and the Government of Canada, may impact business activities, including the import of goods and materials. These measures could lead to changes or disruptions in suppliers and supply chains, affecting the availability or cost of goods and materials we purchase. This could impact our access to certain goods or materials at desired prices, procurement processes, productivity, operating costs and financial condition. There is a risk that our supply chain may use or be alleged to use forced or child labour, and gathering sufficient information from suppliers to assess and mitigate such risks may be challenging. Our due diligence and mitigation activities might not identify or mitigate all risks, potentially harming our reputation. The Government of Canada plans to expand the legislative framework on forced and child labour, possibly including specific due diligence requirements for high-risk goods. However, there is uncertainty about the timing, requirements, implementation, and impact of these additional measures on our business activities and supply chains. The risks and commercial impacts of expanding regulation in this area cannot be fully assessed at this time.
A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business, prospects, financial condition, results of operations and cash flows, and in some cases our reputation, can be found in our subsequently filed MD&A, available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and at cenovus.com.

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CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, as well as use judgment, in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements.
Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.
Identification of Cash-Generating Units
Cash generating units (“CGUs”) are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and impairment reversals.
Assessment of Impairment Indicators or Impairment Reversals
PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. The identification of indicators of impairment or reversal of impairment requires significant judgment.
Exploration and Evaluation Assets
The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.
Joint Arrangements
The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment.
Cenovus has a 50 percent interest in WRB, a jointly-controlled entity. The joint arrangement meets the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
Prior to February 28, 2023, Cenovus held a 50 percent interest in BP-Husky Refining LLC (“Toledo”), which was jointly controlled with BP Products North America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo, as defined under IFRS 10, “Consolidated Financial Statements”, and, accordingly, Toledo was consolidated.

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In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
•The original intention of the joint arrangements was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.
•The agreements require the partners to make contributions if funds are insufficient to meet the obligations or liabilities of the corporation and partnerships. The past development of Toledo and the past and future development of WRB, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.
•WRB has third-party debt facilities to cover short-term working capital requirements.
•Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services, purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does not have employees and, as such, is not capable of performing these roles.
•As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf.
•In each arrangement, output is taken by the partners, indicating that the partners have the rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.
Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis, and any revisions to accounting estimates are recorded in the period in which the estimates are revised.
The evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could change assumptions used to determine the recoverable amount of the Company’s PP&E and E&E assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects, may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built into estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads, net of RINs, and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate market expectations and the evolving worldwide demand for energy.
The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the expected future production volumes, future development and operating expenses, forward commodity prices, estimated royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands, Conventional and Offshore segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.
Recoverable Amounts
Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include quantity of reserves, expected future production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts f or the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, net of RINs, future operating expenses and capital expenditures, and discount rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

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Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of liabilities and estimate the future value. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.
Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination
The fair value of assets acquired, liabilities assumed and assets given up in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparable transactions and discounted cash flows. For the Company’s upstream assets, key assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected future production volumes, quantity of reserves, discount rates, and future development and operating expenses. Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology and engineering professionals, and IQREs. For downstream assets, key assumptions used to estimate fair value include refined product production, forward crude oil prices, forward crack spreads, net of RINs, future operating expenses, future capital expenditures and discount rates. Changes in these variables could significantly impact the carrying value of the net assets acquired.
Income Tax Provisions
The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.
Update to Accounting Policies
As of January 1, 2024, the Company updated its accounting policies to aggregate certain items presented in the Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Cash Flows to more appropriately reflect the integrated operations of the business. There were no re-measurements of balances. Certain historical disaggregated balances continue to be presented in Note 1 of the Consolidated Financial Statements.
The following presentation changes were made, with comparative periods being re-presented:
•Gross sales and royalties were aggregated and presented as ‘Revenues’.
•Purchased product and transportation and blending were aggregated and presented as ‘Purchased Product, Transportation and Blending’.
•Depreciation, depletion and amortization, and exploration expense were aggregated and presented as ‘Depreciation, Depletion, Amortization and Exploration Expense’.
•Finance costs and interest income were aggregated and presented as ‘Finance Costs, Net’.
•Revaluation (gain) loss and (gain) loss on divestiture of assets were aggregated and presented as ‘(Gain) Loss on Divestiture of Assets’.
New Accounting Standards and Interpretations Not Yet Adopted
Presentation and Disclosure in Financial Statements
On April 9, 2024, the IASB issued IFRS 18, “Presentation and Disclosure in Financial Statements” (“IFRS 18”), which will replace International Accounting Standard 1, “Presentation of Financial Statements”. IFRS 18 will establish a revised structure for the Consolidated Statements of Comprehensive Income (Loss) and improve comparability across entities and reporting periods.
IFRS 18 is effective for annual periods beginning on or after January 1, 2027. The standard is to be applied retrospectively, with certain transition provisions. The Company is currently evaluating the impact of adopting IFRS 18 on the Consolidated Financial Statements.

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Financial Instruments
On May 30, 2024, the IASB issued amendments to IFRS 9, “Financial Instruments”, and IFRS 7, “Financial Instruments: Disclosures”. The amendments include clarifications on the derecognition of financial liabilities and the classification of certain financial assets. In addition, new disclosure requirements for equity instruments designated as FVOCI were added. The amendments are effective for annual periods beginning on or after January 1, 2026, and will be applied retrospectively. The Company is currently evaluating the impact of the amendments on the Consolidated Financial Statements.

CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of ICFR and DC&P as at December 31, 2024. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2024.
The effectiveness of our ICFR was audited as at December 31, 2024, by PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our Consolidated Financial Statements for the year ended December 31, 2024.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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ADVISORY

Oil and Gas Information
Barrels of Oil Equivalent – natural gas volumes are converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Interests in Joint Ventures
Cenovus holds interests in a number of joint ventures, as classified under IFRS Accounting Standards, that are accounted for using the equity method of accounting in our Consolidated Financial Statements, including a 30 percent equity ownership interest in Duvernay and a 40 percent equity ownership interest in HCML. Unless otherwise indicated, the operational events and results from these equity interests including, without limitation, production, reserves, revenues, costs and expenses may not be reflected in the Consolidated Financial Statements or this MD&A. As a result, the disclosure in the AIF in respect to certain equity method investees may differ from corresponding information in this MD&A. Readers are directed to the information contained under the heading “Reserves Data and Other Oil and Gas Information” in the AIF for further information regarding Cenovus’s interests in Duvernay and HCML.
Forward-looking Information
This document contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “may”, “objective”, “opportunities”, “plan”, “position”, “priority”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our five strategic objectives; shareholder value and returns; safety; sustainability; our commitment to the Pathways Alliance foundational project; maximizing value; disciplined capital allocation; Free Funds Flow; cash flow volatility and stability; focus on cost and sustainability improvements; liquidity; growth of our base business; capital investment; our 2025 corporate guidance; realizing the full value of our integrated business; reinvesting in our business; capitalizing on opportunities; Net Debt; allocating Excess Free Funds Flow; absolute and per share free funds flow growth; our competitive, reliable downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; project execution; progression of our planned drilling program; growing our competitive advantages while operating safely and reliably monitoring market fundamentals and optimizing run rates at our refineries; safe and reliable operations; being best-in-class operators; maintaining a strong balance sheet; costs; margins; long-term value for Cenovus; downstream reliability and profitability; timing for resuming production from the SeaRose FPSO, timing of first oil from the West White Rose project; progressing the Foster Creek optimization and Sunrise growth projects; our five ESG focus areas; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; volatility of refined product prices; impact of U.S. tariffs on market benchmarks and Cenovus; Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; capitalizing on opportunities throughout the commodity price cycle; Net Debt to Adjusted EBITDA ratio; maintaining sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar, the factors that affect such outlook, and the influences and effects on Cenovus.
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast bitumen, crude oil and natural gas, natural gas liquids, condensate and refined products prices, and light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs, projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change), Indigenous relations, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions and the supply and demand for bitumen, crude oil and natural gas, NGLs, condensate and refined products; the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, third party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further

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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, natural gas and liquids from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company’s ability to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability to complete acquisitions and divestitures, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third-party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2025 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.
2025 guidance dated December 11, 2024, and available on cenovus.com, assumes: Brent prices of US$74.00 per barrel, WTI prices of US$70.00 per barrel; WCS of US$56.00 per barrel; Differential WTI-WCS of US$14.00 per barrel; AECO natural gas prices of $2.05 per Mcf; Chicago 3-2-1 crack spread of US$18.50 per barrel; and an exchange rate of $0.72 US$/C$.
The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; the Company’s ability to successfully integrate acquired business with its own in a timely and cost effective manner; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and divestitures; the Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of ESG targets and ambitions and the commercial viability and scalability of ESG strategies and related technology and products; the development and execution of implementing strategies to meet ESG targets and ambitions; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; the Company’s ability to integrate upstream and downstream operations to help mitigate the impact of volatility in light-heavy crude oil differentials and contribute to its net earnings; foreign exchange risk, including related to agreements denominated in foreign currencies; the Company’s continued liquidity being sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential remaining largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of the Company’s outlook for commodity prices, the impact of tariffs and responses thereto, currency and interest rates; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; the ability to complete and optimize drilling, completion, tie in and infrastructure projects; the ability of the Company to ramp up activities at its refineries on its anticipated timelines; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; tax audits and reassessments; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of

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

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 68

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 | thousand barrels of oil equivalent
MMbbls | million barrels | MMcf/d | million cubic feet per day | MBOE/d | thousand barrels of oil equivalent per day
WCS | Western Canadian Select | Bcf | billion cubic feet | MMBOE | million barrels of oil equivalent
WTI | West Texas Intermediate |  |  | DD&A | depreciation, depletion and amortization
|  |  |  | ESG | environmental, social and governance
|  |  |  | GHG | greenhouse gas
|  |  |  | CO2e | carbon dioxide equivalent
|  |  |  | 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
|  |  |  | SAGD | steam-assisted gravity drainage
|  |  |  | USGC | U.S. Gulf Coast

Revision of Operational Metrics
Following changes to our downstream portfolio in recent years, we undertook a review of our downstream disclosures with the intent of enhancing the performance reporting of our refining operations and increasing comparability with peers. As a result of this review, commencing in June 2024, we introduced the following new, and/or revised, operational metrics to our Canadian Refining and our U.S. Refining segments. Comparative periods have been provided or recalculated where applicable.
•Total processed inputs is a new measure that reflects the overall inputs required to produce refined products in our refineries, and is used as the denominator in our per-unit measures, replacing crude oil unit throughput.
•Market capture is a new measure in our U.S. Refining segment that reflects Refining Margin generated as a percentage of the weighted average crack spread, net of RINs, on a FIFO basis of accounting. 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.
•Operable capacity is the capacity based on barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. Operable capacity has replaced crude oil unit throughput capacity, which was based on barrels per stream day and represents the amount of input that a distillation facility can process under optimal crude and product slate conditions, with no allowance for downtime.
•Crude unit utilization is crude oil unit throughput divided by operable capacity, expressed as a percentage. Previously this measure was calculated using crude oil unit throughput capacity.
The table below details the operable capacity and crude oil unit throughput capacity as at December 31, 2023, and is provided to illustrate the magnitude of the revised metrics detailed above:

(Mbbls/d) | Canadian Refining | U.S. Refining
Operable Capacity | 108.0 |  | 612.3 |
Crude Oil Unit Throughput Capacity | 110.5 |  | 635.2 |

Definitions and reconciliations of certain Specified Financial Measures, such as Refining Margin, Market Capture, per-unit operating expenses, per-unit operating expenses – excluding turnaround costs and per-unit operating expenses – turnaround costs are included in the Specified Financial Measures section of this MD&A.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 69

SPECIFIED FINANCIAL MEASURES
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS Accounting Standards including Operating Margin, Operating Margin by asset, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Total Long-Term Liabilities, Gross Margin, Refining Margin, Market Capture, Realized Sales Price, Offshore and Asia Pacific Per-Unit Operating Expenses, and Netbacks (including the total Netback per BOE).
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 or Liquidity and Capital Resources sections 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, Excess Free Funds Flow, Realized Sales Price and Netbacks for prior period information from 2024, 2023 and 2022 that is not found below.
Non-GAAP 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 unaudited interim Consolidated Financial Statements and accompanying notes for the periods ended December 31, 2024 (“interim Consolidated Financial Statements”).
Operating Margin

| Three Months Ended December 31,
| 2024 |  | 2023 |  | 2024 |  | 2023 |  | 2024 |  | 2023
($ millions) | Upstream (1) |  | Downstream (1) |  | Total
Gross Sales |  |  |  |  |  |  |  |  |  |  |
External Sales | 6,050 |  | 5,796 |  | 7,677 |  | 8,240 |  | 13,727 |  | 14,036
Intersegment Sales | 2,190 |  | 2,001 |  | 160 |  | 164 |  | 2,350 |  | 2,165
| 8,240 |  | 7,797 |  | 7,837 |  | 8,404 |  | 16,077 |  | 16,201
Royalties | (914) |  | (902) |  | — |  | — |  | (914) |  | (902)
Revenues | 7,326 |  | 6,895 |  | 7,837 |  | 8,404 |  | 15,163 |  | 15,299
Expenses |  |  |  |  |  |  |  |  |  |  |
Purchased Product | 1,000 |  | 663 |  | 7,364 |  | 7,888 |  | 8,364 |  | 8,551
Transportation and Blending | 2,816 |  | 2,894 |  | — |  | — |  | 2,816 |  | 2,894
Operating | 842 |  | 864 |  | 866 |  | 826 |  | 1,708 |  | 1,690
Realized (Gain) Loss on Risk Management | (2) |  | 19 |  | 3 |  | (6) |  | 1 |  | 13
Operating Margin | 2,670 |  | 2,455 |  | (396) |  | (304) |  | 2,274 |  | 2,151

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

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 70

| Year Ended December 31, |  |
| 2024 |  | 2023 |  |  |  | 2024 |  | 2023 |  |  |  | 2024 |  | 2023 |  |
($ millions) | Upstream (1) |  | Downstream (1) |  | Total
Gross Sales |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
External Sales | 24,640 |  | 23,713 |  |  |  | 33,086 |  | 31,761 |  |  |  | 57,726 |  | 55,474 |  |
Intersegment Sales | 8,438 |  | 7,369 |  |  |  | 532 |  | 865 |  |  |  | 8,970 |  | 8,234 |  |
| 33,078 |  | 31,082 |  |  |  | 33,618 |  | 32,626 |  |  |  | 66,696 |  | 63,708 |  |
Royalties | (3,449) |  | (3,270) |  |  |  | — |  | — |  |  |  | (3,449) |  | (3,270) |  |
Revenues | 29,629 |  | 27,812 |  |  |  | 33,618 |  | 32,626 |  |  |  | 63,247 |  | 60,438 |  |
Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchased Product | 3,674 |  | 3,152 |  |  |  | 30,252 |  | 28,273 |  |  |  | 33,926 |  | 31,425 |  |
Transportation and Blending | 11,331 |  | 11,088 |  |  |  | — |  | — |  |  |  | 11,331 |  | 11,088 |  |
Operating | 3,489 |  | 3,690 |  |  |  | 3,670 |  | 3,201 |  |  |  | 7,159 |  | 6,891 |  |
Realized (Gain) Loss on Risk Management | 14 |  | 12 |  |  |  | 8 |  | — |  |  |  | 22 |  | 12 |  |
Operating Margin | 11,121 |  | 9,870 |  |  |  | (312) |  | 1,152 |  |  |  | 10,809 |  | 11,022 |  |

(1)Found in Note 1 of the Consolidated Financial Statements.
Operating Margin by Asset

|  |  | Year Ended December 31, 2024
($ millions) |  |  |  |  |  |  | Atlantic |  | Asia Pacific |  | Offshore (1)
Gross Sales |  |  |  |  |  |  | 322 |  | 1,250 |  | 1,572
Royalties |  |  |  |  |  |  | (2) |  | (97) |  | (99)
Revenues |  |  |  |  |  |  | 320 |  | 1,153 |  | 1,473
Expenses |  |  |  |  |  |  |  |  |  |  |
Transportation and Blending |  |  |  |  |  |  | 11 |  | — |  | 11
Operating |  |  |  |  |  |  | 290 |  | 133 |  | 423
Operating Margin |  |  |  |  |  |  | 19 |  | 1,020 |  | 1,039

|  |  | Year Ended December 31, 2023
($ millions) |  |  |  |  |  |  | Atlantic |  | Asia Pacific |  | Offshore (1)
Gross Sales |  |  |  |  |  |  | 400 |  | 1,217 |  | 1,617
Royalties |  |  |  |  |  |  | (15) |  | (84) |  | (99)
Revenues |  |  |  |  |  |  | 385 |  | 1,133 |  | 1,518
Expenses |  |  |  |  |  |  |  |  |  |  |
Transportation and Blending |  |  |  |  |  |  | 16 |  | — |  | 16
Operating |  |  |  |  |  |  | 262 |  | 122 |  | 384
Operating Margin |  |  |  |  |  |  | 107 |  | 1,011 |  | 1,118

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

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 71

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

| Three Months Ended December 31, |  | Year Ended December 31, |  |
($ millions) | 2024 |  | 2023 |  | 2024 |  | 2023 |  |
Cash From (Used in) Operating Activities | 2,029 |  |  | 2,946 |  |  | 9,235 |  |  | 7,388 |  |  |
(Add) Deduct: |  |  |  |  |  |  |  |  |
Settlement of Decommissioning Liabilities | (64) |  |  | (65) |  |  | (234) |  |  | (222) |  |  |
Net Change in Non-Cash Working Capital | 492 |  |  | 949 |  |  | 1,305 |  |  | (1,193) |  |  |
Adjusted Funds Flow | 1,601 |  |  | 2,062 |  |  | 8,164 |  |  | 8,803 |  |  |
Capital Investment | 1,478 |  |  | 1,170 |  |  | 5,015 |  |  | 4,298 |  |  |
Free Funds Flow | 123 |  |  | 892 |  |  | 3,149 |  |  | 4,505 |  |  |
Add (Deduct): |  |  |  |  |  |  |  |  |
Base Dividends Paid on Common Shares | (330) |  |  | (261) |  |  | (1,255) |  |  | (990) |  |  |
Dividends Paid on Preferred Shares | (18) |  |  | (9) |  |  | (45) |  |  | (36) |  |  |
Purchase of Common Shares Under Employee Benefit Plan | (43) |  |  | — |  |  | (43) |  |  | — |  |  |
Settlement of Decommissioning Liabilities | (64) |  |  | (65) |  |  | (234) |  |  | (222) |  |  |
Principal Repayment of Leases | (80) |  |  | (72) |  |  | (299) |  |  | (288) |  |  |
Acquisitions, Net of Cash Acquired | (3) |  |  | (14) |  |  | (22) |  |  | (515) |  |  |
Proceeds From Divestitures | (1) |  |  | — |  |  | 46 |  |  | 12 |  |  |
Excess Free Funds Flow | (416) |  |  | 471 |  |  | 1,297 |  |  | 2,466 |  |  |

Total Long-Term Liabilities
Total Long-Term Liabilities is a non-GAAP financial measure. The measure is disclosed to fulfill the requirements of National Instrument 51-102, “Continuous Disclosure Obligations” and is defined as total liabilities less total current liabilities.

| As at December 31,
($ millions) | 2024 |  |  |  |  | 2023 |  |  |  |  | 2022
Total Liabilities | 26,770 |  |  |  |  |  | 25,203 |  |  |  |  |  | 28,280 |
Less: Total Current Liabilities | 7,362 |  |  |  |  |  | 6,210 |  |  |  |  |  | 8,021 |
Total Long-Term Liabilities | 19,408 |  |  |  |  |  | 18,993 |  |  |  |  |  | 20,259 |

Gross Margin, Refining Margin and Market Capture
Gross Margin is a non-GAAP financial measure and Refining Margin contains a non-GAAP financial measure. These measures are used to evaluate the performance of our downstream operations. We define Gross Margin as revenues less purchased product. We define Refining Margin as Gross Margin from our refineries, Upgrader and commercial fuels business divided by total processed inputs. Commencing in June 2024, total processed inputs was updated as the denominator to better reflect the overall inputs required to produce refined products. Before June 30, 2024, comparative periods were calculated based on barrels of crude oil unit throughput. All comparative periods have been revised to conform with our current presentation. The following tables for the quarters ended December 31, 2024 and 2023, provide a reconciliation to our interim Consolidated Financial Statements.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 72

Canadian Refining

|  |  |  |  | Three Months Ended December 31, 2024
($ millions) |  |  |  |  | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2)
Revenues |  |  |  |  | 1,207 |  | 56 |  | 1,263
Purchased Product |  |  |  |  | 1,032 |  | 36 |  | 1,068
Gross Margin |  |  |  |  | 175 |  | 20 |  | 195
Total Processed Inputs (Mbbls/d) |  |  |  |  | 112.1 |  |  |  |
Refining Margin ($/bbl) |  |  |  |  | 16.95 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)These amounts, excluding Gross Margin, are found in Note 1 of the interim Consolidated Financial Statements.

|  |  |  |  | Three Months Ended December 31, 2023
($ millions) |  |  |  |  | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2)
Revenues |  |  |  |  | 1,454 |  | 103 |  | 1,557
Purchased Product |  |  |  |  | 1,197 |  | 66 |  | 1,263
Gross Margin |  |  |  |  | 257 |  | 37 |  | 294
Total Processed Inputs (Mbbls/d) |  |  |  |  | 105.1 |  |  |  |
Refining Margin ($/bbl) |  |  |  |  | 26.48 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)These amounts, excluding Gross Margin, are found in Note 1 of the interim Consolidated Financial Statements.

|  |  |  |  | Year Ended December 31, 2024
($ millions) |  |  |  |  | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2)
Revenues |  |  |  |  | 5,014 |  | 296 |  | 5,310
Purchased Product |  |  |  |  | 4,278 |  | 205 |  | 4,483
Gross Margin |  |  |  |  | 736 |  | 91 |  | 827
Total Processed Inputs (Mbbls/d) |  |  |  |  | 96.6 |  |  |  |
Refining Margin ($/bbl) |  |  |  |  | 20.82 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)These amounts, excluding Gross Margin, are found in Note 1 of the Consolidated Financial Statements.

|  |  |  |  | Year Ended December 31, 2023
($ millions) |  |  |  |  | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining (2)
Revenues |  |  |  |  | 5,812 |  | 421 |  | 6,233
Purchased Product |  |  |  |  | 4,634 |  | 285 |  | 4,919
Gross Margin |  |  |  |  | 1,178 |  | 136 |  | 1,314
Total Processed Inputs (Mbbls/d) |  |  |  |  | 107.1 |  |  |  |
Refining Margin ($/bbl) |  |  |  |  | 30.13 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
(2)These amounts, excluding Gross Margin, are found in Note 1 of the Consolidated Financial Statements.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 73

|  |  |  |  | Three Months Ended March 31, 2024
($ millions) |  |  |  |  | Lloydminster Upgrader and Lloydminster Refinery Total |  | Other (1) |  | Total Canadian Refining
Revenues |  |  |  |  | 1,249 |  | 83 |  | 1,332
Purchased Product |  |  |  |  | 1,024 |  | 63 |  | 1,087
Gross Margin |  |  |  |  | 225 |  | 20 |  | 245
Total Processed Inputs (Mbbls/d) |  |  |  |  | 108.8 |  |  |  |
Refining Margin ($/bbl) |  |  |  |  | 22.68 |  |  |  |

(1)Includes ethanol operations and crude-by-rail operations.
U.S. Refining
Market Capture contains a non-GAAP financial measure and 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. We define Market Capture as 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.

| Three Months Ended December 31, |  | Year Ended December 31,
($ millions) | 2024 |  | 2023 |  | 2024 |  | 2023
Revenues (1) | 6,574 |  |  | 6,847 |  |  | 28,308 |  |  | 26,393 |
Purchased Product (1) | 6,296 |  |  | 6,625 |  |  | 25,769 |  |  | 23,354 |
Gross Margin | 278 |  |  | 222 |  |  | 2,539 |  |  | 3,039 |
Total Processed Inputs (Mbbls/d) | 588.4 |  |  | 500.6 |  |  | 581.4 |  |  | 479.7 |
Refining Margin ($/bbl) | 5.14 |  |  | 4.82 |  |  | 11.93 |  |  | 17.36 |
Operable Capacity (Mbbls/d) | 612.3 |  |  | 612.3 |  |  | 612.3 |  |  | 612.3 |
Operable Capacity by Regional Benchmark (percent) |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread Weighting | 81 |  |  | 81 |  |  | 81 |  |  | 82 |
Group 3 3-2-1 Crack Spread Weighting | 19 |  |  | 19 |  |  | 19 |  |  | 18 |
Benchmark Prices and Exchange Rate |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread (US$/bbl) | 12.12 |  |  | 13.24 |  |  | 16.74 |  |  | 24.19 |
Group 3 3-2-1 Crack Spread (US$/bbl) | 12.66 |  |  | 18.55 |  |  | 16.81 |  |  | 29.66 |
RINs (US$/bbl) | 4.02 |  |  | 4.77 |  |  | 3.74 |  |  | 7.04 |
US$ per C$1 – Average | 0.715 |  |  | 0.734 |  |  | 0.730 |  |  | 0.741 |
Weighted Average Crack Spread, Net of RINs ($/bbl) | 11.47 |  |  | 12.94 |  |  | 17.82 |  |  | 24.49 |
Market Capture (2) (percent) | 45 |  |  | 37 |  |  | 67 |  |  | 71 |

(1)Found in Note 1 of the interim Consolidated Financial Statements.
(2)The Superior Refinery’s operable capacity is included in Market Capture effective April 1, 2023. For the year ended December 31, 2023, Market Capture includes a weighted average operable capacity for the Toledo Refinery as full ownership was acquired on February 28, 2023.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 74

($ millions) |  |  | Three Months Ended March 31, 2024 |  |  |  |  |  |
Revenues (1) |  |  | 6,901 |  |  |  |  |  |  |
Purchased Product (1) |  |  | 5,798 |  |  |  |  |  |  |
Gross Margin |  |  | 1,103 |  |  |  |  |  |  |
Total Processed Inputs (Mbbls/d) |  |  | 575.0 |  |  |  |  |  |  |
Refining Margin ($/bbl) |  |  | 21.08 |  |  |  |  |  |  |
Operable Capacity (Mbbls/d) |  |  | 612.3 |  |  |  |  |  |  |
Operable Capacity by Regional Benchmark (percent) |  |  |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread Weighting |  |  | 81 |  |  |  |  |  |  |
Group 3 3-2-1 Crack Spread Weighting |  |  | 19 |  |  |  |  |  |  |
Benchmark Prices and Exchange Rate |  |  |  |  |  |  |  |  |
Chicago 3-2-1 Crack Spread (US$/bbl) |  |  | 17.45 |  |  |  |  |  |  |
Group 3 3-2-1 Crack Spread (US$/bbl) |  |  | 17.50 |  |  |  |  |  |  |
RINs (US$/bbl) |  |  | 3.68 |  |  |  |  |  |  |
US$ per C$1 – Average |  |  | 0.741 |  |  |  |  |  |  |
Weighted Average Crack Spread, Net of RINs ($/bbl) |  |  | 18.59 |  |  |  |  |  |  |
Market Capture (percent) |  |  | 113 |  |  |  |  |  |  |

(1)Reflects certain revisions. See Prior Period Revisions section of this MD&A.
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. In March 2024, modifications were made to our Netback definition to enhance the clarity of certain costs captured in this metric. These modifications resulted in minor adjustments that are captured in the Netback calculation on a prospective basis.
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. Offshore and Asia Pacific Per-Unit Operating Expenses contain non-GAAP measures. Offshore and Asia Pacific operating expenses, as used in the basis of our Netback calculation, reflect our 40 percent equity interest in HCML. The HCML joint venture is accounted for using the equity method in the Consolidated Financial Statements. 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.
The following tables provide a reconciliation of Netback to Operating Margin found in our interim Consolidated Financial Statements and Consolidated Financial Statements.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 75

Oil Sands

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

| Basis of Netback Calculation | Adjustments |  |
Three Months Ended December 31, 2024 ($ millions) | Total Oil Sands |  | Condensate | Third-party Sourced | Other (2) |  | Total Oil Sands (3)
Gross Sales | 4,351 |  |  | 2,181 |  | 465 |  | 94 |  |  | 7,091 |
Royalties | (874) |  |  | — |  | — |  | — |  |  | (874) |
Revenues | 3,477 |  |  | 2,181 |  | 465 |  | 94 |  |  | 6,217 |
Expenses |  |  |  |  |  |  |
Purchased Product | — |  |  | — |  | 465 |  | 65 |  |  | 530 |
Transportation and Blending | 521 |  |  | 2,181 |  | — |  | 33 |  |  | 2,735 |
Operating | 622 |  |  | — |  | — |  | (7) |  |  | 615 |
Netback | 2,334 |  |  | — |  | — |  | 3 |  |  | 2,337 |
Realized (Gain) Loss on Risk Management | (3) |  |  | — |  | — |  | — |  |  | (3) |
Operating Margin | 2,337 |  |  | — |  | — |  | 3 |  |  | 2,340 |

(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
(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
Three Months Ended December 31, 2023 ($ millions) | Foster Creek | Christina Lake | Sunrise | Lloydminster Oil Sands (1) |  | Total Bitumen and Heavy Oil |  | Natural Gas |  | Total Oil Sands
Gross Sales | 1,312 |  | 1,447 |  | 357 |  | 778 |  |  | 3,894 |  |  | 2 |  |  | 3,896 |
Royalties | (353) |  | (366) |  | (32) |  | (86) |  |  | (837) |  |  | (1) |  |  | (838) |
Revenues | 959 |  | 1,081 |  | 325 |  | 692 |  |  | 3,057 |  |  | 1 |  |  | 3,058 |
Expenses |  |  |  |  |  |  |  |  |  |
Purchased Product | — |  | — |  | — |  | — |  |  | — |  |  | — |  |  | — |
Transportation and Blending | 200 |  | 161 |  | 58 |  | 39 |  |  | 458 |  |  | — |  |  | 458 |
Operating | 174 |  | 167 |  | 65 |  | 203 |  |  | 609 |  |  | 1 |  |  | 610 |
Netback | 585 |  | 753 |  | 202 |  | 450 |  |  | 1,990 |  |  | — |  |  | 1,990 |
Realized (Gain) Loss on Risk Management |  |  |  |  |  |  |  |  |  | 24 |
Operating Margin |  |  |  |  |  |  |  |  |  | 1,966 |

| Basis of Netback Calculation | Adjustments |  |
Three Months Ended December 31, 2023 ($ millions) | Total Oil Sands |  | Condensate | Third-party Sourced | Other (2) |  | Total Oil Sands (3)
Gross Sales | 3,896 |  |  | 2,329 |  | 156 |  | 96 |  |  | 6,477 |
Royalties | (838) |  |  | — |  | — |  | (3) |  |  | (841) |
Revenues | 3,058 |  |  | 2,329 |  | 156 |  | 93 |  |  | 5,636 |
Expenses |  |  |  |  |  |  |
Purchased Product | — |  |  | — |  | 156 |  | 70 |  |  | 226 |
Transportation and Blending | 458 |  |  | 2,329 |  | — |  | 22 |  |  | 2,809 |
Operating | 610 |  |  | — |  | — |  | 5 |  |  | 615 |
Netback | 1,990 |  |  | — |  | — |  | (4) |  |  | 1,986 |
Realized (Gain) Loss on Risk Management | 24 |  |  | — |  | — |  | — |  |  | 24 |
Operating Margin | 1,966 |  |  | — |  | — |  | (4) |  |  | 1,962 |

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

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 76

| Basis of Netback Calculation
Year Ended December 31, 2024 ($ millions) | Foster Creek | Christina Lake | Sunrise | Lloydminster Oil Sands (1) |  | Total Bitumen and Heavy Oil |  | Natural Gas |  | Total Oil Sands
Gross Sales | 5,837 |  | 6,428 |  | 1,574 |  | 3,724 |  |  | 17,563 |  |  | — |  |  | 17,563 |
Royalties | (1,176) |  | (1,601) |  | (78) |  | (413) |  |  | (3,268) |  |  | — |  |  | (3,268) |
Revenues | 4,661 |  | 4,827 |  | 1,496 |  | 3,311 |  |  | 14,295 |  |  | — |  |  | 14,295 |
Expenses |  |  |  |  |  |  |  |  |  |
Purchased Product | — |  | — |  | — |  | — |  |  | — |  |  | — |  |  | — |
Transportation and Blending | 937 |  | 554 |  | 294 |  | 185 |  |  | 1,970 |  |  | — |  |  | 1,970 |
Operating | 682 |  | 733 |  | 263 |  | 819 |  |  | 2,497 |  |  | — |  |  | 2,497 |
Netback | 3,042 |  | 3,540 |  | 939 |  | 2,307 |  |  | 9,828 |  |  | — |  |  | 9,828 |
Realized (Gain) Loss on Risk Management |  |  |  |  |  |  |  |  |  | 20 |
Operating Margin |  |  |  |  |  |  |  |  |  | 9,808 |

| Basis of Netback Calculation | Adjustments |  |
Year Ended December 31, 2024 ($ millions) | Total Oil Sands |  | Condensate | Third-party Sourced | Other (2) |  | Total Oil Sands (3)
Gross Sales | 17,563 |  |  | 8,913 |  | 1,531 |  | 440 |  |  | 28,447 |
Royalties | (3,268) |  |  | — |  | — |  | (6) |  |  | (3,274) |
Revenues | 14,295 |  |  | 8,913 |  | 1,531 |  | 434 |  |  | 25,173 |
Expenses |  |  |  |  |  |  |
Purchased Product | — |  |  | — |  | 1,531 |  | 320 |  |  | 1,851 |
Transportation and Blending | 1,970 |  |  | 8,913 |  | — |  | 117 |  |  | 11,000 |
Operating | 2,497 |  |  | — |  | — |  | 14 |  |  | 2,511 |
Netback | 9,828 |  |  | — |  | — |  | (17) |  |  | 9,811 |
Realized (Gain) Loss on Risk Management | 20 |  |  | — |  | — |  | — |  |  | 20 |
Operating Margin | 9,808 |  |  | — |  | — |  | (17) |  |  | 9,791 |

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

| Basis of Netback Calculation
Year Ended December 31, 2023 ($ millions) | Foster Creek | Christina Lake | Sunrise | Lloydminster Oil Sands (1) |  | Total Bitumen and Heavy Oil |  | Natural Gas |  | Total Oil Sands
Gross Sales | 5,347 |  | 5,848 |  | 1,298 |  | 3,208 |  |  | 15,701 |  |  | 8 |  |  | 15,709 |
Royalties | (1,136) |  | (1,556) |  | (74) |  | (285) |  |  | (3,051) |  |  | (5) |  |  | (3,056) |
Revenues | 4,211 |  | 4,292 |  | 1,224 |  | 2,923 |  |  | 12,650 |  |  | 3 |  |  | 12,653 |
Expenses |  |  |  |  |  |  |  |  |  |
Purchased Product | — |  | — |  | — |  | — |  |  | — |  |  | — |  |  | — |
Transportation and Blending | 819 |  | 572 |  | 215 |  | 153 |  |  | 1,759 |  |  | — |  |  | 1,759 |
Operating | 782 |  | 729 |  | 294 |  | 884 |  |  | 2,689 |  |  | 9 |  |  | 2,698 |
Netback | 2,610 |  | 2,991 |  | 715 |  | 1,886 |  |  | 8,202 |  |  | (6) |  |  | 8,196 |
Realized (Gain) Loss on Risk Management |  |  |  |  |  |  |  |  |  | 17 |
Operating Margin |  |  |  |  |  |  |  |  |  | 8,179 |

| Basis of Netback Calculation | Adjustments |  |
Year Ended December 31, 2023 ($ millions) | Total Oil Sands |  | Condensate | Third-party Sourced | Other (2) |  | Total Oil Sands (3)
Gross Sales | 15,709 |  |  | 8,907 |  | 1,199 |  | 377 |  |  | 26,192 |
Royalties | (3,056) |  |  | — |  | — |  | (3) |  |  | (3,059) |
Revenues | 12,653 |  |  | 8,907 |  | 1,199 |  | 374 |  |  | 23,133 |
Expenses |  |  |  |  |  |  |
Purchased Product | — |  |  | — |  | 1,199 |  | 258 |  |  | 1,457 |
Transportation and Blending | 1,759 |  |  | 8,907 |  | — |  | 108 |  |  | 10,774 |
Operating | 2,698 |  |  | — |  | — |  | 18 |  |  | 2,716 |
Netback | 8,196 |  |  | — |  | — |  | (10) |  |  | 8,186 |
Realized (Gain) Loss on Risk Management | 17 |  |  | — |  | — |  | — |  |  | 17 |
Operating Margin | 8,179 |  |  | — |  | — |  | (10) |  |  | 8,169 |

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

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 77

Conventional

| Basis of Netback Calculation |  | Adjustments |  |
Three Months Ended December 31, 2024 ($ millions) | Conventional |  | Third-party Sourced | Other (1) |  | Conventional (2)
Gross Sales | 273 |  |  | 470 |  | 33 |  |  | 776 |
Royalties | (15) |  |  | — |  | — |  |  | (15) |
Revenues | 258 |  |  | 470 |  | 33 |  |  | 761 |
Expenses |  |  |  |  |  |
Purchased Product | — |  |  | 470 |  | — |  |  | 470 |
Transportation and Blending | 52 |  |  | — |  | 27 |  |  | 79 |
Operating | 118 |  |  | — |  | 5 |  |  | 123 |
Netback | 88 |  |  | — |  | 1 |  |  | 89 |
Realized (Gain) Loss on Risk Management | 1 |  |  | — |  | — |  |  | 1 |
Operating Margin | 87 |  |  | — |  | 1 |  |  | 88 |

| Basis of Netback Calculation |  | Adjustments |  |
Three Months Ended December 31, 2023 ($ millions) | Conventional |  | Third-party Sourced | Other (1) |  | Conventional (2)
Gross Sales | 331 |  |  | 437 |  | 38 |  |  | 806 |
Royalties | (27) |  |  | — |  | — |  |  | (27) |
Revenues | 304 |  |  | 437 |  | 38 |  |  | 779 |
Expenses |  |  |  |  |  |
Purchased Product | — |  |  | 437 |  | — |  |  | 437 |
Transportation and Blending | 54 |  |  | — |  | 24 |  |  | 78 |
Operating | 141 |  |  | — |  | 5 |  |  | 146 |
Netback | 109 |  |  | — |  | 9 |  |  | 118 |
Realized (Gain) Loss on Risk Management | (5) |  |  | — |  | — |  |  | (5) |
Operating Margin | 114 |  |  | — |  | 9 |  |  | 123 |

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

| Basis of Netback Calculation |  | Adjustments |  |
Year Ended December 31, 2024 ($ millions) | Conventional |  | Third-party Sourced | Other (1) |  | Conventional (2)
Gross Sales | 1,105 |  |  | 1,823 |  | 131 |  |  | 3,059 |
Royalties | (76) |  |  | — |  | — |  |  | (76) |
Revenues | 1,029 |  |  | 1,823 |  | 131 |  |  | 2,983 |
Expenses |  |  |  |  |  |
Purchased Product | — |  |  | 1,823 |  | — |  |  | 1,823 |
Transportation and Blending | 218 |  |  | — |  | 102 |  |  | 320 |
Operating | 526 |  |  | — |  | 29 |  |  | 555 |
Netback | 285 |  |  | — |  | — |  |  | 285 |
Realized (Gain) Loss on Risk Management | (6) |  |  | — |  | — |  |  | (6) |
Operating Margin | 291 |  |  | — |  | — |  |  | 291 |

| Basis of Netback Calculation |  | Adjustments |  |
Year Ended December 31, 2023 ($ millions) | Conventional |  | Third-party Sourced | Other (1) |  | Conventional (2)
Gross Sales | 1,390 |  |  | 1,695 |  | 188 |  |  | 3,273 |
Royalties | (112) |  |  | — |  | — |  |  | (112) |
Revenues | 1,278 |  |  | 1,695 |  | 188 |  |  | 3,161 |
Expenses |  |  |  |  |  |
Purchased Product | — |  |  | 1,695 |  | — |  |  | 1,695 |
Transportation and Blending | 182 |  |  | — |  | 116 |  |  | 298 |
Operating | 570 |  |  | — |  | 20 |  |  | 590 |
Netback | 526 |  |  | — |  | 52 |  |  | 578 |
Realized (Gain) Loss on Risk Management | (5) |  |  | — |  | — |  |  | (5) |
Operating Margin | 531 |  |  | — |  | 52 |  |  | 583 |

(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 Consolidated Financial Statements.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 78

Offshore

| Basis of Netback Calculation |  | Adjustments |  |
Three Months Ended December 31, 2024 ($ millions) | Atlantic | China | Indonesia (1) | Total Asia Pacific |  | Total Offshore |  | Equity Adjustment (1) | Other (2) |  | Total Offshore (3)
Gross Sales | 58 |  | 315 |  | 110 |  | 425 |  |  | 483 |  |  | (110) |  | — |  |  | 373 |
Royalties | — |  | (25) |  | (27) |  | (52) |  |  | (52) |  |  | 27 |  | — |  |  | (25) |
Revenues | 58 |  | 290 |  | 83 |  | 373 |  |  | 431 |  |  | (83) |  | — |  |  | 348 |
Expenses |  |  |  |  |  |  |  |  |  |  |
Purchased Product | — |  | — |  | — |  | — |  |  | — |  |  | — |  | — |  |  | — |
Transportation and Blending | 2 |  | — |  | — |  | — |  |  | 2 |  |  | — |  | — |  |  | 2 |
Operating | 65 |  | 35 |  | 20 |  | 55 |  |  | 120 |  |  | (19) |  | 3 |  |  | 104 |
Netback | (9) |  | 255 |  | 63 |  | 318 |  |  | 309 |  |  | (64) |  | (3) |  |  | 242 |
Realized (Gain) Loss on Risk Management |  |  |  |  |  | — |  |  | — |  | — |  |  | — |
Operating Margin |  |  |  |  |  | 309 |  |  | (64) |  | (3) |  |  | 242 |

| Basis of Netback Calculation |  | Adjustments |  |
Three Months Ended December 31, 2023 ($ millions) | Atlantic | China | Indonesia (1) | Total Asia Pacific |  | Total Offshore |  | Equity Adjustment (1) | Other (2) |  | Total Offshore (3)
Gross Sales | 168 |  | 346 |  | 91 |  | 437 |  |  | 605 |  |  | (91) |  | — |  |  | 514 |
Royalties | (4) |  | (30) |  | (18) |  | (48) |  |  | (52) |  |  | 18 |  | — |  |  | (34) |
Revenues | 164 |  | 316 |  | 73 |  | 389 |  |  | 553 |  |  | (73) |  | — |  |  | 480 |
Expenses |  |  |  |  |  |  |  |  |  |  |
Purchased Product | — |  | — |  | — |  | — |  |  | — |  |  | — |  | — |  |  | — |
Transportation and Blending | 7 |  | — |  | — |  | — |  |  | 7 |  |  | — |  | — |  |  | 7 |
Operating | 71 |  | 29 |  | 17 |  | 46 |  |  | 117 |  |  | (15) |  | 1 |  |  | 103 |
Netback | 86 |  | 287 |  | 56 |  | 343 |  |  | 429 |  |  | (58) |  | (1) |  |  | 370 |
Realized (Gain) Loss on Risk Management |  |  |  |  |  | — |  |  | — |  | — |  |  | — |
Operating Margin |  |  |  |  |  | 429 |  |  | (58) |  | (1) |  |  | 370 |

(1)Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the interim Consolidated Financial Statements.
(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 |  | Adjustments |  |
Year Ended December 31, 2024 ($ millions) | Atlantic | China | Indonesia (1) | Total Asia Pacific |  | Total Offshore |  | Equity Adjustment (1) | Other (2) |  | Total Offshore (3)
Gross Sales | 322 |  | 1,250 |  | 339 |  | 1,589 |  |  | 1,911 |  |  | (339) |  | — |  |  | 1,572 |
Royalties | (2) |  | (97) |  | (55) |  | (152) |  |  | (154) |  |  | 55 |  | — |  |  | (99) |
Revenues | 320 |  | 1,153 |  | 284 |  | 1,437 |  |  | 1,757 |  |  | (284) |  | — |  |  | 1,473 |
Expenses |  |  |  |  |  |  |  |  |  |  |
Purchased Product | — |  | — |  | — |  | — |  |  | — |  |  | — |  | — |  |  | — |
Transportation and Blending | 11 |  | — |  | — |  | — |  |  | 11 |  |  | — |  | — |  |  | 11 |
Operating | 287 |  | 119 |  | 64 |  | 183 |  |  | 470 |  |  | (56) |  | 9 |  |  | 423 |
Netback | 22 |  | 1,034 |  | 220 |  | 1,254 |  |  | 1,276 |  |  | (228) |  | (9) |  |  | 1,039 |
Realized (Gain) Loss on Risk Management |  |  |  |  |  | — |  |  | — |  | — |  |  | — |
Operating Margin |  |  |  |  |  | 1,276 |  |  | (228) |  | (9) |  |  | 1,039 |

| Basis of Netback Calculation |  | Adjustments |  |
Year Ended December 31, 2023 ($ millions) | Atlantic | China | Indonesia (1) | Total Asia Pacific |  | Total Offshore |  | Equity Adjustment (1) | Other (2) |  | Total Offshore (3)
Gross Sales | 400 |  | 1,217 |  | 317 |  | 1,534 |  |  | 1,934 |  |  | (317) |  | — |  |  | 1,617 |
Royalties | (15) |  | (84) |  | (74) |  | (158) |  |  | (173) |  |  | 74 |  | — |  |  | (99) |
Revenues | 385 |  | 1,133 |  | 243 |  | 1,376 |  |  | 1,761 |  |  | (243) |  | — |  |  | 1,518 |
Expenses |  |  |  |  |  |  |  |  |  |  |
Purchased Product | — |  | — |  | — |  | — |  |  | — |  |  | — |  | — |  |  | — |
Transportation and Blending | 16 |  | — |  | — |  | — |  |  | 16 |  |  | — |  | — |  |  | 16 |
Operating | 239 |  | 111 |  | 58 |  | 169 |  |  | 408 |  |  | (47) |  | 23 |  |  | 384 |
Netback | 130 |  | 1,022 |  | 185 |  | 1,207 |  |  | 1,337 |  |  | (196) |  | (23) |  |  | 1,118 |
Realized (Gain) Loss on Risk Management |  |  |  |  |  | — |  |  | — |  | — |  |  | — |
Operating Margin |  |  |  |  |  | 1,337 |  |  | (196) |  | (23) |  |  | 1,118 |

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

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 79

Upstream Sales Volumes (1)
The following table provides the sales volumes used to calculate Netback:

| Three Months Ended December 31, |  | Year Ended December 31,
(MBOE/d) | 2024 |  | 2023 |  | 2024 |  | 2023
Oil Sands (2) |  |  |  |  |  |  |
Foster Creek | 184.0 |  |  | 192.6 |  |  | 188.8 |  |  | 187.4 |
Christina Lake | 245.7 |  |  | 238.6 |  |  | 231.9 |  |  | 234.3 |
Sunrise | 52.2 |  |  | 50.8 |  |  | 50.0 |  |  | 47.3 |
Lloydminster | 125.9 |  |  | 123.4 |  |  | 127.7 |  |  | 120.5 |
Total Oil Sands | 607.8 |  |  | 605.4 |  |  | 598.4 |  |  | 589.5 |
Conventional | 117.8 |  |  | 123.8 |  |  | 119.9 |  |  | 119.9 |
Offshore |  |  |  |  |  |  |
Atlantic | 6.2 |  |  | 15.0 |  |  | 8.0 |  |  | 9.6 |
Asia Pacific |  |  |  |  |  |  |
China | 42.6 |  |  | 44.2 |  |  | 42.6 |  |  | 40.5 |
Indonesia | 19.6 |  |  | 16.3 |  |  | 16.0 |  |  | 14.7 |
Total Asia Pacific | 62.2 |  |  | 60.5 |  |  | 58.6 |  |  | 55.2 |
Total Offshore | 68.4 |  |  | 75.5 |  |  | 66.6 |  |  | 64.8 |

(1)Sales volumes exclude the impact of purchased condensate.
(2)Includes bitumen and heavy crude oil sales.
Other Specified Financial Measures
Per-Unit Operating Expenses and Turnaround Costs
Per-unit operating expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. 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 operating expenses – excluding turnaround costs are specified financial measures used to evaluate the normalized performance of our downstream operations. We define per-unit operating expenses – excluding turnaround costs as the refining segments’ operating expenses – excluding turnaround costs divided by total processed inputs.
Per-unit operating expenses – turnaround costs are specified financial measures used to evaluate the cost of turnarounds for our downstream operations. We define per-unit operating expenses – turnaround costs as the refining segments’ operating expenses – turnaround costs divided by total processed inputs.
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.
Per-Unit Transportation Expenses
Per-unit transportation expenses are specified financial measures used to measure transportation expenses on a per-unit basis in our upstream segments. We define per-unit transportation expenses as the total transportation expenses divided by sales volumes. Our upstream per-unit transportation expenses are part of the transportation and blending line in our Netback calculation, which can be found above.
Per-Unit Depreciation, Depletion and Amortization
Per-unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define per-unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties, and the associated decommissioning costs, divided by sales volumes.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 80

Prior Period Revisions

During the three months ended December 31, 2024, it was identified that certain transactions in the U.S Refining segment undertaken in contemplation of each other 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. Prior quarters have been restated to reflect the change. There was no impact on net earnings (loss), segment income (loss), cash flows or financial position.
The following tables reconcile the amounts previously reported in the Consolidated Statements of Comprehensive Income (Loss) and segmented disclosures to the corresponding revised amounts:

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

| U.S. Refining Segment |  | Consolidated
For the three months ended June 30, 2024 | Previously Reported |  | Revisions |  | Revised Balance |  | Previously Reported |  | Revisions |  | Revised Balance
Revenues | 7,918 |  |  | (303) |  |  | 7,615 |  | 14,885 |  |  | (303) |  |  | 14,582
Purchased Product | 7,124 |  |  | (303) |  |  | 6,821 |  |  | 7,184 |  |  | (303) |  |  | 6,881 |
Transportation and Blending | — |  |  | — |  |  | — |  |  | 2,865 |  |  | — |  |  | 2,865 |
Purchased Product, Transportation and Blending (1) | 7,124 |  |  | (303) |  |  | 6,821 |  |  | 10,049 |  |  | (303) |  |  | 9,746 |
| 794 |  |  | — |  |  | 794 |  |  | 4,836 |  |  | — |  |  | 4,836 |

| U.S. Refining Segment |  | Consolidated
For the three months ended September 30, 2024 | Previously Reported |  | Revisions |  | Revised Balance |  | Previously Reported |  | Revisions |  | Revised Balance
Revenues | 7,648 |  |  | (430) |  |  | 7,218 |  | 14,249 |  |  | (430) |  |  | 13,819
Purchased Product | 7,284 |  |  | (430) |  |  | 6,854 |  |  | 7,556 |  |  | (430) |  |  | 7,126 |
Transportation and Blending | — |  |  | — |  |  | — |  |  | 2,489 |  |  | — |  |  | 2,489 |
Purchased Product, Transportation and Blending (1) | 7,284 |  |  | (430) |  |  | 6,854 |  |  | 10,045 |  |  | (430) |  |  | 9,615 |
| 364 |  |  | — |  |  | 364 |  |  | 4,204 |  |  | — |  |  | 4,204 |

(1)Revised presentation as of January 1, 2024. Refer to Note 4 of the Consolidated Financial Statements for further detail.

Cenovus Energy Inc. – 2024 Management's Discussion and Analysis | 81