Cenovus Energy

ANNUAL REPORT
2024

For additional information about forward‑looking statements, specified financial measures and reserves contained in this 
Annual Report, see the Advisory on page 132.
Message from our President & Chief Executive Officer
3
Management’s Discussion and Analysis
4
Consolidated Financial Statements
68
Notes to Consolidated Financial Statements
77 
Supplemental information
125
Advisory
132
Information for shareholders
149
 TABLE OF  
CONTENTS
At Cenovus, our purpose is to energize the world to make 
people’s lives better.

CENOVUS ENERGY 2024 ANNUAL REPORT   |   3
Cenovus achieved significant operational and financial 
milestones in 2024, marking a year of solid performance and 
meaningful returns to our shareholders. Our continued focus 
on operational efficiency, safety and financial discipline has 
ensured we are well-positioned for future growth and to 
navigate the evolving energy landscape. 
At the core of our success is safety, which remains 
fundamental to everything we do. In 2024, we had our 
best‑ever process safety performance, making us a 
top‑quartile performer in this area ‒ a trend we’ve continued 
since 2022.
Our financial discipline has resulted in one of the strongest 
balance sheets in our industry. Last year we met our  
$4.0 billion net debt target, enabling us to return 100%  
of excess free funds flow to shareholders, over and above our 
regular dividends. In 2024, we had $3.2 billion of cash returns to 
our common and preferred shareholders in the form of base 
and variable dividends, common share purchases, and through 
preferred share redemptions.
Since 2021, the company’s total shareholder returns on a 
relative basis have outperformed the S&P/TSX composite and 
energy indices by 144% and 50% respectively.  
Our financial performance is driven by operational excellence 
in our Upstream operations, with daily and annual production 
records at our Oil Sands operations. 
2024 marked the first year our U.S. Downstream network 
was fully operational, and we’re moving quickly to make that 
business competitive and profitable. Throughput, utilization 
and costs are all trending positively, and I’m pleased with the 
work underway to further strengthen this part of the business.
Mid-to late 2025 will mark a significant inflection point for 
our company. Our capital spending decreases as we complete 
a number of growth projects, and we begin to see the first 
of our 150,000 barrels per day of growth. All our key growth 
projects remain on track towards completion and are expected 
to result in a material rate of change in our free cash flow 
through 2026 and beyond. This free cash flow profile, along 
with our strong balance sheet, positions the company well to 
manage continued volatility in commodity prices, return cash 
to shareholders and strategically invest in the business.  
As we look to the future, we are focused on maintaining a 
competitive cost structure, through innovation, streamlining 
our operations – foundational for our ability to grow – and a 
strong balance sheet. Keeping our business robust is essential 
in this time of continually evolving market dynamics.
We know that Canadians, and the world, rely on the essential 
natural resources our industry provides. We are proud to 
advocate for our company and industry, sharing the benefits 
our sector responsibly delivers. 
I want to thank the shareholders, and our Board, employees 
and contractors, for your ongoing support. I am looking 
forward to the significant year we have ahead.
Message from our President & Chief Executive Officer
Jon McKenzie
Keeping our business 
robust is essential 
in this time of 
continually evolving 
market dynamics.

4   |   CENOVUS ENERGY 2024 ANNUAL REPORT
Management’s Discussion  
and Analysis (unaudited)
For the year ended December 31, 2024 
(Canadian dollars)
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.
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 of the Advisory for commonly used oil and gas terms.
Overview of Cenovus
5
Year in review
5
Operating and financial results
8
Commodity prices underlying  
our financial results
13
Outlook
16
Reportable segments
19
Upstream 
19
Oil Sands
19
Conventional
24
Offshore
26
Downstream
30
Canadian Refining
30
U.S. Refining
31
Corporate and eliminations
34
Quarterly results
36
Oil and gas reserves
39
Liquidity and capital resources
40
Risk management and risk factors
45
Critical accounting judgments, 
estimation uncertainties and  
accounting policies
64
Control environment
67

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   5

•
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
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6   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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 Advisory. 
(5)
Specified financial measure. See the Specified Financial Measures Advisory.
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   7

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.
(3)
Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory. 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
8   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
(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
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   9

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
($ millions)
9,791
291
1,039
(80)
(232)
8,169
583
1,118
675
477
2024
2023
Oil Sands
Conventional 
Offshore
Canadian Refining
U.S. Refining
(5,000)
—
5,000
10,000
15,000
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
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10   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   11

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
12   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   13

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)
(average US$/bbl)
WTI
WCS at Hardisty
WCS at Nederland
Dated Brent
Synthetic at Edmonton
Q4
2022
Q1
2023
Q2
2023
Q3
2023
Q4 
2023
Q1
2024
Q2
2024
Q3
2024
Q4
2024
Q1
2025F
Q2
2025F
Q3
2025F
Q4
2025F
40
60
80
100
(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
14   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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$1.00/bbl relative to the fourth quarter of 2023. 
Average cost of RINs were also lower in 2024 compared with 2023, due to a decline in biofuel feedstock costs and increased 
renewable diesel production.
North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices. 
The strength of refining market crack spreads in the U.S. Midwest and Midcontinent generally reflects the differential between 
Brent and WTI benchmark prices.
Our refining margins are affected by various other factors such as the quality and purchase location of crude oil feedstock, 
refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the 
feedstock is valued on a first in, first out (“FIFO”) accounting basis. The market crack spreads do not precisely mirror the 
configuration and product output of our refineries, or the location we sell product; however, they are used as a general market 
indicator.
Refined Product Benchmarks (1)
(average US$/bbl)
(average US$/bbl - RUL and ULSD)
Chicago 3-2-1 Crack Spread
Group 3 3-2-1 Crack Spread
RUL
ULSD
Q4
2022
Q1
2023
Q2
2023
Q3
2023
Q4 
2023
Q1
2024
Q2
2024
Q3
2024
Q4
2024
Q1
2025F
Q2
2025F
Q3
2025F
Q4
2025F
0
10
20
30
40
50
60
70
0
25
50
75
100
125
150
175
(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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   15

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
16   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   17

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
18   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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 usage of crude oil, natural gas, condensate, other NGLs and refined 
products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail 
terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and 
sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.
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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   19

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 
($ millions)
8,169
1,571
281
6
(212)
(217)
201
(7)
9,791
Year Ended
December 31, 
2023
Price (1)
Volume
Condensate
Revenue (1)
Royalties
Transportation 
and
Blending (1)
Operating 
Expenses
Other (2)
Year Ended
December 31, 
2024
—
5,000
10,000
15,000
(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
20   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
(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.
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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   21

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.
(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
22   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
(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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   23

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.
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
24   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Operating Margin Variance
Year Ended December 31, 2024
($ millions)
583
(288)
36
(36)
44
(48)
291
Year Ended 
December 31, 
2023
Price (1)
Royalties
Transportation 
and
Blending
Operating 
Expenses
Other (2)
Year Ended 
December 31, 
2024
—
200
400
600
800
(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.
(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.
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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   25

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.
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
26   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
Operating Margin Variance
Year Ended December 31, 2024
($ millions)
1,118
(66)
21
5
(56)
17
1,039
Year Ended
December 31, 
2023
Price
Volume
Transportation 
and
Blending
Operating 
Expenses
Other
Year Ended
December 31, 
2024
—
500
1,000
1,500
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
 25
CENOVUS ENERGY 2024 ANNUAL REPORT   |   27

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.
(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.
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
28   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
(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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   29

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. 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 the Advisory. 
(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
30   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   31

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.
(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 the Advisory. 
(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
32   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   33

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
34   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   35

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 the Advisory.
(5)
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory.
(6)
Specified financial measure. See the Specified Financial Measures Advisory.
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
 34
36   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   37

Operating Margin
Three Months Ended December 31, 2024 and 2023
($ millions)
2,340
88
242
47
(443)
1,962
123
370
126
(430)
2024
2023
Oil Sands
Conventional 
Offshore
Canadian Refining
U.S. Refining
(1,000)
—
1,000
2,000
3,000
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
38   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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 of this MD&A and the Advisory.
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   39

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
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40   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
(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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   41

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
42   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   43

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).
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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. 
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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. 
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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 for 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. 
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
 63
CENOVUS ENERGY 2024 ANNUAL REPORT   |   65

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.
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
 64
66   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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.
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
 65
CENOVUS ENERGY 2024 ANNUAL REPORT   |   67

CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2024 
(Canadian dollars)
REPORT OF MANAGEMENT	
 69
REPORT OF INDEPENDENT REGISTERED PUBLIC  
ACCOUNTING FIRM	
 70
CONSOLIDATED STATEMENTS OF COMPREHENSIVE  
INCOME (LOSS)	
 73
CONSOLIDATED BALANCE SHEETS	
 74
CONSOLIDATED STATEMENTS OF EQUITY	
 75
CONSOLIDATED STATEMENTS OF CASH FLOWS	
 76
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	
 77
	
1.	 DESCRIPTION OF BUSINESS AND  
	
	
SEGMENTED DISCLOSURES	
 77
	
2.	 BASIS OF PREPARATION AND STATEMENT  
	
	
OF COMPLIANCE	
 82
	
3. 	 CRITICAL ACCOUNTING JUDGMENTS AND  
	
	
KEY SOURCES OF ESTIMATION UNCERTAINTY	
 82
	
4. 	 UPDATES TO ACCOUNTING POLICIES	
 84
	
5. 	 ACQUISITIONS AND DIVESTITURES	
 85
	
6. 	 GENERAL AND ADMINISTRATIVE	
 86
	
7. 	 FINANCE COSTS, NET	
 86
	
8. 	 FOREIGN EXCHANGE (GAIN) LOSS, NET	
 86
	
9. 	 IMPAIRMENT CHARGES AND REVERSALS	
 86
	
10. 	INCOME TAXES	
 88
	
11. 	 PER SHARE AMOUNTS	
 91
	
12. 	CASH AND CASH EQUIVALENTS	
 92
	
13. 	ACCOUNTS RECEIVABLE AND ACCRUED REVENUES	
 92
	
14. 	INVENTORIES	
 92
	
15. 	EXPLORATION AND EVALUATION ASSETS, NET	
 93
	
16. 	PROPERTY, PLANT AND EQUIPMENT, NET	
 94
	
17. 	 LEASES	
 95
	
18. 	JOINT ARRANGEMENTS	
 96
	
19. 	OTHER ASSETS	
 97
	
20. 	GOODWILL	
 97
	
21. 	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES	
 97
	
22. 	DEBT AND CAPITAL STRUCTURE	
 97
	
23. 	CONTINGENT PAYMENTS	
 101
	
24. 	DECOMMISSIONING LIABILITIES	
 101
	
25. 	OTHER LIABILITIES	
 102
	
26. 	PENSIONS AND OTHER  
	
	
POST-EMPLOYMENT BENEFITS	
 102
	
27. 	SHARE CAPITAL AND WARRANTS	
 105
	
28. 	ACCUMULATED OTHER COMPREHENSIVE  
	
	
INCOME (LOSS)	
 108
	
29. 	STOCK-BASED COMPENSATION PLANS	
 108
	
30. 	EMPLOYEE SALARIES AND BENEFIT EXPENSES	
 111
	
31. 	RELATED PARTY TRANSACTIONS	
 111
	
32. 	FINANCIAL INSTRUMENTS	
 112
	
33. 	RISK MANAGEMENT	
 114
	
34. 	SUPPLEMENTARY CASH FLOW INFORMATION	
 117
	
35. 	COMMITMENTS AND CONTINGENCIES	
 119
	
36. 	MATERIAL ACCOUNTING POLICIES	
119
68   |   CENOVUS ENERGY 2024 ANNUAL REPORT

REPORT OF MANAGEMENT 
Management’s Responsibility for the Consolidated Financial Statements 
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The 
Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International 
Financial Reporting Accounting Standards as issued by the International Accounting Standards Board and include certain 
estimates that reflect Management’s best judgments. 
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of 
Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of 
four independent directors. The Audit Committee has a written mandate that complies with the current requirements of 
Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with 
the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the 
independent auditors on at least a quarterly basis to review and recommend the approval of the interim Consolidated Financial 
Statements and Management’s Discussion and Analysis to the Board of Directors prior to their public release, as well as 
annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend 
their approval to the Board of Directors. 
Management’s Assessment of Internal Control Over Financial Reporting 
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The 
internal control system was designed to provide reasonable assurance to Management regarding the preparation and 
presentation of the Consolidated Financial Statements. 
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. 
Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2024. In 
making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission 
framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over 
financial reporting. Based on their evaluation, Management has concluded that internal control over financial reporting was 
effective as at December 31, 2024. 
PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed to audit and provide 
independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at 
December 31, 2024, as stated in their Report of Independent Registered Public Accounting Firm dated February 19, 2025. 
PricewaterhouseCoopers LLP has provided such opinions. 
/s/ Jonathan M. McKenzie
/s/ Karamjit S. Sandhar
Jonathan M. McKenzie
Karamjit S. Sandhar
President & Chief Executive Officer
Executive Vice-President & Chief Financial Officer
Cenovus Energy Inc.
Cenovus Energy Inc.
February 19, 2025
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
3
CENOVUS ENERGY 2024 ANNUAL REPORT   |   69

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
To the Shareholders and Board of Directors of Cenovus Energy Inc. 
Opinions on the Financial Statements and Internal Control Over Financial Reporting 
We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. and its subsidiaries (together, the 
Company) as of December 31, 2024 and 2023, and the related consolidated statements of comprehensive income (loss), of 
equity and of cash flows for the years then ended, including the related notes (collectively referred to as the Consolidated 
Financial Statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2024, 
based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring 
Organizations of the Treadway Commission (COSO).
In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial 
position of the Company as of December 31, 2024 and 2023, and its financial performance and its cash flows for the years then 
ended in conformity with International Financial Reporting Standards as issued by the International Accounting Standards 
Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting 
as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.
Basis for Opinions 
The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective internal 
control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included 
in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our responsibility is to express 
opinions on the Company’s Consolidated Financial Statements and on the Company’s internal control over financial reporting 
based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United 
States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities 
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform 
the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material 
misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in 
all material respects. 
Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material 
misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that 
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in 
the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant 
estimates made by Management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our 
audit of internal control over financial reporting included obtaining an understanding of internal control over financial 
reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness 
of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered 
necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. 
Definition and Limitations of Internal Control over Financial Reporting 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the 
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally 
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures 
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and 
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to 
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and 
expenditures of the company are being made only in accordance with authorizations of management and directors of the 
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or 
disposition of the company’s assets that could have a material effect on the financial statements. 
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
4
70   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.
Critical Audit Matters 
The critical audit matters communicated below are matters arising from the current period audit of the Consolidated Financial 
Statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or 
disclosures that are material to the Consolidated Financial Statements and (ii) involved our especially challenging, subjective, or 
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the Consolidated 
Financial Statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate 
opinions on the critical audit matters or on the accounts or disclosures to which they relate. 
Impact of Crude Oil and Natural Gas Reserves (together, the Reserves) on Property, Plant and Equipment (PP&E), Net within the 
Oil Sands and Offshore Segments
As described in Notes 1, 3, 9, 16 and 36 to the Consolidated Financial Statements, Management assesses its cash-generating 
units (CGUs) for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying 
amount of a CGU, which is net of accumulated depreciation, depletion and amortization (DD&A) and net impairment losses, 
may exceed its recoverable amount. Management calculates depletion for Oil Sands PP&E using the unit-of-production method 
based on estimated proved reserves. For Offshore PP&E, Management calculates depletion using the unit-of-production 
method based on estimated proved developed producing reserves or proved plus probable reserves. Costs subject to depletion 
include estimated future development costs to be incurred in developing those proved or proved plus probable reserves. As of 
December 31, 2024, the Company had $24.6 billion and $3.4 billion in Oil Sands and Offshore PP&E, net, respectively. In 
aggregate, the Company recognized $3.7 billion of DD&A expense and noted no indicators of impairment related to PP&E in the 
Oil Sands and Offshore segments in the year ended December 31, 2024. Estimating reserves requires the use of significant 
assumptions and judgments by Management related to expected future production volumes, future development and 
operating expenses, as well as forward commodity prices. Management’s estimates of reserves used for the calculation of 
DD&A expense related to PP&E in the Oil Sands and Offshore segments have been developed by Management’s specialists, 
specifically independent qualified reserves evaluators. 
The principal considerations for our determination that performing procedures relating to the impact of reserves on PP&E, net, 
within the Oil Sands and Offshore segments is a critical audit matter are (i) the significant amount of judgment required by 
Management, including the use of Management’s specialists, when developing the estimates of reserves; and (ii) there was a 
high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained 
related to expected future production volumes, future development and operating expenses, as well as forward commodity 
prices. 
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall 
opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to 
Management’s estimates of reserves and the calculation of DD&A expenses related to PP&E in the Oil Sands and Offshore 
segments. These procedures also included, among others, testing Management’s process for determining DD&A expense for 
the Oil Sands and Offshore segments, which included for certain properties (i) evaluating the appropriateness of the methods 
used by Management in making these estimates; (ii) testing the completeness and accuracy of the underlying data used in 
Management’s estimates of reserves; (iii) assessing the reasonability of the significant assumptions related to expected future 
production volumes, future development and operating expenses, as well as forward commodity prices, and (iv) testing the 
unit-of-production rates used to calculate DD&A expense. The work of Management’s specialists was used in performing the 
procedures to evaluate the reasonableness of the estimated reserves used in the calculation of DD&A expense related to PP&E 
in the Oil Sands and Offshore segments. As a basis for using this work, the specialists’ qualifications were understood, and the 
Company’s relationship with the specialists was assessed. The procedures performed also included for certain properties within 
the Oil Sands and Offshore segments, evaluation of the methods and significant assumptions used by the specialists, tests of 
data used by the specialists and an evaluation of the specialists’ findings. Evaluating the significant assumptions used by 
Management’s specialists related to expected future production volumes, future development and operating expenses, as well 
as forward commodity prices involved assessing whether the assumptions used were reasonable considering the current and 
past performance of the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the 
audit, as applicable.
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
5
CENOVUS ENERGY 2024 ANNUAL REPORT   |   71

Impairment Assessment of PP&E for each of the Wood River, Toledo, and Lima CGUs within the U.S. Refining Segment
As described in Notes 1, 3, 9, 16 and 36 to the Consolidated Financial Statements, Management assesses its CGUs for indicators 
of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of 
accumulated DD&A including net impairment losses, may exceed its recoverable amount. If indicators of impairment exist, the 
recoverable amount of the CGU is estimated as the greater of value-in-use and fair value less costs of disposal (FVLCOD). As of 
December 31, 2024, the Company had $5.5 billion of PP&E assets net of accumulated DD&A including net impairment losses 
relating to the U.S. Refining segment, of which the majority related to the Wood River, Toledo, and Lima CGUs. Management 
identified indicators of impairment for these CGUs and performed impairment assessments for each of these CGUs as of 
December 31, 2024. The recoverable amounts of these CGUs were determined to be greater than their carrying amounts and 
no impairment charge was recorded. Management determined the recoverable amounts of these CGUs based on their FVLCOD 
using discounted after-tax cash flows models requiring the use of significant assumptions and judgments by Management 
related to refined product production, forward crude oil prices, forward crack spreads, net of renewable identification numbers 
(RINs), future operating expenses, future capital expenditures and discount rates.
The principal considerations for our determination that performing procedures relating to the impairment assessment of PP&E 
for each of the Wood River, Toledo, and Lima CGUs within the U.S. Refining segment is a critical audit matter are (i) the 
significant amount of judgment required by Management when developing the recoverable amounts for these CGUs; (ii) a high 
degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in 
developing these estimates including refined product production, forward crude oil prices, forward crack spreads, net of RINs, 
future operating expenses, future capital expenditures and discount rates; and (iii) the audit effort involved the use of 
professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall 
opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to 
Management’s determination of the recoverable amounts of the Wood River, Toledo, and Lima CGUs within the U.S. Refining 
segment. These procedures also included, among others, testing Management’s process for determining the recoverable 
amounts of these CGUs, which included (i) evaluating the appropriateness of the methods used by Management in making 
these estimates; (ii) testing the completeness and accuracy of underlying data used in these models; and (iii) assessing the 
reasonability of the significant assumptions used by Management, including refined product production, forward crude oil 
prices, forward crack spreads, net of RINs, future operating expenses, future capital expenditures and discount rates. Evaluating 
these significant assumptions used by Management involved assessing whether they were reasonable considering the current 
and past performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained in 
other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the 
overall reasonableness of the recoverable amounts of these CGUs, including the discount rates. 
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 19, 2025
We have served as the Company’s auditor since 2008.
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
6
72   |   CENOVUS ENERGY 2024 ANNUAL REPORT

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the years ended December 31,
($ millions, except per share amounts)
Notes
2024
2023
Revenues (1)
1
54,277
52,204
Expenses
1
Purchased Product, Transportation and Blending (1)
36,641
34,856
Operating
6,841
6,352
(Gain) Loss on Risk Management
32
58
61
Depreciation, Depletion, Amortization and Exploration Expense (1)
15,16,17
4,940
4,686
(Income) Loss From Equity-Accounted Affiliates
18
(66)
(51)
General and Administrative
6
794
688
Finance Costs, Net (1)
7
514
538
Integration, Transaction and Other Costs
166
85
Foreign Exchange (Gain) Loss, Net
8
462
(67)
(Gain) Loss on Divestiture of Assets (1)
5
(119)
20
Re-measurement of Contingent Payments
23
30
59
Other (Income) Loss, Net
(55)
(63)
Earnings (Loss) Before Income Tax
4,071
5,040
Income Tax Expense (Recovery)
10
929
931
Net Earnings (Loss)
3,142
4,109
Other Comprehensive Income (Loss), Net of Tax
28
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits
26
14
(44)
Change in the Fair Value of Equity Instruments at FVOCI (2)
32
71
56
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment
1,020
(274)
Total Other Comprehensive Income (Loss), Net of Tax
1,105
(262)
Comprehensive Income (Loss)
4,247
3,847
Net Earnings (Loss) Per Common Share ($)
11
Basic
1.68
2.15
Diluted
1.67
2.09
(1)
Revised presentation as of January 1, 2024. See Note 4. 
(2)
Fair value through other comprehensive income (loss) (“FVOCI”).
See accompanying Notes to the Consolidated Financial Statements.
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
7
CENOVUS ENERGY 2024 ANNUAL REPORT   |   73

CONSOLIDATED BALANCE SHEETS
As at December 31, 
($ millions)
Notes
2024
2023
Assets
Current Assets
Cash and Cash Equivalents
12
3,093
2,227
Accounts Receivable and Accrued Revenues
13
2,614
3,035
Income Tax Receivable
231
416
Inventories
14
4,496
4,030
Total Current Assets
10,434
9,708
Restricted Cash
24
241
211
Exploration and Evaluation Assets, Net
1,15
484
738
Property, Plant and Equipment, Net
1,16
38,568
37,250
Right-of-Use Assets, Net
1,17
1,950
1,680
Income Tax Receivable
25
25
Investments in Equity-Accounted Affiliates
18
399
366
Other Assets
19
451
318
Deferred Income Taxes
10
1,064
696
Goodwill
1,20
2,923
2,923
Total Assets
56,539
53,915
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
21
6,242
5,480
Income Tax Payable
396
88
Short-Term Borrowings
22
173
179
Long-Term Debt
22
192
—
Lease Liabilities
17
359
299
Contingent Payments
23
—
164
Total Current Liabilities
7,362
6,210
Long-Term Debt
22
7,342
7,108
Lease Liabilities
17
2,568
2,359
Decommissioning Liabilities
24
4,534
4,155
Other Liabilities
25
919
1,183
Deferred Income Taxes
10
4,045
4,188
Total Liabilities
26,770
25,203
Shareholders’ Equity
29,754
28,698
Non-Controlling Interest
15
14
Total Liabilities and Equity
56,539
53,915
Commitments and Contingencies
35
See accompanying Notes to the Consolidated Financial Statements.
/s/ Alexander J. Pourbaix
/s/ Jane E. Kinney
Alexander J. Pourbaix
Jane E. Kinney
Director
Director
Cenovus Energy Inc.
Cenovus Energy Inc.
February 19, 2025
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
8
74   |   CENOVUS ENERGY 2024 ANNUAL REPORT

CONSOLIDATED STATEMENTS OF EQUITY
($ millions)
Shareholders’ Equity
Common 
Shares
Treasury
Shares
Preferred 
Shares
Warrants
Paid in
Surplus
Retained
Earnings
AOCI (1)
Total
(Note 27)
(Note 27)
(Note 27)
(Note 27)
(Note 27)
(Note 28)
As at December 31, 2022
16,320
—
519
184
2,691
6,392
1,470
27,576
Net Earnings (Loss)
—
—
—
—
—
4,109
—
4,109
Other Comprehensive Income
   (Loss), Net of Tax
—
—
—
—
—
—
(262)
(262)
Total Comprehensive Income (Loss)
—
—
—
—
—
4,109
(262)
3,847
Common Shares Issued Under
    Stock Option Plans
58
—
—
—
(12)
—
—
46
Purchase of Common Shares Under
   NCIB (2)
(373)
—
—
—
(688)
—
—
(1,061)
Warrants Exercised
26
—
—
(8)
—
—
—
18
Warrants Purchased and Cancelled
—
—
—
(151)
—
(562)
—
(713)
Stock-Based Compensation 
   Expense
—
—
—
—
11
—
—
11
Base Dividends on Common Shares
—
—
—
—
—
(990)
—
(990)
Dividends on Preferred Shares
—
—
—
—
—
(36)
—
(36)
As at December 31, 2023
16,031
—
519
25
2,002
8,913
1,208
28,698
Net Earnings (Loss)
—
—
—
—
—
3,142
—
3,142
Other Comprehensive Income 
   (Loss), Net of Tax
—
—
—
—
—
—
1,105
1,105
Total Comprehensive Income (Loss)
—
—
—
—
—
3,142
1,105
4,247
Common Shares Issued Under
   Stock Option Plans
68
—
—
—
(16)
—
—
52
Purchase of Common Shares Under
   NCIB (2)
(479)
—
—
—
(966)
—
—
(1,445)
Purchase of Common Shares Under
   Employee Benefit Plan
—
(43)
—
—
—
—
—
(43)
Preferred Shares Redeemed
—
—
(163)
—
(87)
—
—
(250)
Warrants Exercised
39
—
—
(13)
—
—
—
26
Stock-Based Compensation 
   Expense
—
—
—
—
11
—
—
11
Base Dividends on Common Shares
—
—
—
—
—
(1,255)
—
(1,255)
Variable Dividends on Common 
   Shares
—
—
—
—
—
(251)
—
(251)
Dividends on Preferred Shares
—
—
—
—
—
(36)
—
(36)
As at December 31, 2024
15,659
(43)
356
12
944
10,513
2,313
29,754
(1)
Accumulated other comprehensive income (loss) (“AOCI”).
(2)
Normal course issuer bid (“NCIB”). For the year ended December 31, 2024, amount includes taxes payable on purchase of shares. 
See accompanying Notes to the Consolidated Financial Statements.
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
9
CENOVUS ENERGY 2024 ANNUAL REPORT   |   75

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
Notes
2024
2023
Operating Activities
Net Earnings (Loss)
3,142
4,109
Depreciation, Depletion and Amortization
16,17
4,871
4,644
Deferred Income Tax Expense (Recovery)
10
(474)
(250)
Unrealized (Gain) Loss on Risk Management
32
12
52
Unrealized Foreign Exchange (Gain) Loss
8
550
(210)
Realized Foreign Exchange (Gain) Loss on Non-Operating Items
—
98
(Gain) Loss on Divestiture of Assets (1)
5
(119)
20
Re-measurement of Contingent Payments
23
30
59
Unwinding of Discount on Decommissioning Liabilities
24
225
220
(Income) Loss From Equity-Accounted Affiliates
18
(66)
(51)
Distributions Received From Equity-Accounted Affiliates
18
172
149
Stock-Based Compensation, Net of Payments
(145)
(12)
Other
(34)
(25)
Settlement of Decommissioning Liabilities
24
(234)
(222)
Net Change in Non-Cash Working Capital
34
1,305
(1,193)
Cash From (Used in) Operating Activities
9,235
7,388
Investing Activities
Acquisitions, Net of Cash Acquired
5
(22)
(515)
Capital Investment
1
(5,015)
(4,298)
Proceeds From Divestitures
5
46
12
Net Change in Investments and Other
(80)
(125)
Net Change in Non-Cash Working Capital
34
(55)
(369)
Cash From (Used in) Investing Activities
(5,126)
(5,295)
Net Cash Provided (Used) Before Financing Activities
4,109
2,093
Financing Activities
34
Net Issuance (Repayment) of Short-Term Borrowings
5
58
Repayment of Long-Term Debt
22
—
(1,346)
Principal Repayment of Leases
17
(299)
(288)
Common Shares Issued Under Stock Option Plans
52
46
Purchase of Common Shares Under NCIB
27
(1,445)
(1,061)
Purchase of Common Shares Under Employee Benefit Plan
27
(43)
—
Redemption of Preferred Shares
27
(250)
—
Payment for Purchase of Warrants
27
—
(711)
Proceeds From Exercise of Warrants
26
18
Dividends Paid
11
(1,551)
(1,026)
Other
—
(3)
Cash From (Used in) 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)
Cash and Cash Equivalents, Beginning of Year
2,227
4,524
Cash and Cash Equivalents, End of Year
3,093
2,227
(1)
Revised presentation as of January 1, 2024. See Note 4. 
See accompanying Notes to the Consolidated Financial Statements.
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
10
76   |   CENOVUS ENERGY 2024 ANNUAL REPORT

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Cenovus Energy Inc. (“Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production 
operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United 
States (“U.S.”). 
Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase 
warrants are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Cenovus’s cumulative redeemable 
preferred shares series 1, 2, 5 and 7 are listed on the TSX. The executive and registered office is located at 4100, 225 
6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these Consolidated 
Financial Statements is found in Note 2.
Management has determined the operating segments based on information regularly reviewed for the purposes of decision 
making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The 
Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a 
combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on 
operating margin.
The Company operates through the following reportable segments: 
Upstream Segments
•
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 natural gas liquids (“NGLs”) and natural gas in Alberta and British Columbia in the 
Edson, Clearwater and Rainbow Lake operating areas, in addition to the Northern Corridor, which includes Elmworth 
and Wapiti. The segment also includes interests in numerous natural gas processing facilities. Cenovus’s NGLs and 
natural gas production is marketed and transported, with additional third-party commodity trading volumes, through 
access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market 
access to optimize product mix, delivery points, transportation commitments and customer diversification.
•
Offshore, includes offshore operations, exploration and development activities in the east coast of Canada and the 
Asia Pacific region, representing China and the equity-accounted investment in Husky-CNOOC Madura Ltd. (“HCML”), 
which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia.
Downstream Segments
•
Canadian Refining, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which 
converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also 
owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels 
business across Canada is included in this segment. Cenovus markets its production and third-party commodity 
trading volumes in an effort to use its integrated network of assets to maximize value. 
•
U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the 
wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment also includes the jointly-owned Wood 
River and Borger refineries, held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. 
Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt. 
Corporate and Eliminations
Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains 
and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations 
include adjustments for feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined 
products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail 
terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and 
sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
11
CENOVUS ENERGY 2024 ANNUAL REPORT   |   77

A) Results of Operations – Segment and Operational Information
Upstream
Oil Sands
Conventional
Offshore
Total
For the years ended December 31,
2024
2023
2024
2023
2024
2023
2024
2023
Gross Sales
External Sales
21,857
20,608
1,211
1,488
1,572
1,617
24,640
23,713
Intersegment Sales
6,590
5,584
1,848
1,785
—
—
8,438
7,369
28,447
26,192
3,059
3,273
1,572
1,617
33,078
31,082
Royalties
(3,274)
(3,059)
(76)
(112)
(99)
(99)
(3,449)
(3,270)
Revenues
25,173
23,133
2,983
3,161
1,473
1,518
29,629
27,812
Expenses
Purchased Product
1,851
1,457
1,823
1,695
—
—
3,674
3,152
Transportation and Blending
11,000
10,774
320
298
11
16
11,331
11,088
Operating
2,511
2,716
555
590
423
384
3,489
3,690
Realized (Gain) Loss on Risk
   Management
20
17
(6)
(5)
—
—
14
12
Operating Margin
9,791
8,169
291
583
1,039
1,118
11,121
9,870
Unrealized (Gain) Loss on Risk
   Management 
(16)
15
4
(19)
—
—
(12)
(4)
Depreciation, Depletion and
   Amortization
3,117
2,993
442
386
563
487
4,122
3,866
Exploration Expense
2
19
1
6
66
17
69
42
(Income) Loss From Equity-
   Accounted Affiliates
(14)
6
2
—
(53)
(57)
(65)
(51)
Segment Income (Loss)
6,702
5,136
(158)
210
463
671
7,007
6,017
Downstream
Canadian Refining
U.S. Refining
Total
For the years ended December 31,
2024
2023
2024
2023
2024
2023
Gross Sales
External Sales
4,787
5,385
28,299
26,376
33,086
31,761
Intersegment Sales
523
848
9
17
532
865
5,310
6,233
28,308
26,393
33,618
32,626
Royalties
—
—
—
—
—
—
Revenues
5,310
6,233
28,308
26,393
33,618
32,626
Expenses
Purchased Product
4,483
4,919
25,769
23,354
30,252
28,273
Transportation and Blending
—
—
—
—
—
—
Operating
907
639
2,763
2,562
3,670
3,201
Realized (Gain) Loss on Risk Management
—
—
8
—
8
—
Operating Margin
(80)
675
(232)
477
(312)
1,152
Unrealized (Gain) Loss on Risk Management 
—
—
8
(17)
8
(17)
Depreciation, Depletion and Amortization
185
185
462
486
647
671
Exploration Expense
—
—
—
—
—
—
(Income) Loss From Equity-Accounted Affiliates
—
—
—
—
—
—
Segment Income (Loss)
(265)
490
(702)
8
(967)
498
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
12
78   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Corporate and 
Eliminations
Consolidated
For the years ended December 31,
2024
2023
2024
2023
Gross Sales
External Sales
—
—
57,726
55,474
Intersegment Sales
(8,970)
(8,234)
—
—
(8,970)
(8,234)
57,726
55,474
Royalties
—
—
(3,449)
(3,270)
Revenues
(8,970)
(8,234)
54,277
52,204
Expenses
Purchased Product
(7,823)
(6,710)
26,103
24,715
Transportation and Blending
(793)
(947)
10,538
10,141
Purchased Product, Transportation and Blending (1)
(8,616)
(7,657)
36,641
34,856
Operating
(318)
(539)
6,841
6,352
Realized (Gain) Loss on Risk Management
24
(3)
46
9
Unrealized (Gain) Loss on Risk Management
16
73
12
52
Depreciation, Depletion and Amortization
102
107
4,871
4,644
Exploration Expense
—
—
69
42
(Income) Loss From Equity-Accounted Affiliates
(1)
—
(66)
(51)
Segment Income (Loss)
(177)
(215)
5,863
6,300
General and Administrative
794
688
794
688
Finance Costs, Net (1)
514
538
514
538
Integration, Transaction and Other Costs
166
85
166
85
Foreign Exchange (Gain) Loss, Net
462
(67)
462
(67)
(Gain) Loss on Divestiture of Assets (1)
(119)
20
(119)
20
Re-measurement of Contingent Payments
30
59
30
59
Other (Income) Loss, Net
(55)
(63)
(55)
(63)
1,792
1,260
1,792
1,260
Earnings (Loss) Before Income Tax
4,071
5,040
Income Tax Expense (Recovery)
929
931
Net Earnings (Loss)
3,142
4,109
(1)
Revised presentation as of January 1, 2024. See Note 4. 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
13
CENOVUS ENERGY 2024 ANNUAL REPORT   |   79

B) External Sales by Product 
Upstream
Oil Sands
Conventional
Offshore
Total
For the years ended December 31,
2024
2023
2024
2023
2024
2023
2024
2023
Crude Oil
21,183
20,022
207
238
321
401
21,711
20,661
Natural Gas and Other
332
271
648
988
925
901
1,905
2,160
NGLs (1)
342
315
356
262
326
315
1,024
892
External Sales
21,857
20,608
1,211
1,488
1,572
1,617
24,640
23,713
Downstream
Canadian Refining
U.S. Refining
Total
For the years ended December 31,
2024
2023
2024
2023
2024
2023
Gasoline
429
522
13,792
12,375
14,221
12,897
Distillates (2)
1,484
1,752
10,632
9,612
12,116
11,364
Synthetic Crude Oil
1,814
1,899
—
—
1,814
1,899
Asphalt
548
537
1,029
864
1,577
1,401
Other Products and Services
512
675
2,846
3,525
3,358
4,200
External Sales
4,787
5,385
28,299
26,376
33,086
31,761
(1)
Third-party condensate sales are included within NGLs.
(2)
Includes diesel and jet fuel. 
C) Geographical Information 
Revenues (1)
For the years ended December 31,
2024
2023
Canada
26,791
25,128
United States
26,333
25,943
China
1,153
1,133
Consolidated
54,277
52,204
(1)
Revenues by country are classified based on where the operations are located. 
Non-Current Assets (1)
As at December 31, 
2024
2023
Canada
37,006
35,876
United States
5,902
5,230
China
1,249
1,608
Indonesia
295
344
Consolidated
44,452
43,058
(1)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in 
equity-accounted affiliates, precious metals, intangible assets and goodwill. 
Major Customers
In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products 
for the year ended December 31, 2024, Cenovus had two customers (2023 – two) that individually accounted for more than 10 
percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with 
investment grade credit ratings, were approximately $17.7 billion and $8.1 billion, respectively (2023 – $18.0 billion and $7.1 
billion, respectively), and are reported across all of the Company’s operating segments.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
14
80   |   CENOVUS ENERGY 2024 ANNUAL REPORT

D) Assets by Segment
E&E Assets
PP&E
ROU Assets
As at December 31, 
2024
2023
2024
2023
2024
2023
Oil Sands
461
729
24,646
24,443
1,018
849
Conventional
15
—
2,230
2,209
57
1
Offshore
8
9
3,365
2,798
95
102
Canadian Refining
—
—
2,511
2,469
39
28
U.S. Refining
—
—
5,538
5,014
342
268
Corporate and Eliminations
—
—
278
317
399
432
Consolidated
484
738
38,568
37,250
1,950
1,680
Goodwill
Total Assets
As at December 31, 
2024
2023
2024
2023
Oil Sands
2,923
2,923
31,668
31,673
Conventional
—
—
2,610
2,429
Offshore
—
—
4,089
3,511
Canadian Refining
—
—
2,901
2,960
U.S. Refining
—
—
9,517
8,660
Corporate and Eliminations
—
—
5,754
4,682
Consolidated
2,923
2,923
56,539
53,915
E) Capital Expenditures (1)
For the years ended December 31,
2024
2023
Capital Investment
Oil Sands
2,714
2,382
Conventional
421
452
Offshore
Atlantic
1,077
635
Asia Pacific
68
7
Total Upstream 
4,280
3,476
Canadian Refining
208
145
U.S. Refining
488
602
Total Downstream
696
747
Corporate and Eliminations
39
75
5,015
4,298
Acquisitions
Oil Sands
9
37
Conventional
13
5
U.S. Refining (2)
—
385
22
427
Total Capital Expenditures
5,037
4,725
(1)
Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the Company's joint ventures.
(2)
In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) and reacquired it at fair value as required by 
International Financial Reporting Standard 3, "Business Combinations" (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-
existing interest in Toledo of $368 million. See Note 5. 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
15
CENOVUS ENERGY 2024 ANNUAL REPORT   |   81

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
These Consolidated Financial Statements are presented in Canadian dollars, which is the Company's functional and presentation 
currency. Certain Cenovus subsidiaries operate in countries other than Canada and have functional currencies other than the 
Canadian dollar. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.
These Consolidated Financial Statements were prepared in accordance with International Financial Reporting Standards (“IFRS”) 
as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”) and interpretations of the 
International Financial Reporting Interpretations Committee.
These Consolidated Financial Statements were prepared on a historical cost basis, except as detailed in the Company’s 
accounting policies as disclosed in Note 36. 
These Consolidated Financial Statements were approved by the Board of Directors effective February 19, 2025.
3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in accordance with IFRS Accounting Standards requires that 
Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, 
disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts 
of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date 
of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are 
subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events 
occur. 
A) 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.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
16
82   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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 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. 
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. 
B) 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 
renewable identification numbers (“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 depreciation, depletion and amortization 
(“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 independent qualified reserves evaluators 
(“IQREs”).
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
17
CENOVUS ENERGY 2024 ANNUAL REPORT   |   83

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 for 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, future capital expenditures 
and discount rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the 
related assets. 
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.
4. UPDATES 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.
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’.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
18
84   |   CENOVUS ENERGY 2024 ANNUAL REPORT

5. ACQUISITIONS AND DIVESTITURES
A) Acquisitions
i) BP-Husky Refining LLC
On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The 
Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil 
production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash, 
including cost of working capital.
The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, 
assets and liabilities are recorded at fair value on the date of acquisition and the total consideration is allocated to the assets 
acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is 
recorded as goodwill. 
ii) Identifiable Assets Acquired and Liabilities Assumed
As at
February 28, 
2023
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash
69
Accounts Receivable and Accrued Revenues
3
Inventories
387
Property, Plant and Equipment 
770
Right-of-Use Assets
33
Other Assets
10
Accounts Payable and Accrued Liabilities
(139)
Lease Liabilities
(33)
Decommissioning Liabilities 
(5)
Other Liabilities
(73)
Total Identifiable Net Assets
1,022
iii) Goodwill
As at
February 28, 
2023
Total Purchase Consideration
514
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo
508
Fair Value of Identifiable Net Assets
(1,022)
Goodwill
—
Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC
The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of 
Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss in (gain) loss on divestiture of assets of $34 
million ($23 million, after tax) on the re-measurement of its pre-existing interest in Toledo to fair value, net of $12 million in 
associated cumulative foreign currency translation adjustments. 
iv) Transaction Costs
For the year ended December 31, 2023, transaction costs of $11 million related to the Toledo Acquisition were recognized in 
net earnings (loss). 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
19
CENOVUS ENERGY 2024 ANNUAL REPORT   |   85

B) Divestitures
The Company closed a transaction with Athabasca Oil Corporation (“Athabasca”) to create the jointly-controlled Duvernay 
Energy Corporation (“Duvernay”). Cenovus contributed non-monetary assets with a fair value of $94 million and cash of $18 
million, before closing adjustments, in exchange for a 30 percent equity interest in Duvernay. The Company recognized an 
investment of $84 million in Duvernay and a before-tax gain on divestiture of assets of $65 million (after-tax gain – $50 million), 
reflecting the difference between the carrying value and fair value of contributed assets to the extent of Athabasca’s share.
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 (after-tax gain – $39 million).
6. GENERAL AND ADMINISTRATIVE
For the years ended December 31,
2024
2023
Salaries and Benefits
269
249
Administrative and Other
399
342
Stock-Based Compensation Expense (Recovery) (Note 29)
126
97
794
688
7. FINANCE COSTS, NET
For the years ended December 31,
2024
2023
Interest Expense – Short-Term Borrowings and Long-Term Debt
307
362
Net Premium (Discount) on Redemption of Long-Term Debt (1)
—
(84)
Interest Expense – Lease Liabilities (Note 17)
162
161
Unwinding of Discount on Decommissioning Liabilities (Note 24)
225
220
Other
35
32
Capitalized Interest
(45)
(20)
Finance Costs
684
671
Interest Income
(170)
(133)
514
538
(1)
Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.
8. FOREIGN EXCHANGE (GAIN) LOSS, NET
For the years ended December 31,
2024
2023
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada
442
(231)
Other
108
21
Unrealized Foreign Exchange (Gain) Loss
550
(210)
Realized Foreign Exchange (Gain) Loss
(88)
143
462
(67)
9. IMPAIRMENT CHARGES AND REVERSALS
A) Upstream Cash-Generating Units
Impairment Charges
The Company tested CGUs with associated goodwill for impairment as at December 31, 2024, and 2023, and there were no 
impairments. No impairment indicators were identified for the remaining CGUs as at December 31, 2024, and 2023. 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
20
86   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs with associated goodwill were estimated using fair value less 
costs of disposal (“FVLCOD”). Key assumptions used to estimate the present value of future net cash flows from reserves 
include expected future production volumes, quantity of reserves, forward commodity prices, and future development and 
operating expenses, all consistent with Cenovus’s IQREs, as well as discount rates. Fair values for producing properties were 
calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as 
at December 31, 2024, and December 31, 2023. All reserves were evaluated by the Company’s IQREs as at December 31, 2024, 
and 2023.
Crude Oil, NGLs and Natural Gas Prices
The forward commodity prices as at December 31, 2024, used to determine future cash flows from crude oil, NGLs and natural 
gas reserves were:
2025
2026
2027
2028
2029
Average 
Annual 
Increase 
Thereafter
(percent)
West Texas Intermediate (“WTI”) (US$/bbl) (1)
71.58
74.48
75.81
77.66
79.22
 2.00 
Western Canadian Select at Hardisty (2) (C$/bbl)
82.69
84.27
83.81
85.70
87.45
 2.00 
Condensate at Edmonton (C$/bbl)
100.14
100.72
100.24
102.73
104.79
 2.00 
Alberta Energy Company Natural Gas (C$/Mcf) (3)
2.36
3.33
3.48
3.69
3.76
 2.00 
(1)
Barrel ("bbl").
(2)
Western Canadian Select at Hardisty (“WCS”). 
(3)
One thousand cubic feet (“Mcf”).
The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural 
gas reserves were:
2024
2025
2026
2027
2028
Average 
Annual 
Increase 
Thereafter
(percent)
WTI (US$/bbl) 
73.67
74.98
76.14
77.66
79.22
 2.00 
WCS (C$/bbl)
76.74
79.77
81.12
82.88
85.04
 2.00 
Condensate at Edmonton (C$/bbl)
96.79
98.75
100.71
102.72
104.78
 2.00 
Alberta Energy Company Natural Gas (C$/Mcf)
2.20
3.37
4.05
4.13
4.21
 2.00 
Discount Rates
Discounted future cash flows were determined by applying a discount rate of 14 percent (2023 – 14 percent). 
Sensitivities
A one percent (2023 – one percent) increase in the discount rate or a five percent (2023 – five percent) decrease in forward 
commodity price estimates would not impact the results of the impairment tests performed. 
B) Downstream Cash-Generating Units
i) 2024 Impairment Charges and Reversals
As at December 31, 2024, lower forward Chicago 3-2-1 crack spreads, net of RINs, that would result in lower margins for refined 
products was identified as an indicator of impairment for the Lima, Toledo and Wood River CGUs. As a result, these CGUs were 
tested for impairment. 
The recoverable amounts of the Lima, Toledo and Wood River CGUs were in excess of their respective carrying amounts and no 
impairment was recorded. There were no indicators of impairment for the remaining downstream CGUs and no indicators of 
impairment reversal for the Superior and Borger CGUs. 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
21
CENOVUS ENERGY 2024 ANNUAL REPORT   |   87

Key Assumptions
The recoverable amount (Level 3) of each of the CGUs were determined using FVLCOD. FVLCOD was calculated based on 
discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash 
flows included refined product production, forward crude oil prices, forward crack spreads, net of RINs, future capital 
expenditures, future operating costs and discount rates. Forward prices are based on third-party consultant forecasts.
Crude Oil and Select Refining Benchmark Prices
As at December 31, 2024, the forward prices used to determine future cash flows were:
(US$/bbl)
2025
2026
2027
2028
2029
WTI
77.68
77.07
78.74
81.51
83.14
Differential WTI – WCS
(14.17)
(15.34)
(15.71)
(16.62)
(17.11)
Chicago 3-2-1 Crack Spread
20.01
21.97
22.60
23.87
24.66
Renewable Identification Numbers
6.79
7.31
8.05
8.69
9.03
Subsequent estimated cash flows were determined using a pricing growth rate between one percent and six percent up to the 
year 2034. 
Discount Rates
Discounted future cash flows were determined by applying a discount rate between 15 percent and 16 percent based on the 
individual characteristics of the CGU and on the economic and operating factors. 
Sensitivities
The sensitivity analysis below shows the impact that a change in the discount rate or in forward prices would have on the 
impairment amount as at December 31, 2024, for the U.S. Refining CGUs:
Increase (Decrease) to Impairment Amount
 One Percent Increase in 
the Discount Rate
Five Percent Decrease in 
the Forward Prices
Lima and Wood River CGUs
214
619
For the Toledo CGU, a one percent increase in the discount rate or a five percent decrease in forward prices would not result in 
an impairment. 
ii) 2023 Impairment Charges and Reversals
As at December 31, 2023, there were no indicators of impairment or impairment reversals for the Company's downstream 
CGUs.
10. INCOME TAXES
A) Income Tax Expense (Recovery)
For the years ended December 31,
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
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
22
88   |   CENOVUS ENERGY 2024 ANNUAL REPORT

The following table reconciles income taxes calculated at the consolidated combined federal and provincial Canadian statutory 
rate with the recorded income taxes:
For the years ended December 31,
2024
2023
Earnings (Loss) Before Income Tax
4,071
5,040
Canadian Statutory Rate (percent)
 23.7 
 23.7 
Expected Income Tax Expense (Recovery)
965
1,194
Effect on Taxes Resulting From:
Statutory and Other Rate Differences
(34)
(38)
Non-Taxable Capital (Gains) Losses
45
(15)
Non-Recognition of Capital (Gains) Losses
45
(30)
Adjustments Arising From Prior Year Tax Filings
(31)
(16)
Recognition of U.S. Tax Basis
(77)
(115)
Other
16
(49)
Total Tax Expense (Recovery)
929
931
Effective Tax Rate (percent)
 22.8 
 18.5 
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. 
For the year ended December 31, 2024, Pillar Two taxes did not have a material impact on net earnings. The Company is not 
expecting a material impact from jurisdictions where we operate that have not enacted Pillar Two legislation. 
B) Deferred Income Tax Assets and Liabilities
The breakdown of deferred income tax assets and deferred income tax liabilities, without taking into consideration the 
offsetting of balances within the same tax jurisdiction, is as follows:
As at December 31, 2024
2024
2023
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months
(29)
(315)
Deferred Income Tax Assets to be Settled After More Than Twelve Months
(1,269)
(1,174)
(1,298)
(1,489)
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled Within Twelve Months
68
138
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months
4,211
4,843
4,279
4,981
Net Deferred Income Tax Liability
2,981
3,492
The deferred income tax assets and liabilities to be settled within twelve months represents Management’s estimate of the 
timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent 
year.
The movement in deferred income tax assets and liabilities, without taking into consideration the offsetting of balances within 
the same tax jurisdiction, was:
Deferred Income Tax Assets
Unused Tax 
Losses
Other
Total
As at December 31, 2022
(156)
(622)
(778)
Charged (Credited) to Earnings
(777)
54
(723)
Charged (Credited) to Other Comprehensive Income
19
(7)
12
As at December 31, 2023
(914)
(575)
(1,489)
Charged (Credited) to Earnings
242
(9)
233
Charged (Credited) to Other Comprehensive Income
(66)
24
(42)
As at December 31, 2024
(738)
(560)
(1,298)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
23
CENOVUS ENERGY 2024 ANNUAL REPORT   |   89

Deferred Income Tax Liabilities
PP&E
Other
Total
As at December 31, 2022
4,460
55
4,515
Charged (Credited) to Earnings
495
(22)
473
Charged (Credited) to Other Comprehensive Income
(7)
—
(7)
As at December 31, 2023
4,948
33
4,981
Charged (Credited) to Earnings
(716)
9
(707)
Charged (Credited) to Other Comprehensive Income
5
—
5
As at December 31, 2024
4,237
42
4,279
Net Deferred Income Tax Liabilities
Total
As at December 31, 2022
3,737
Charged (Credited) to Earnings
(250)
Charged (Credited) to Other Comprehensive Income
5
As at December 31, 2023
3,492
Charged (Credited) to Earnings
(474)
Charged (Credited) to Other Comprehensive Income
(37)
As at December 31, 2024
2,981
The deferred income tax asset of $1.1 billion as at December 31, 2024 (December 31, 2023 – $696 million) represents net 
deductible temporary differences in the U.S. jurisdiction, which have been fully recognized, as the probability of realization is 
expected due to forecasted taxable income. No deferred tax liability was recognized as at December 31, 2024, or December 31, 
2023, on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can 
control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future.
C) Tax Pools
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
2024
2023
Canada
10,086
8,547
United States
9,905
8,058
Asia Pacific
351
347
20,342
16,952
As at December 31, 2024, the above tax pools included $197 million (December 31, 2023 – $126 million) of Canadian federal 
non-capital losses and $3.0 billion (December 31, 2023 – $3.7 billion) of U.S. net operating losses. These losses expire no earlier 
than 2043. 
As at December 31, 2024, the Company had Canadian net capital losses totaling $85 million (December 31, 2023 – $59 million), 
which are available for carry forward to reduce future capital gains. The Company has not recognized $362 million 
(December 31, 2023 – $141 million) of deductible temporary differences associated with unrealized foreign exchange losses on 
its U.S. denominated debt.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
24
90   |   CENOVUS ENERGY 2024 ANNUAL REPORT

11. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Common Share – Basic and Diluted
For the years ended December 31,
2024
2023
Net Earnings (Loss)
3,142
4,109
Effect of Cumulative Dividends on Preferred Shares
(36)
(36)
Net Earnings (Loss) – Basic 
3,106
4,073
Effect of Stock-Based Compensation
3
(12)
Net Earnings (Loss) – Diluted
3,109
4,061
Basic – Weighted Average Number of Shares (thousands)
1,850,193
1,895,487
Dilutive Effect of Warrants
4,483
22,223
Dilutive Effect of Stock-Based Compensation
8,540
22,135
Diluted – Weighted Average Number of Shares (thousands)
1,863,216
1,939,845
Net Earnings (Loss) Per Common Share – Basic ($)
1.68
2.15
Net Earnings (Loss) Per Common Share – Diluted (1) ($)
1.67
2.09
(1)
For the year ended December 31, 2024, net earnings of $16 million (2023 – $nil) and 9.8 million common shares (2023 – 1.6 million), related to the assumed 
exercise of stock-based compensation, were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive.
B) Common Share Dividends
2024
2023
For the years ended December 31,
Per Share
Amount
Per Share
Amount
Base Dividends
0.680
1,255
0.525
990
Variable Dividends
0.135
251
—
—
Total Common Share Dividends Declared and Paid
0.815
1,506
0.525
990
The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered 
quarterly.
On February 19, 2025, the Company’s Board of Directors declared a first quarter base dividend of $0.180 per common share, 
payable on March 31, 2025, to common shareholders of record as at March 14, 2025.
C) Preferred Share Dividends
For the years ended December 31,
2024
2023
Series 1 First Preferred Shares
7
7
Series 2 First Preferred Shares
2
2
Series 3 First Preferred Shares
12
12
Series 5 First Preferred Shares
9
9
Series 7 First Preferred Shares
6
6
Total Preferred Share Dividends Declared
36
36
The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered 
quarterly.
For the year ended December 31, 2024, the Company paid $45 million in preferred share dividends (December 31, 2023 – $36 
million).
On February 19, 2025, the Company’s Board of Directors declared first quarter dividends of $6 million payable on March 
31, 2025, to preferred shareholders of record as at March 14, 2025.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
25
CENOVUS ENERGY 2024 ANNUAL REPORT   |   91

12. CASH AND CASH EQUIVALENTS
As at December 31,
2024
2023
Cash
2,723
2,109
Short-Term Investments
370
118
3,093
2,227
Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a 
maturity of three months or less. 
13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
2024
2023
Trade and Accruals
2,378
2,722
Prepaids and Deposits
187
242
Joint Operations Receivables
40
49
Other
9
22
2,614
3,035
14. INVENTORIES
As at December 31,
2024
2023
Product
Crude Oil
2,297
2,084
Diluent
401
379
Natural Gas and NGLs
77
68
Refined Products
1,176
1,073
Total Product
3,951
3,604
Parts and Supplies
545
426
4,496
4,030
For the year ended December 31, 2024, approximately $42.8 billion of produced and purchased inventory was recorded as an 
expense (2023 – approximately $39.1 billion). 
As at December 31, 2024, the Company had no inventory write-downs. As at December 31, 2023, the Company recorded non-
cash inventory write-downs of $86 million and $3 million in refined products and crude oil inventory, respectively. The non-cash 
inventory write-downs were included in purchased product, transportation and blending expense.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
26
92   |   CENOVUS ENERGY 2024 ANNUAL REPORT

15. EXPLORATION AND EVALUATION ASSETS, NET
Total
As at December 31, 2022
685
Acquisition
31
Additions
84
Transfer to PP&E (Note 16)
(60)
Write-downs
(29)
Change in Decommissioning Liabilities
28
Exchange Rate Movements and Other
(1)
As at December 31, 2023
738
Acquisition
7
Additions
65
Transfer to PP&E (Note 16)
(285)
Write-downs
(37)
Change in Decommissioning Liabilities
(5)
Exchange Rate Movements and Other
1
As at December 31, 2024
484
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
27
CENOVUS ENERGY 2024 ANNUAL REPORT   |   93

16. PROPERTY, PLANT AND EQUIPMENT, NET
Crude Oil and 
Natural Gas 
Properties
Processing, 
Transportation 
and Storage 
Assets
Refining Assets
Other Assets (1)
Total
COST
As at December 31, 2022
43,528
254
12,132
1,825
57,739
Acquisitions (Note 5) (2)
11
—
770
—
781
Additions
3,392
14
719
89
4,214
Transfer from E&E (Note 15)
60
—
—
—
60
Change in Decommissioning Liabilities
542
—
21
18
581
Divestitures (Note 5) (2)
(17)
—
(633)
(17)
(667)
Exchange Rate Movements and Other
(91)
4
(239)
(7)
(333)
As at December 31, 2023
47,425
272
12,770
1,908
62,375
Acquisitions
15
—
—
—
15
Additions 
4,215
3
661
71
4,950
Transfer from E&E (Note 15)
285
—
—
—
285
Change in Decommissioning Liabilities
312
2
4
(5)
313
Divestitures (Note 5) 
(270)
—
—
(1)
(271)
Exchange Rate Movements and Other
108
3
890
2
1,003
As at December 31, 2024
52,090
280
14,325
1,975
68,670
ACCUMULATED DEPRECIATION, DEPLETION AND 
AMORTIZATION
As at December 31, 2022
14,302
106
5,547
1,285
21,240
Depreciation, Depletion and Amortization
3,692
19
554
86
4,351
Divestitures (Note 5) (2)
(8)
—
(299)
(12)
(319)
Exchange Rate Movements and Other
(11)
4
(135)
(5)
(147)
As at December 31, 2023
17,975
129
5,667
1,354
25,125
Depreciation, Depletion and Amortization
3,949
11
539
81
4,580
Divestitures (Note 5)
(208)
—
—
—
(208)
Exchange Rate Movements and Other
133
1
469
2
605
As at December 31, 2024
21,849
141
6,675
1,437
30,102
CARRYING VALUE
As at December 31, 2023
29,450
143
7,103
554
37,250
As at December 31, 2024
30,241
139
7,650
538
38,568
(1)
Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft.
(2)
In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by 
IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million.
Assets Under Construction
PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A:
As at December 31,
2024
2023
Crude Oil and Natural Gas Properties
3,359
2,507
Refining Assets
400
243
3,759
2,750
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
28
94   |   CENOVUS ENERGY 2024 ANNUAL REPORT

17. LEASES
A) Right-of-Use Assets, Net
Real Estate
Transportation 
and Storage 
Assets (1)
Refining Assets
Other Assets (2)
Total
COST
As at December 31, 2022
599
1,840
174
74
2,687
Acquisitions (Note 5) (3)
1
24
8
—
33
Additions
1
56
—
—
57
Divestitures (Note 5) (3)
—
—
(19)
—
(19)
Exchange Rate Movements and Other
(13)
44
(2)
(4)
25
As at December 31, 2023
588
1,964
161
70
2,783
Additions
2
317
—
51
370
Exchange Rate Movements and Other
2
111
17
4
134
As at December 31, 2024
592
2,392
178
125
3,287
ACCUMULATED DEPRECIATION
As at December 31, 2022
127
645
58
12
842
Depreciation
36
223
22
12
293
Divestitures (Note 5) (3)
—
—
(12)
—
(12)
Exchange Rate Movements and Other
(7)
(5)
(3)
(5)
(20)
As at December 31, 2023
156
863
65
19
1,103
Depreciation
35
198
21
37
291
Exchange Rate Movements and Other
2
(62)
8
(5)
(57)
As at December 31, 2024
193
999
94
51
1,337
CARRYING VALUE
As at December 31, 2023
432
1,101
96
51
1,680
As at December 31, 2024
399
1,393
84
74
1,950
(1)
Includes a pipeline, storage tanks, railcars, vessels, barges, a natural gas processing plant and caverns. 
(2)
Includes assets in the commercial fuels business, fleet vehicles, camps and other equipment.
(3)
In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by 
IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million.
B) Lease Liabilities
2024
2023
Lease Liabilities, Beginning of Year
2,658
2,836
Acquisitions (Note 5) (1)
—
33
Additions
363
57
Interest Expense (Note 7)
162
161
Lease Payments
(461)
(449)
Divestitures (Note 5) (1)
—
(11)
Exchange Rate Movements and Other
205
31
Lease Liabilities, End of Year
2,927
2,658
Less: Current Portion
359
299
Long-Term Portion
2,568
2,359
(1)
In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by 
IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million.
Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The Company has 
variable lease payments related to property taxes for real estate contracts. The Company includes extension options in the 
calculation of lease liabilities when the Company has the right to extend a lease term at its discretion and is reasonably certain 
to exercise the extension option. The Company does not have any significant termination options and the residual amounts are 
not material.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
29
CENOVUS ENERGY 2024 ANNUAL REPORT   |   95

18. JOINT ARRANGEMENTS
A) Joint Operations
Cenovus has a number of joint operations in the Upstream segments. As at December 31, 2024, the Company also has a 50 
percent interest in WRB in the U.S. Refining segment. Phillips 66 holds the remaining 50 percent interest and is the operator of 
the Wood River Refinery in Illinois and the Borger Refinery in Texas.
As at December 31, 2024, Toledo is 100 percent controlled by Cenovus and has been consolidated. Refer to Note 5 for more 
information on this transaction. 
B) Joint Ventures
Husky-CNOOC Madura Ltd. 
The Company holds a 40 percent 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. 
Summarized below is the financial information for HCML accounted for using the equity method.  
Results of Operations
For the years ended December 31,
2024
2023
Revenue
736
615
Expenses
605
545
Net Earnings (Loss)
131
70
Balance Sheet
As at December 31,
2024
2023
Current Assets (1)
441
334
Non-Current Assets
1,594
1,751
Current Liabilities
188
140
Non-Current Liabilities 
1,046
1,188
Net Assets
801
757
(1)
Includes cash and cash equivalents of $108 million (December 31, 2023 – $111 million). 
For the year ended December 31, 2024, the Company’s share of income from the equity-accounted affiliate was $53 million 
(2023 – $57 million). As at December 31, 2024, the carrying amount of the Company’s share of net assets was $294 million 
(December 31, 2023 – $344 million). These amounts do not equal the 40 percent joint control of the revenues, expenses and 
net assets of HCML due to differences in the values attributed to the investment and accounting policies between the joint 
venture and the Company.
For the year ended December 31, 2024, the Company received $107 million in distributions from HCML (2023 – $93 million) and 
paid $nil in contributions (2023 – $35 million).
Other Joint Ventures 
The Company has interests in a number of individually immaterial joint ventures, which include HMLP and Duvernay. The 
Company’s aggregate share of equity investment income (loss) related to these joint ventures are recorded in (income) loss 
from equity-accounted affiliates.
Summarized aggregate financial information is shown below:
For the years ended December 31,
2024
2023
Cenovus's Share of Net Earnings (Loss) 
(16)
(1)
Cenovus's Share of Other Comprehensive Income (Loss) 
(2)
(2)
Cenovus's Share of Total Other Comprehensive Income (Loss) 
(18)
(3)
As at December 31, 2024, the aggregate carrying value of the Company's investment in these joint ventures was $105 million 
(December 31, 2023 – $22 million).
For the year ended December 31, 2024, the Company received $65 million in distributions from HMLP (2023 – $56 million) and 
paid $51 million in contributions (2023 – $62 million).
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
30
96   |   CENOVUS ENERGY 2024 ANNUAL REPORT

19. OTHER ASSETS
As at December 31,
2024
2023
Private Equity Investments (Note 32)
219
131
Precious Metals
92
76
Long-Term Receivables and Prepaids 
68
50
Net Investment in Finance Leases
61
61
Intangible Assets
11
—
451
318
20. GOODWILL
For the years ended December 31, 2024, and December 31, 2023, no additions, disposals or impairments of goodwill were 
recognized.
The carrying amount of goodwill is allocated to the following CGUs: 
As at December 31,
2024
2023
Primrose (Foster Creek)
1,171
1,171
Christina Lake
1,101
1,101
Lloydminster Thermal 
651
651
2,923
2,923
21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
2024
2023
Accruals
4,902
3,931
Trade
1,005
1,075
Joint Operations Payable
110
75
Employee Long-Term Incentives
132
284
Interest
72
69
Provisions for Onerous and Unfavourable Contracts
11
18
Other
10
28
6,242
5,480
22. DEBT AND CAPITAL STRUCTURE
For the year ended December 31, 2024, the annualized weighted average interest rate on outstanding debt, including the 
Company’s proportionate share of short-term borrowings, was 4.5 percent (2023 – 4.7 percent). 
A) Short-Term Borrowings
As at December 31,
Notes
2024
2023
Uncommitted Demand Facilities
i
—
—
WRB Uncommitted Demand Facilities
ii
173
179
Total Debt Principal
173
179
i) Uncommitted Demand Facilities
As at December 31, 2024, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2023 – $1.7 billion) in 
place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As 
at 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). 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
31
CENOVUS ENERGY 2024 ANNUAL REPORT   |   97

ii) WRB Uncommitted Demand Facilities
WRB has uncommitted demand facilities of US$450 million (December 31, 2023 – US$450 million) that may be used to cover 
short-term working capital requirements, of which Cenovus’s proportionate share is 50 percent. As at December 31, 2024, 
US$240 million was drawn on these facilities, of which Cenovus’s proportionate share was US$120 million (C$173 million). As at 
December 31, 2023, Cenovus's proportionate share of drawings was US$135 million (C$179 million).
B) Long-Term Debt
As at December 31,
Notes
2024
2023
Committed Credit Facility 
i
—
—
U.S. Dollar Denominated Unsecured Notes
ii
5,470
5,028
Canadian Dollar Unsecured Notes
ii
2,000
2,000
Total Debt Principal
7,470
7,028
Debt Premiums (Discounts), Net, and Transaction Costs
64
80
Long-Term Debt
7,534
7,108
Less: Current Portion
192
—
Long-Term Portion
7,342
7,108
i) Committed Credit Facility
On June 26, 2024, Cenovus renewed its existing committed credit facility to extend the maturity dates by more than one year. 
The committed credit facility consists of a $2.2 billion tranche maturing on June 26, 2027, and a $3.3 billion tranche maturing on 
June 26, 2028. As at December 31, 2024, no amount was drawn on the credit facility (December 31, 2023 – $nil).
The committed credit facility may include Canadian overnight repo rate average loans, secured overnight financing rate loans, 
prime rate loans and U.S. base rate loans.
ii) U.S. Dollar Denominated and Canadian Dollar Denominated Unsecured Notes 
The principal amounts of the Company’s outstanding unsecured notes are: 
2024
2023
As at December 31,
US$ Principal
C$ Principal and 
Equivalent
US$ Principal
C$ Principal and 
Equivalent
U.S. Dollar Denominated Unsecured Notes
5.38% due July 15, 2025
133
192
133
176
4.25% due April 15, 2027
373
537
373
493
4.40% due April 15, 2029
183
262
183
241
2.65% due January 15, 2032
500
720
500
661
5.25% due June 15, 2037
333
479
333
441
6.80% due September 15, 2037
191
275
191
253
6.75% due November 15, 2039
652
938
652
862
4.45% due September 15, 2042
91
131
91
121
5.20% due September 15, 2043
27
39
27
36
5.40% due June 15, 2047
569
818
569
752
3.75% due February 15, 2052
750
1,079
750
992
3,802
5,470
3,802
5,028
Canadian Dollar Unsecured Notes
3.60% due March 10, 2027
750
750
3.50% due February 7, 2028
1,250
1,250
2,000
2,000
Total Unsecured Notes
7,470
7,028
For the year ended December 31, 2023, the Company purchased US$1.0 billion in principal of its outstanding unsecured notes.
As at December 31, 2024, the Company was in compliance with all of the terms of its debt agreements. Under the terms of 
Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the 
agreement, not to exceed 65 percent. The Company is below this limit.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
32
98   |   CENOVUS ENERGY 2024 ANNUAL REPORT

C) Mandatory Debt Payments
U.S. Dollar
Unsecured Notes
Canadian Dollar 
Unsecured Notes
Total
As at December 31, 2024
US$ Principal
C$ Principal 
Equivalent
C$ Principal
C$ Principal and 
Equivalent
2025
133
192
—
192
2026
—
—
—
—
2027
373
537
750
1,287
2028
—
—
1,250
1,250
2029
183
262
—
262
Thereafter
3,113
4,479
—
4,479
3,802
5,470
2,000
7,470
D) Capital Structure
Cenovus’s capital structure consists of shareholders’ equity and Net Debt. Net Debt includes the Company’s short-term 
borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents, and short-term 
investments. Net Debt is used in managing the Company’s capital structure. The Company’s objectives when managing its 
capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally 
generated growth and to fund potential acquisitions, while maintaining the ability to meet the Company’s financial obligations 
as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, 
steward working capital, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, 
purchase the Company’s common shares or preferred shares for cancellation, issue new debt, or issue new shares.
Cenovus monitors its capital structure and financing requirements using, among other things, Total Debt, Net Debt to adjusted 
earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. 
These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.
Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times 
and Net Debt at or below $4.0 billion over the long-term at a 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. 
On November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company 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.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
33
CENOVUS ENERGY 2024 ANNUAL REPORT   |   99

Net Debt to Adjusted EBITDA
As at December 31,
2024
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
Less: Cash and Cash Equivalents
(3,093)
(2,227)
Net Debt
4,614
5,060
Net Earnings (Loss)
3,142
4,109
Add (Deduct):
Finance Costs, Net (1)
514
538
Income Tax Expense (Recovery)
929
931
Depreciation, Depletion and Amortization
4,871
4,644
Exploration and Evaluation Asset Write-downs
37
29
(Income) Loss From Equity-Accounted Affiliates
(66)
(51)
Unrealized (Gain) Loss on Risk Management
12
52
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)
Adjusted EBITDA (2)
9,757
10,201
Net Debt to Adjusted EBITDA (times)
0.5
0.5
(1)
Revised presentation as of January 1, 2024. See Note 4.
(2)
Calculated on a trailing twelve-month basis.
Net Debt to Adjusted Funds Flow
As at December 31, 
2024
2023
Net Debt
4,614
5,060
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 (1)
8,164
8,803
Net Debt to Adjusted Funds Flow (times)
0.6
0.6
(1)
Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
As at December 31,
2024
2023
Net Debt
4,614
5,060
Shareholders’ Equity
29,754
28,698
Capitalization
34,368
33,758
Net Debt to Capitalization (percent)
 13 
 15 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
34
100   |   CENOVUS ENERGY 2024 ANNUAL REPORT

23. CONTINGENT PAYMENTS
In connection with the transaction with BP Canada Energy Group ULC (“bp Canada”) to purchase the remaining 50 percent 
interest in Sunrise Oil Sands Partnership (“SOSP”) (the “Sunrise Acquisition”), Cenovus agreed to make quarterly variable 
payments from SOSP to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS price in a 
quarter exceeded $52.00 per barrel. The quarterly payment was calculated as $2.8 million plus the difference between the 
average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price was equal to or 
greater than $52.00 per barrel. If the average WCS price was less than $52.00 per barrel, no payment would be made for that 
quarter. On August 31, 2024, the variable payment obligation ended. 
In the year ended December 31, 2024, the Company made payments of $301 million for the quarterly payment periods ending 
November 30, 2023, February 29, 2024, May 31, 2024, and August 31, 2024. 
2024
2023
Contingent Payments, Beginning of Year
164
419
Liabilities Settled or Payable
(194)
(314)
Re-measurement
30
59
Contingent Payments, End of Year
—
164
24. DECOMMISSIONING LIABILITIES
2024
2023
Decommissioning Liabilities, Beginning of Year
4,155
3,559
Liabilities Incurred
24
14
Liabilities Acquired (Note 5) (1)
—
5
Liabilities Settled
(234)
(221)
Liabilities Disposed (Note 5) (1)
(72)
(5)
Change in Estimated Future Cash Flows
276
330
Change in Discount Rates
132
265
Unwinding of Discount on Decommissioning Liabilities (Note 7)
225
220
Exchange Rate Movements and Other
28
(12)
Decommissioning Liabilities, End of Year
4,534
4,155
(1)
In connection with the Toledo Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by 
IFRS 3. As at February 28, 2023, the carrying value of the pre-existing interest in Toledo’s decommissioning liabilities was $2 million.
As at December 31, 2024, the undiscounted amount of estimated future cash flows required to settle the obligation is 
$15.6 billion (December 31, 2023 – $15.0 billion). Most of these obligations are not expected to be paid for several years, or 
decades, and will be funded through general resources when they become due. The Company plans to settle approximately 
$203 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change 
in the timing of decommissioning liabilities over the estimated life of the reserves and an increase in cost estimates. These 
obligations were discounted using a credit-adjusted risk-free rate of 5.2 percent (December 31, 2023 – 5.5 percent) and 
assumes an inflation rate of two percent (December 31, 2023 – two percent).
The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in 
accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2024, the Company had 
$241 million in long-term restricted cash (December 31, 2023 – $211 million). 
Sensitivities
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning 
liabilities: 
Sensitivity 
2024
2023
As at December 31, 
Range
Increase
Decrease
Increase
Decrease
Credit-Adjusted Risk-Free Rate
± one percent
(487)
595
(387)
515
Inflation Rate
± one percent
615
(507)
519
(392)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
35
CENOVUS ENERGY 2024 ANNUAL REPORT   |   101

25. OTHER LIABILITIES
As at December 31, 
2024
2023
Renewable Volume Obligation, Net (1)
284
397
Pension and Other Post-Employment Benefit Plan
269
276
Employee Long-Term Incentives
96
100
Provisions for Onerous and Unfavourable Contracts
66
72
Provision for West White Rose Expansion Project (2)
54
156
Drilling Provisions
3
25
Other
147
157
919
1,183
(1)
The gross amounts of the renewable volume obligation (“RVO”) and RINs asset were $652 million and $368 million, respectively (December 31, 2023 – 
$785 million and $388 million, respectively).
(2)
Cenovus expects to draw down the provision by $54 million in the next 12 months.
26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides the majority of employees with a defined contribution pension plan (“DC Pension Plan”). The Company 
also provides other post-employment benefit (“OPEB”) plans to retirees and sponsors defined benefit pension plans in Canada 
and the U.S. (together, the “DB Pension Plan”).
The DB Pension Plan provides pension benefits at retirement based on years of service and final average earnings. In Canada, 
future enrollment is limited to a small group of eligible employees who may elect to move from the defined contribution 
component to the defined benefit component for their future service. In the U.S., the defined benefit pension is closed to new 
members. The Company’s OPEB plans provides certain retired employees with health care and dental benefits. 
The Company is required to file actuarial valuations of its registered defined benefit pension plans with regulators on a periodic 
basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2023, and the 
next required actuarial valuation will be as at December 31, 2026. The most recently filed valuation for the U.S. defined benefit 
pension plan was dated January 1, 2024, and the next required actuarial valuation will be dated January 1, 2025.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
36
102   |   CENOVUS ENERGY 2024 ANNUAL REPORT

A) Plan Obligations, Assets and Funded Status 
DB Pension Plan
OPEB Plans
2024
2023
2024
2023
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year
202
172
249
174
Current Service Costs
14
10
2
14
Past Service Costs - Curtailment and Plan Amendments
—
—
—
10
Interest Costs (1)
9
9
12
10
Benefits Paid
(12)
(8)
(9)
(9)
Plan Participant Contributions
3
3
—
—
Re-measurements:
(Gains) Losses From Experience Adjustments
—
4
1
1
(Gains) Losses From Changes in Financial Assumptions
(3)
13
(6)
50
Exchange Rate Movements and Other
1
(1)
3
(1)
Defined Benefit Obligation, End of Year
214
202
252
249
Plan Assets
Fair Value of Plan Assets, Beginning of Year
178
147
—
—
Employer Contributions
11
18
9
9
Plan Participant Contributions 
3
3
—
—
Benefits Paid
(12)
(7)
(9)
(9)
Interest Income (1)
8
8
—
—
Re-measurements:
Return on Plan Assets Excluding Interest Income
11
10
—
—
Exchange Rate Movements and Other
2
(1)
—
—
Fair Value of Plan Assets, End of Year
201
178
—
—
Defined Benefit Pension and OPEB Asset (Liability) (2)
(13)
(24)
(252)
(249)
(1)
Based on the discount rate of the defined benefit obligation at the beginning of the year. 
(2)
Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities.
The weighted average duration of the obligations for the DB Pension Plan and OPEB plans are 16 years and 14 years, 
respectively.
B) Costs
DB Pension Plan and 
DC Pension Plan
OPEB Plans
For the years ended December 31,
2024
2023
2024
2023
Defined Benefit Plan Cost
Current Service Costs
14
10
2
14
Past Service Costs – Curtailments and Plan Amendments
—
—
—
10
Net Interest Costs
1
1
12
10
Re-measurements:
Return on Plan Assets Excluding Interest Income
(11)
(10)
—
—
(Gains) Losses From Experience Adjustments
—
4
1
1
(Gains) Losses From Changes in Financial Assumptions
(3)
13
(6)
50
Defined Benefit Plan Cost (Recovery)
1
18
9
85
Defined Contribution Plan Cost (1)
107
99
—
—
Total Plan Cost
108
117
9
85
(1)
Includes defined contribution and U.S. 401(k) plans.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
37
CENOVUS ENERGY 2024 ANNUAL REPORT   |   103

C) Investment Objectives and Fair Value of Plan Assets
The objective of the asset allocation is to manage the funded status of the DB Pension Plan at an appropriate level of risk, giving 
consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both 
contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a 
composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject 
to diversification requirements and constraints that reduce risk by limiting exposure to individual equity investment and credit 
rating categories.
The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced as necessary. 
The Canadian defined benefit pension plan and U.S. defined benefit pension plan are managed independently of each other 
and, accordingly, the target asset allocation is reflective of their different liability profiles. The Company does not use derivative 
instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage 
these risks from prior periods.
The fair value of the DB Pension Plan assets, as represented by fair value hierarchy levels are as follows:
As at December 31, 
2024
2023
Level 1 – Cash and Cash Equivalents
3
5
Level 2 – Equity and Fixed Income Funds
185
161
Level 3 – Real Estate Funds and Other
13
12
 
201
178
The DB Pension Plan does not hold any direct investment in Cenovus common shares or preferred shares. 
D) Funding 
The DB Pension Plan is funded in accordance with applicable pension legislation. Contributions are made to trust funds 
administered by independent trustees. The Company’s contributions to the DB Pension Plan are based on the most recent 
actuarial valuations and the direction of the Management Pension Committees and Human Resources and Compensation 
Committee of the Board of Directors.
Employees participating in the Canadian defined benefit pension are required to contribute four percent of their pensionable 
earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be 
fully provided for at retirement. In the year ended December 31, 2025, the Company expects to contribute $12 million to the 
DB Pension Plan.
The OPEB plans are funded on an as required basis. For the year ended December 31, 2025, the Company expects to contribute 
$12 million to the OPEB plans.
E) Actuarial Assumptions and Sensitivities 
Actuarial Assumptions 
The principal weighted average actuarial assumptions used to determine benefit obligations are as follows:
Defined Benefit Plan
OPEB Plans
For the years ended December 31, 
2024
2023
2024
2023
Discount Rate (percent)
 4.65 
 4.58 
 4.85 
 4.65 
Future Salary Growth Rate (percent)
 3.95 
 4.00 
N/A
N/A
Average Longevity (years)
88.4
88.4
88.4
88.4
Health Care Cost Trend Rate (percent)
N/A
N/A
 5.24 
 5.24 
Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the 
benefit obligations. 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
38
104   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Sensitivities
The sensitivity of the DB Pension Plan and OPEB plan obligations to a one percent change in future salary growth rate, health 
care cost trend rate, or a one year change in assumed life expectancy is nominal. A one percent change in discount rate, while 
holding all other assumptions constant, would result in a sensitivity to change as follows:
2024
2023
As at December 31,
Increase
Decrease
Increase
Decrease
Discount Rate
(56)
69
(54)
66
Actual experience may result in a number of assumptions changing simultaneously, and the changes in some assumptions may 
be correlated. When calculating the sensitivity of the DB Pension Plan and the OPEB plan obligations to significant actuarial 
assumptions, the same methodologies have been applied as when valuing the obligations to be recognized on the Consolidated 
Balance Sheets. 
27. SHARE CAPITAL AND WARRANTS
A) Authorized
Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in 
aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be 
issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject 
to the Company’s articles.
B) Issued and Outstanding – Common Shares
2024
2023
Number of
Common
Shares
(thousands)
Amount
Number of
Common
Shares
(thousands)
Amount
Outstanding, Beginning of Year
1,871,868
16,031
1,909,190
16,320
Issued Upon Exercise of Warrants
3,982
39
2,610
26
Issued Under Stock Option Plans
5,049
68
3,679
58
Purchase of Common Shares under NCIB
(55,861)
(479)
(43,611)
(373)
Outstanding, End of Year
1,825,038
15,659
1,871,868
16,031
As at December 31, 2024, there were 48.8 million (December 31, 2023 – 45.5 million) common shares available for future 
issuance under the stock option plan.
C) Normal Course Issuer Bid
On November 7, 2024, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 
127.5 million common shares during the period from November 11, 2024, to November 10, 2025.
For the year ended December 31, 2024, the Company purchased and cancelled 55.9 million common shares (2023 – 43.6 
million) through the NCIB. The shares were purchased at a volume weighted average price of $25.38 per common share (2023 – 
$24.32) for a total of $1.4 billion (2023 – $1.1 billion). Paid in surplus was reduced by $966 million (2023 – $688 million), 
representing the excess of the purchase price of the common shares over their average carrying value of $939 million (2023 – 
$688 million) and taxes paid of $27 million (2023 – $nil). 
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. 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
39
CENOVUS ENERGY 2024 ANNUAL REPORT   |   105

D) Treasury Shares
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.
2024
Number of
Common 
Shares
(thousands)
Amount
Outstanding, Beginning of Year
—
—
Purchase of Common Shares Under Employee Benefit Plan
2,000
43
Outstanding, End of Year
2,000
43
E) Issued and Outstanding – Preferred Shares
First Preferred Shares
2024
2023
Number of 
Preferred 
Shares 
(thousands)
Amount
       Number of
         Preferred
              Shares
     (thousands)
Amount
Outstanding, Beginning of Year
36,000
519
36,000
519
Preferred Shares Redeemed
(10,000)
(163)
—
—
Outstanding, End of Year
26,000
356
36,000
519
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. Paid in surplus was reduced by $87 million, representing the excess of the 
purchase price of the series 3 preferred shares over their carrying value. 
The Company had the following preferred shares outstanding as at December 31, 2024:
As at December 31, 2024
Dividend Reset Date
Dividend Rate
(percent)
Number of 
Preferred 
Shares 
(thousands)
Series 1 First Preferred Shares
March 31, 2026
 2.58 
10,740
Series 2 First Preferred Shares (1)
Quarterly
 5.21 
1,260
Series 5 First Preferred Shares
March 31, 2025
 4.59 
8,000
Series 7 First Preferred Shares
June 30, 2025
 3.94 
6,000
(1)
The floating-rate dividend was 6.77 percent from December 31, 2023, to March 30, 2024 (December 31, 2022, to March 30, 2023 – 5.86 percent); 6.71 percent 
from March 31, 2024, to June 29, 2024 (March 31, 2023, to June 29, 2023 – 6.29 percent); 6.60 percent from June 30, 2024, to September 29, 2024 (June 30, 
2023, to September 29, 2023 – 6.29 percent); and 5.94 percent from September 30, 2024, to December 30, 2024 (September 30, 2023, to December 30, 2023 – 
6.89 percent).
Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert 
their shares into a specified series of first preferred shares should the Company elect to not redeem the shares. On March 31, 
2026, and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares will have such option to 
convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 
and series 6 first preferred shares (if any) will have such option to convert their shares into the other series. On June 30, 2025, 
and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares (if any) will have such option to 
convert their shares into the other series.
Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day 
of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the 
series 1, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the sum of the 
five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1), 3.57 percent (series 
5) and 3.52 percent (series 7). For the series 2, series 6 and series 8 first preferred shares, such dividend rate resets every 
quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date 
plus 1.73 percent (series 2), 3.57 percent (series 6) and 3.52 percent (series 8).
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
40
106   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any 
number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be 
redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all 
or any number of the then-outstanding series 2, series 6 and series 8 first preferred shares, by payment of an amount in cash 
for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid dividends 
thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).
If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common 
shares shall apply. The preferred share dividends are cumulative.
Second Preferred Shares
There were no second preferred shares outstanding as at December 31, 2024 (December 31, 2023 – nil).
F) Issued and Outstanding – Warrants
2024
2023
Number of
Warrants
(thousands)
Amount
Number of
Warrants
(thousands)
Amount
Outstanding, Beginning of Year
7,625
25
55,720
184
Exercised
(3,982)
(13)
(2,610)
(8)
Purchased and Cancelled
—
—
(45,485)
(151)
Outstanding, End of Year
3,643
12
7,625
25
The exercise price of the warrants is $6.54 per share. The warrants expire on January 1, 2026.
On June 14, 2023, Cenovus purchased and cancelled 45.5 million warrants. The price for each warrant purchased represented a 
price of $22.18 per common share, less the warrant exercise price, for a total of $711 million. Retained earnings was reduced by 
$560 million, representing the excess of the purchase price of the warrants over their average carrying value, and $2 million in 
transaction costs.
G) Paid in Surplus
Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as 
Ovintiv Inc. (“Ovintiv”)) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In 
addition, paid in surplus includes the excess of the purchase price of common shares over their average carrying value for 
shares purchased under the NCIB, the excess or deficiency of treasury shares over their average carrying value to settle the 
employee long-term incentive (“LTI”) liability, and stock-based compensation expense related to the Company’s net settlement 
rights (“NSRs”) discussed in Note 29.
Retained 
Earnings Prior 
to Ovintiv Split
Stock-Based 
Compensation
Total
As at December 31, 2022
2,395
296
2,691
Stock-Based Compensation Expense
—
11
11
Purchase of Common Shares Under NCIB
(688)
—
(688)
Common Shares Issued on Exercise of Stock Options
—
(12)
(12)
As at December 31, 2023
1,707
295
2,002
Stock-Based Compensation Expense
—
11
11
Purchase of Common Shares Under NCIB
(966)
—
(966)
Preferred Shares Redeemed
(87)
—
(87)
Common Shares Issued on Exercise of Stock Options
—
(16)
(16)
As at December 31, 2024
654
290
944
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
41
CENOVUS ENERGY 2024 ANNUAL REPORT   |   107

28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Pension and 
Other Post-
Retirement 
Benefits
Private Equity 
Instruments
Foreign 
Currency 
Translation 
Adjustment
Total
As at December 31, 2022
99
29
1,342
1,470
Other Comprehensive Income (Loss), Before Tax
(58)
63
(286)
(281)
Reclassification on Divestiture (Note 5)
—
—
12
12
Income Tax (Expense) Recovery
14
(7)
—
7
As at December 31, 2023
55
85
1,068
1,208
Other Comprehensive Income (Loss), Before Tax
19
81
1,020
1,120
Income Tax (Expense) Recovery
(5)
(10)
—
(15)
As at December 31, 2024
69
156
2,088
2,313
29. STOCK-BASED COMPENSATION PLANS
Cenovus has a number of stock-based compensation plans that include NSRs, Cenovus replacement stock options, performance 
share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”).
A) Employee Stock Options
Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a 
common share of the Company. Option exercise prices approximate the market value for the common shares on the date the 
options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 
percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years. 
Options issued by the Company have associated NSRs. The NSR, in lieu of exercising the option, gives the option holder the right 
to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus's 
common shares at the time of exercise over the exercise price of the option. Alternatively, the holder may elect to exercise the 
option and receive a net cash payment equal to the excess of the market price received from the sale of the common shares 
over the exercise price of the option. 
The NSRs vest and expire under the same terms and conditions of the underlying option.
Stock Options With Associated Net Settlement Rights 
The weighted average unit fair value of NSRs granted during the year ended December 31, 2024, was $5.20 before considering 
forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant 
date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: 
Risk-Free Interest Rate (percent)
 3.51 
Expected Dividend Yield (percent)
 2.37 
Expected Volatility (1) (percent)
 23.64 
Expected Life (years)
5.39
(1)
Expected volatility has been based on historical share volatility of the Company.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
42
108   |   CENOVUS ENERGY 2024 ANNUAL REPORT

For the year ended December 31, 2024, 793 thousand NSRs, with a weighted average exercise price of $11.97, were exercised 
and settled for 562 thousand common shares.
Number of 
Stock Options 
with Associated 
Net Settlement 
Rights
Weighted 
Average 
Exercise Price
For the year ended December 31, 2024
(thousands)
($/unit)
Outstanding, Beginning of Year
11,895
 
13.66 
Granted
2,427
 
23.90 
Exercised
(5,251)
 
10.77 
Forfeited
(416)
 
23.16 
Expired
(2)
 
24.60 
Outstanding, End of Year
8,653
17.83
Outstanding 
Exercisable 
As at December 31, 2024
Number of 
Stock Options 
with Associated 
Net Settlement 
Rights
Weighted 
Average 
Remaining 
Contractual 
Life 
Weighted 
Average 
Exercise Price 
Number of 
Stock Options 
with Associated 
Net Settlement 
Rights
Weighted 
Average 
Exercise Price 
Range of Exercise Price ($/unit)
(thousands)
(years)
($/unit)
(thousands)
($/unit)
5.00 to 9.99
1,486
2.47
8.87
1,486
8.87
10.00 to 14.99
2,004
2.08
11.70
1,902
11.69
15.00 to 19.99
1,560
4.13
19.88
902
19.88
20.00 to 24.99
3,373
5.75
23.84
448
24.14
25.00 to 29.99
230
6.46
27.21
3
27.71
8,653
4.06
17.83
4,741
13.55
Cenovus Replacement Stock Options
For the year ended December 31, 2024, 577 thousand Cenovus replacement stock options, with a weighted average exercise 
price of $7.48, were exercised and net settled for cash and 37 thousand Cenovus replacement stock options were exercised 
with a weighted average price of $5.17 and settled for 29 thousand common shares.
The Company recorded a liability of $5 million as at December 31, 2024, (December 31, 2023 – $12 million) for Cenovus 
replacement stock options based on the fair value at year end using the Black-Scholes-Merton valuation model.
As at December 31, 2024, there were 348 thousand outstanding and exercisable Cenovus replacement stock options, with a 
remaining life of 0.47 years and a weighted average exercise price of $3.54.
Number of 
Cenovus 
Replacement 
Stock Options
Weighted 
Average 
Exercise Price
For the year ended December 31, 2024
(thousands)
($/unit)
Outstanding, Beginning of Year
1,005
 
6.49 
Exercised
(614)
 
7.34 
Expired
(43)
 
18.35 
Outstanding, End of Year
348
3.54
B) Performance Share Units
Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. The PSUs are time-
vested whole-share units that entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment 
equal to the value of a Cenovus common share. PSUs granted under the Performance Share Unit Plan for Local Employees in the 
Asia Pacific region may only be settled in cash.  
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
43
CENOVUS ENERGY 2024 ANNUAL REPORT   |   109

The number of PSUs eligible to vest is determined by a multiplier that ranges from zero percent to 200 percent and is based on 
the Company achieving key pre-determined performance measures. PSUs vest after three years.
The Company has recorded a liability of $80 million as at December 31, 2024, (December 31, 2023 – $238 million) for PSUs 
based on the market value of Cenovus’s common shares at the end of the year. PSUs are paid out upon vesting and, as a result, 
the intrinsic value was $nil as at December 31, 2024.
Number of 
Performance 
Share Units
For the year ended December 31, 2024
(thousands)
Outstanding, Beginning of Year
10,243
Granted
6,368
Vested and Paid Out
(8,903)
Forfeited
(742)
Units Granted in Lieu of Base Dividends
244
Outstanding, End of Year
7,210
C) Restricted Share Units
Cenovus granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and 
entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a 
Cenovus common share. RSUs vest over three years. RSUs granted under the Performance Share Unit Plan for Local Employees 
in the Asia Pacific region may only be settled in cash. 
The Company recorded a liability of $105 million as at December 31, 2024, (December 31, 2023 – $97 million) for RSUs based on 
the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of 
vested RSUs was $nil as at December 31, 2024. 
Number of 
Restricted 
Share Units
For the year ended December 31, 2024
(thousands)
Outstanding, Beginning of Year
7,234
Granted
3,393
Vested and Paid Out
(2,286)
Forfeited
(466)
Units Granted in Lieu of Base Dividends
273
Outstanding, End of Year
8,148
D) Deferred Share Units
Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are 
equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25, 50, 75 or 
100 percent of their annual bonus award into DSUs. DSUs vest immediately, are settled in cash and are redeemed in accordance 
with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship 
or employment.
The Company recorded a liability of $38 million as at December 31, 2024 (December 31, 2023 – $37 million) for DSUs based on 
the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying 
value as DSUs vest at the time of grant.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
44
110   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Number of 
Deferred 
Share Units
For the year ended December 31, 2024
(thousands)
Outstanding, Beginning of Year
1,691
Granted to Directors
126
Granted
72
Units Granted in Lieu of Dividends
58
Redeemed
(186)
Outstanding, End of Year
1,761
E) Total Stock-Based Compensation
For the years ended December 31,
2024
2023
Stock Options With Associated Net Settlement Rights
12
11
Cenovus Replacement Stock Options
1
(5)
Performance Share Units
48
47
Restricted Share Units
60
46
Deferred Share Units
5
(2)
Total Stock-Based Compensation Expense (Recovery)
126
97
30. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
2024
2023
Salaries, Bonuses and Other Short-Term Employee Benefits
1,526
1,344
Pension and Post-Employment Benefits
119
125
Stock-Based Compensation (Note 29)
126
97
Termination Benefits
41
14
1,812
1,580
31. RELATED PARTY TRANSACTIONS
A) Key Management Compensation 
Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-
Presidents. The compensation paid or payable to key management is:
For the years ended December 31,
2024
2023
Salaries, Director Fees and Other Short-Term Benefits
47
40
Pension and Post-Employment Benefits
4
3
Stock-Based Compensation
48
40
Termination Benefits
11
—
110
83
B) Other Related Party Transactions
The Company charges HMLP for construction and management services and incurs costs for the use of HMLP’s pipeline 
systems, as well as transportation and storage services. Access fees and transportation and storage services are based on 
contractually agreed rates with HMLP.
The following table summarizes revenues and associated expenses related to HMLP:
For the years ended December 31,
2024
2023
Revenues from Construction and Management Services
155
160
Transportation Expenses
278
295
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
45
CENOVUS ENERGY 2024 ANNUAL REPORT   |   111

32. FINANCIAL INSTRUMENTS
A) Fair Value of Non-Derivative Financial Instruments
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued 
liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments. 
The fair values of restricted cash, certain portions of other assets and other liabilities, approximate their carrying amount due to 
the specific non-tradeable nature of these instruments. 
Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end 
trading prices of long-term debt on the secondary market (Level 2). As at December 31, 2024, the carrying value of Cenovus’s 
long-term debt was $7.5 billion and the fair value was $6.9 billion (December 31, 2023 carrying value – $7.1 billion, fair value – 
$6.6 billion).
The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are 
not reflective of the Company’s operations. These assets are carried at fair value in other assets. Fair value is determined based 
on recent market activity which may include equity transactions of the entity when available (Level 3).
The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI: 
2024
2023
Fair Value, Beginning of Year
131
55
Acquisitions
7
13
Changes in Fair Value
81
63
Fair Value, End of Year
219
131
B) Fair Value of Risk Management Assets and Liabilities 
Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable 
and accrued liabilities (for short-term positions), other assets and other liabilities (for long-term positions). Changes in fair value 
are recorded in (gain) loss on risk management.
The Company’s risk management assets and liabilities consist of condensate and refined product futures; crude oil and natural 
gas futures and swaps; and renewable power, power and foreign exchange contracts. The Company may also enter into 
forwards and options to manage commodity, foreign exchange and interest rate exposures.
Crude oil, natural gas, condensate, refined products and power contracts are recorded at their estimated fair value based on 
the difference between the contracted price and the period-end forward price for the same commodity, using quoted market 
prices or the period-end forward price for the same commodity, extrapolated to the end of the term of the contract (Level 2). 
The fair value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable 
market data and foreign exchange forward curves (Level 2).
The fair value of renewable power contracts is calculated using internal valuation models that incorporate broker pricing for 
relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair 
value of renewable power contracts are calculated by Cenovus’s internal valuation team, which consists of individuals who are 
knowledgeable and have experience in fair value techniques.
Summary of Risk Management Positions
2024
2023
Risk Management
Risk Management
As at December 31,
Asset
Liability
Net
Asset
Liability
Net
Crude Oil, Natural Gas, Condensate and 
Refined Products
9
10
(1)
11
19
(8)
Power Contracts
6
—
6
2
—
2
Renewable Power Contracts
5
—
5
18
—
18
Foreign Exchange Rate Contracts
—
3
(3)
—
—
—
20
13
7
31
19
12
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
46
112   |   CENOVUS ENERGY 2024 ANNUAL REPORT

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:
As at December 31,
2024
2023
Level 2 – Prices Sourced From Observable Data or Market Corroboration
2
(6)
Level 3 – Prices Sourced From Partially Unobservable Data
5
18
7
12
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities: 
2024
2023
Fair Value of Contracts, Beginning of Year
12
46
Change in Fair Value of Contracts in Place at Beginning of Year
(20)
—
Change in Fair Value of Contracts Entered Into During the Year
(30)
(45)
Fair Value of Contracts Realized During the Year
46
9
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
(1)
2
Fair Value of Contracts, End of Year
7
12
Offsetting Financial Assets and Liabilities
Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same.
2024
2023
Risk Management
Risk Management
As at December 31,
Asset
Liability
Net
Asset
Liability
Net
Recognized Risk Management Positions
Gross Amount
38
31
7
71
59
12
Amount Offset
(18)
(18)
—
(40)
(40)
—
Net Amount
20
13
7
31
19
12
The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions 
according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit 
risk of financial liabilities is immaterial.
Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the 
related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts 
as commodity prices change. As at December 31, 2024, $18 million was pledged as cash collateral (December 31, 2023 – $47 
million).
C) Earnings Impact of (Gains) Losses From Risk Management Positions
For the years ended December 31,
2024
2023
Realized (Gain) Loss
46
9
Unrealized (Gain) Loss
12
52
(Gain) Loss on Risk Management 
58
61
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative 
instrument relates. 
D) Fair Value of Contingent Payments 
i) 2024 Fair Value
The variable payment (Level 3) associated with the transaction with the Sunrise Acquisition ended on August 31, 2024. The final 
payment was made in October 2024.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
47
CENOVUS ENERGY 2024 ANNUAL REPORT   |   113

ii) 2023 Fair Value
The variable payment (Level 3) associated with the Sunrise Acquisition was carried at fair value in the contingent payments. Fair 
value was estimated by calculating the present value of the expected future cash flows using an option pricing model, which 
assumed the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign 
exchange rate options and both WTI and WCS futures pricing that was discounted using a credit-adjusted risk-free rate. Fair 
value of the variable payment was calculated by Cenovus’s internal valuation team, which consists of individuals who are 
knowledgeable and have experience in fair value techniques. As at December 31, 2023, the fair value of the variable payment 
was estimated to be $164 million applying a credit-adjusted risk-free rate of 5.6 percent. 
As at December 31, 2023, average WCS forward pricing for the remaining term of the variable payment was $71.86 per barrel. 
The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 39.4 percent and 5.8 percent, 
respectively.
As at December 31, 2023, changes in WCS forward prices, with fluctuations in all other variables held constant, could have 
impacted earnings before income tax as follows:
Sensitivity Range
Increase
Decrease
WCS Forward Prices
± $10.00 per barrel
(21)
45
33. RISK MANAGEMENT
Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates, 
commodity power prices as well as credit risk and liquidity risk. 
To manage exposure to commodity price movements between when products are produced or purchased and when sold to the 
customer or used by Cenovus, the Company may periodically enter into financial positions as a part of ongoing operations to 
market the Company’s production and physical inventory positions of crude oil, natural gas, condensate, refined products, and 
power consumption. The Company may also enter into arrangements, such as renewable power contracts or power swaps, to 
manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation 
and refining of crude oil, or to offset select carbon emissions.
To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To manage interest 
costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. To mitigate the 
Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts.
As at December 31, 2024, the fair value of risk management positions was a net asset of $7 million (see Note 32). As at 
December 31, 2024, there were foreign exchange contracts with a notional value of US$250 million and no interest rate 
contracts or cross currency interest rate swap contracts outstanding. As at December 31, 2023, there were no forward 
exchange contracts, interest rate contracts or cross currency interest rate swap contacts outstanding.
Net Fair Value of Risk Management Positions 
As at December 31, 2024
Notional 
Volumes (1) (2)
Terms (3)
Weighted
Average
Price (2)
Fair Value Asset 
(Liability)
WTI Contracts Related to Blending (4)
WTI Fixed – Sell
1.6 MMbbls
January 2025 - November 2025
US$70.18/bbl
(3)
WTI Fixed – Buy
0.3 MMbbls
January 2025 - November 2025
US$72.80/bbl
(1)
Power Contacts
6
Renewable Power Contracts
5
Other Financial Positions (5)
3
Foreign Exchange Rate Contracts
(3)
Total Fair Value
7
(1)
Million barrels ("MMbbls").
(2) 
Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the 
notional volumes and weighted average price may fluctuate from month to month. 
(3) 
Includes individual contracts with varying terms, the longest of which is 14 months.
(4) 
WTI contracts related to blending are used to help manage price exposure to condensate used for blending.
(5) 
Includes risk management positions related to WCS, heavy oil, light oil and condensate differentials, benchmark delivery location spreads, Belvieu fixed price 
contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts and the Company’s U.S. refining 
and marketing activities. 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
48
114   |   CENOVUS ENERGY 2024 ANNUAL REPORT

A) Commodity Price and Foreign Exchange Rate Risk
i) Commodity Price Risk 
Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future 
cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered 
into various financial derivative instruments. 
The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of 
Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.
The Company has used crude oil, natural gas, condensate, refined product and power risk management contracts, and may 
enter into options, forward or swaps. In addition, various crude oil, natural gas and condensate basis contracts for both price 
and location may be used. These derivative instruments are used to partially mitigate exposure to the commodity price risk on 
its crude oil and condensate transactions and to protect both near-term and future cash flows. Cenovus has entered into a 
number of transactions to help protect against widening light/heavy crude oil price differentials and to manage exposure to 
commodity price movements between when products are produced or purchased and when sold to the customer or used by 
Cenovus. In addition, the Company has entered into risk management positions to help mitigate the risk to incremental margin 
expected to be received in future periods at the time products will be sold. The Company has used commodity futures and 
swaps, as well as differential price risk management contracts to partially mitigate its exposure to the commodity price risk on 
its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate its natural gas 
commodity price risk. 
ii) Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of 
Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the 
U.S./Canadian dollar can have a significant effect on reported results. 
Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the 
U.S. dollar debt issued from Canada (see Note 8). As at December 31, 2024, Cenovus had US$3.8 billion in U.S. dollar debt 
(December 31, 2023 – US$3.8 billion).
iii) Commodity Price and Foreign Exchange Rate Sensitivities
The following tables summarize the sensitivity of the fair value of Cenovus’s risk management positions to independent 
fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the 
fluctuations identified in the tables below are a reasonable measure of volatility. 
The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions 
could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:
As at 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”). 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
49
CENOVUS ENERGY 2024 ANNUAL REPORT   |   115

As at December 31, 2023
Sensitivity Range
Increase
Decrease
Crude Oil and Condensate Commodity 
Price
± US$10.00/bbl Applied to WTI, Condensate and Related Hedges
(1)
1
Crude Oil and Condensate Differential 
Price (1)
± US$2.50/bbl Applied to Differential Hedges Tied to Production
(4)
4
WCS (Hardisty) Differential Price
± US$5.00/bbl Applied to WCS Differential Hedges Tie to Production
—
—
Refined Products Commodity Price
± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges
(3)
3
Natural Gas Commodity Price
± $1.00/Mcf Applied to Natural Gas Hedges Tied to Production
—
—
Natural Gas Basis Price
± US$0.50/Mcf Applied to Natural Gas Basis Hedges
—
—
Power Commodity Price
± C$20.00/MWh Applied to Power Hedges
92
(92)
U.S. to Canadian Dollar Exchange Rate
± $0.05 in the U.S. to Canadian Dollar Exchange Rate
—
—
(1)
Excluding WCS at Hardisty.
In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have 
resulted in a change to the foreign exchange (gain) loss as follows:
As at December 31,
2024
2023
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate
196
197
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate
(196)
(197)
B) Credit Risk
Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails 
to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved 
by the Audit Committee and the Board of Directors, which is designed to ensure that its credit exposures are within an 
acceptable risk level. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how 
credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits. 
Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing 
basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to 
normal industry credit risks. Cenovus’s exposure to its counterparties is within its credit policy tolerances. The maximum credit 
risk exposure associated with accounts receivable and accrued revenues, net investment in finance leases, risk management 
assets and long-term receivables is the total carrying value.
As at December 31, 2024, approximately 79 percent (December 31, 2023 – 83 percent) of the Company’s accounts receivable 
and accrued revenues were with investment grade counterparties, and 96 percent of the Company’s accounts receivable were 
outstanding for less than 60 days. The associated average expected credit loss (“ECL”) on these accounts was 0.4 percent as at 
December 31, 2024 (December 31, 2023 – 0.4 percent). 
C) Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity 
risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price.
As disclosed in Note 22, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted 
Funds Flow ratio of approximately 1.0 times at a WTI price of US$45.00 per barrel to manage the Company’s overall debt 
position.  
As at December 31, 2024, the Company’s sources of capital included:
•
$3.1 billion in cash and cash equivalents.
•
$5.5 billion available on its committed credit facility.
•
$1.3 billion available on its uncommitted demand facilities, of which $1.1 billion may be drawn for general purposes, 
or the full amount may be available to issue letters of credit. 
•
US$105 million (C$151 million) on the Company’s proportionate share of the uncommitted demand facilities from 
WRB. 
•
The base shelf prospectus, availability of which is dependent on market conditions.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
50
116   |   CENOVUS ENERGY 2024 ANNUAL REPORT

Undiscounted cash outflows relating to financial liabilities are:
As at December 31, 2024
1 Year
Years 2 and 3
Years 4 and 5
Thereafter
Total
Accounts Payable and Accrued Liabilities (1)
6,242
—
—
—
6,242
Short-Term Borrowings
173
—
—
—
173
Lease Liabilities (2)
538
824
645
2,606
4,613
Long-Term Debt (2)
526
1,910
1,989
7,286
11,711
As at December 31, 2023
1 Year
Years 2 and 3
Years 4 and 5
Thereafter
Total
Accounts Payable and Accrued Liabilities (1)
5,480
—
—
—
5,480
Short-Term Borrowings
179
—
—
—
179
Contingent Payments
168
—
—
—
168
Lease Liabilities (2)
438
712
569
2,635
4,354
Long-Term Debt (2)
313
792
3,007
7,145
11,257
(1)
Includes current risk management liabilities.
(2)
Principal and interest, including current portion, if applicable.
34. SUPPLEMENTARY CASH FLOW INFORMATION
A) Working Capital 
As at December 31,
2024
2023
Total Current Assets
10,434
9,708
Total Current Liabilities
7,362
6,210
Working Capital 
3,072
3,498
B) Changes in Non-Cash Working Capital 
For the years ended December 31,
2024
2023
Accounts Receivable and Accrued Revenues
547
314
Income Tax Receivable
199
(295)
Inventories
(117)
216
Accounts Payable and Accrued Liabilities
299
(685)
Income Tax Payable
322
(1,112)
Total Change in Non-Cash Working Capital
1,250
(1,562)
Net Change in Non-Cash Working Capital – Operating Activities
1,305
(1,193)
Net Change in Non-Cash Working Capital – Investing Activities
(55)
(369)
Total Change in Non-Cash Working Capital
1,250
(1,562)
C) Cash Flows Related to Interest and Taxes
For the years ended December 31,
2024
2023
Interest Paid
356
402
Interest Received
163
130
Income Taxes Paid
868
2,595
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
51
CENOVUS ENERGY 2024 ANNUAL REPORT   |   117

D) Reconciliation of Liabilities 
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
Dividends 
Payable
Warrants
Short-Term 
Borrowings
Long-Term 
Debt
Lease 
Liabilities
As at December 31, 2022
9
—
115
8,691
2,836
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
—
—
58
—
—
Repayment of Long-Term Debt
—
—
—
(1,346)
—
Principal Repayment of Leases
—
—
—
—
(288)
Dividends Paid
(1,026)
—
—
—
—
Payment for Purchase of Warrants
—
(711)
—
—
—
Finance and Transaction Costs
—
(2)
—
—
—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
—
—
—
(84)
—
Finance and Transaction Costs
—
2
—
(19)
—
Lease Acquisitions
—
—
—
—
33
Lease Additions
—
—
—
—
57
Base Dividends Declared on Common Shares 
990
—
—
—
—
Dividends Declared on Preferred Shares
36
—
—
—
—
Warrants Purchased and Cancelled
—
711
—
—
—
Exchange Rate Movements and Other
—
—
6
(134)
20
As at December 31, 2023
9
—
179
7,108
2,658
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
—
—
5
—
—
Principal Repayment of Leases
—
—
—
—
(299)
Dividends Paid
(1,551)
—
—
—
—
Non-Cash Changes:
Finance and Transaction Costs
—
—
—
(16)
—
Lease Additions
—
—
—
—
363
Base Dividends Declared on Common Shares 
1,255
—
—
—
—
Variable Dividends Declared on Common Shares
251
—
—
—
—
Dividends Declared on Preferred Shares
36
—
—
—
—
Exchange Rate Movements and Other
—
—
(11)
442
205
As at December 31, 2024
—
—
173
7,534
2,927
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
52
118   |   CENOVUS ENERGY 2024 ANNUAL REPORT

35. COMMITMENTS AND CONTINGENCIES
A) Commitments
Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities 
less than one year are excluded from the table below. Future payments for the Company’s commitments are below:
As at December 31, 2024
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
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
As at December 31, 2023
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
Transportation and Storage (1) (2)
2,018
1,927
1,680
1,663
1,641
15,738
24,667
Product Purchases
617
—
—
—
—
—
617
Real Estate
57
57
59
63
58
604
898
Obligation to Fund HCML
94
94
94
89
52
90
513
Other Long-Term Commitments
417
194
184
175
166
965
2,101
Total Commitments
3,203
2,272
2,017
1,990
1,917
17,397
28,796
(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).
There were outstanding letters of credit aggregating to $355 million (December 31, 2023 – $364 million) issued as security for 
financial and performance conditions under certain contracts. 
B) Contingencies
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that 
any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its 
Consolidated Financial Statements. 
Income Tax Matters
The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are 
continually changing. As a result, there are usually a number of tax matters under review. Management believes that the 
provision for taxes is adequate.
36. MATERIAL ACCOUNTING POLICIES
A) Revenue Recognition 
Revenue is based on the consideration specified in a contract and is recorded when control of the product or service passes to 
the customer in accordance with terms of the contract. Performance obligations are largely satisfied at a point in time upon the 
delivery of crude oil, NGLs, natural gas, and petroleum and refined products. Cenovus sells its production of crude oil, NGLs, 
natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for 
variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Performance 
obligations for crude oil and natural gas processing revenue, transportation services and transloading services are satisfied over 
time as the service is provided. Revenue associated with crude oil and natural gas processing, transportation services and 
transloading services are generally based on fixed price contracts.
Revenues are typically collected in the month following delivery. Therefore, Cenovus has elected to apply the practical 
expedient to not adjust consideration for the effects of a financing component. The Company does not disclose information 
about remaining performance obligations with an original expected duration of one year or less and it does not have any long-
term contracts, with the exception of certain construction contracts with HMLP and take-or-pay contracts, with unfulfilled 
performance obligations.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
53
CENOVUS ENERGY 2024 ANNUAL REPORT   |   119

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded 
as non-monetary exchanges on a net basis.
Cenovus has take-or-pay contracts where customers are required to take, or pay for, minimum quantities. If a customer has a 
right to defer delivery to a later date, Cenovus’s performance obligation has not been satisfied. Revenue is deferred and 
recognized only when the product is delivered, or the deferral provision can no longer be extended. 
B) Purchased Product, Transportation and Blending
Purchased Product
Purchased product includes the costs of refining feedstock, crude oil and diluent purchased for optimization activities, and costs 
associated with transporting refined products to market.
Transportation and Blending
Costs paid for the transportation of crude oil, NGLs and natural gas, and the cost of diluent used in blending are recognized 
when the product is sold. 
C) Employee Benefit Plans
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit 
component. OPEB plans are also provided to qualifying employees. In some cases, the benefits are provided through medical 
care plans to which the Company, employees and retirees may contribute. In some plans, benefits are not funded before 
employees retire. 
The cost of the defined contribution pension plan is recorded as the benefits are earned. The cost of the defined benefit 
pension and OPEB plans are actuarially determined using the projected unit credit method. The estimated cost is based on 
length of service and reflects Management’s best estimate of salary escalation, longevity rates, employees’ retirement age and 
expected future health care costs. The liability for the defined benefit pension and OPEB plans is the present value of the 
defined benefit obligation less the fair value of plan assets. 
Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, 
corresponding to where the salaries of the employees providing the service are recorded. Interest costs on the net obligation 
(asset) are included as part of pension benefit costs. Remeasurement changes, including actuarial gains or losses related to the 
plan assets and defined benefit obligation, the effect of changes to the asset ceiling and return on plan assets are recognized in 
OCI when they occur.
D) Deferred Income Taxes
Cenovus follows the liability method of accounting for deferred income taxes. Under this method, deferred income taxes are 
recorded for the effect of any temporary difference between the accounting basis and income tax basis of an asset or liability, 
using the substantively enacted income tax rates expected to apply when the assets will be realized, or liabilities will be settled. 
The effect of a change in the enacted tax rate or laws is recognized in net earnings (loss) in the period that the change occurs, 
except when it relates to items recorded in equity or OCI, in which case the deferred income tax is also recorded in equity or 
OCI, respectively.
Deferred income tax is recognized on temporary differences arising from investments in subsidiaries, except in the case where 
the timing of the reversal of the temporary difference is controlled by the Company, and it is probable that the temporary 
difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.
Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available 
against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they 
arise within the same entity and tax jurisdiction. 
E) Inventories
Product inventories are valued at the lower of cost, using a first-in, first-out, or weighted average cost basis, and net realizable 
value. Parts and supplies are valued at the lower of weighted average cost and net realizable value. The cost of inventory 
includes purchase costs, direct production costs, and DD&A. Net realizable value is the estimated selling price in the ordinary 
course of business less expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized in 
net earnings (loss). 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
54
120   |   CENOVUS ENERGY 2024 ANNUAL REPORT

F) Exploration and Evaluation Assets
E&E assets consist of exploratory projects for crude oil, NGLs and natural gas that are pending the determination of proved 
reserves. The costs to acquire non-producing oil and gas properties, licenses to explore, drilling exploratory wells and the costs 
to evaluate the commercial potential of the resources are initially capitalized as E&E assets. Costs incurred prior to obtaining 
the legal right to explore an area (pre-exploration costs) are recorded as exploration expense when incurred. 
Once technical feasibility and commercial viability of an E&E asset is established, the carrying value is transferred to PP&E. If 
Management does not consider an E&E asset to be technically feasible and commercially viable, the related capital costs are 
written off as exploration expense.  
G) Property, Plant and Equipment 
PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals. Capitalized costs 
include the purchase price, construction or development expenditures, directly attributable internal costs, decommissioning 
liabilities and, for qualifying assets, borrowing costs. Costs incurred to install the asset and make it ready for its intended use are 
also capitalized. Expenditures that improve the productive capacity or extend the life of an asset are capitalized, while 
maintenance costs and repairs are expensed as incurred.
Crude Oil and Natural Gas Properties
Development and production assets are capitalized by area. Costs includes all expenditures associated with the development of 
crude oil and natural gas properties and related infrastructure, as well as expenditures transferred from E&E assets. 
Development and production assets are depleted using the unit-of-production method based on estimated reserves 
determined using forward prices and costs. The unit-of-production depletion rate takes into account expenditures incurred to 
date, together with the future development expenditures required to develop reserves. Onshore assets are depleted based on 
estimated proved reserves. Offshore assets are depleted based on estimated proved developed producing reserves or proved 
plus probable reserves. 
Refining Assets 
The Company’s refineries and plants are composed of highly integrated and interdependent crude oil and other feedstock 
processing facilities and supporting infrastructure. Where facilities and equipment, including major components, are significant 
in relation to the total cost of the assets and have different useful lives, they are depreciated on a straight-line basis over the 
estimated service life of each component. Major components are depreciated as follows:
•
Land improvements and buildings: 10 to 40 years.
•
Office equipment and vehicles: 3 to 15 years.
•
Rail facilities: 10 to 40 years.
•
Refining equipment: 5 to 60 years.
Processing, Transportation and Storage Assets, Commercial Fuels Business and Other 
Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, 
which range from three to 60 years. Land is not depreciated.
H) Impairments of Assets
Impairment and Impairment Reversals of Non-Financial Assets
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 of an asset or CGU may exceed its recoverable amount. Goodwill is tested for 
impairment at least annually. E&E assets are also tested for impairment immediately prior to being transferred to PP&E.
Cenovus allocates E&E assets to a related CGU containing development and production assets when testing for impairment. 
ROU assets may be tested as part of a CGU, as a separate CGU, or as an individual asset. Goodwill is allocated to CGUs that 
benefited from the historical business combinations.
The recoverable amount of the asset or CGU is estimated as the greater of value-in-use (“VIU”) and FVLCOD. VIU is estimated as 
the present value of the future cash flows expected to arise from the continuing use of an asset or CGU. FVLCOD is the amount 
that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and 
willing parties. The FVLCOD for upstream assets is estimated based on the discounted after-tax cash flows of reserves using 
forward prices, future operating costs and future capital expenditures consistent with Cenovus’s IQREs, and may consider an 
evaluation of comparable asset transactions. FVLCOD for downstream assets is estimated based on discounted after-tax cash 
flows of refined product production, forward crude oil prices, forward crack spreads, net of RINs, future capital expenditures, 
future operating costs and discount rates. Forward prices are based on third-party consultant forecasts.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
55
CENOVUS ENERGY 2024 ANNUAL REPORT   |   121

If the recoverable amount of the asset or CGU is less than the carrying amount, an impairment loss is recognized. The 
impairment loss first reduces the goodwill allocated to a CGU, if any, and then reduces the carrying amount of the remaining 
assets in the CGU. Impairment losses on PP&E and ROU assets are recognized as additional DD&A. E&E asset impairments or 
write-downs are recognized as exploration expense. 
Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for 
indicators that the impairment losses may no longer exist or may have decreased. If such indications exist, the carrying amount 
of the asset or CGU is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying 
amount does not exceed the amount that would have been determined had no impairment loss been recognized in prior 
periods. The reversal is recognized as a reduction to DD&A. 
Impairment of Financial Assets
At each reporting date, the Company assesses the expected credit losses associated with its financial assets measured at 
amortized cost. For accounts receivable, Cenovus measures loss allowances at an amount equal to lifetime ECLs. ECLs are 
estimated as the difference between the cash flows due to the Company and the cash flows the Company expects to receive, 
discounted at the effective interest rate on initial recognition. Changes in ECLs are recognized in other income (loss).
I) Leases
As Lessee 
The Company recognizes an ROU asset and a lease liability when the leased asset is available for use. 
Lease liabilities are measured at the present value of lease payments and estimated costs to dismantle and remove the 
underlying leased asset. Lease liabilities are discounted using the interest rate implicit in the lease or, if that rate cannot be 
readily determined, the Company’s incremental borrowing rate. Lease payments include fixed payments, as well as variable 
payments based on an index or rate. Lease liabilities are re-measured when there is a change in the future lease payments due 
to a change in an index or rate. Re-measurement will also occur if there is a change in the expected residual value guarantee or 
if the Company reconsiders the exercise of a purchase, extension or termination option that is within its control. When the 
lease liability is re-measured, an adjustment is also made to the carrying amount of the ROU asset.
The ROU asset is initially measured at cost, which includes the initial measurement of the lease liability and initial direct costs. 
The cost is depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term.
Leases with a term of less than twelve months, or leases of an asset with a low value, are recognized over the lease term as an 
operating, transportation, or general and administrative expense. The Company has elected not to separate non-lease 
components for storage tanks.
As Lessor 
Leases where the Company transfers substantially all of the risks and rewards from ownership of an underlying asset are 
classified as financing leases. The Company recognizes a receivable at an amount equal to the net investment in the lease, 
which is the present value of the aggregate of lease payments receivable by the lessor. Cenovus recognizes lease payments for 
operating leases as income on a straight-line basis over the term of the lease as other income.
J) Business Combinations and Goodwill
Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, 
liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of 
acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets.
Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and 
classified as a financial liability or equity in accordance with the terms of the agreement. Contingent consideration classified as 
a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings (loss). 
Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value 
of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating 
activities. Contingent consideration classified as equity is not re-measured and settlements are recorded in equity. 
When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date 
fair value and recognizes the resulting gain or loss, if any, in net earnings (loss).
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
56
122   |   CENOVUS ENERGY 2024 ANNUAL REPORT

K) Provisions
A provision is recognized if the Company has a present legal or constructive obligation as a result of a past event. It must be 
possible to reliably estimate the obligation and it is more likely than not that an outflow of economic benefits will be required 
to settle the obligation. Where applicable, the expected future cash flows of a provision are discounted using a credit-adjusted 
risk-free rate. The increase in the provision due to the passage of time is recognized as a finance expense.
Decommissioning Liabilities 
The Company will be required to retire its tangible long-lived assets such as producing well sites, upstream processing facilities, 
surface and subsea plant and equipment, refining facilities and the crude-by-rail terminal. When a disturbance occurs, the 
Company recognizes a decommissioning liability equal to the present value of estimated future expenditures required to settle 
the obligation using a credit-adjusted risk-free rate. The initial estimate of the liability is added to the cost of the related asset 
and amortized over the useful life of the asset. Changes in the provision arising from revisions to expected timing or future 
decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. Actual 
expenditures incurred are charged against the liability.
Renewable Fuel Obligations
The Company’s U.S. refining operations incur an RVO, which the Company settles annually using RINs. After considering RINs on 
hand, the RVO is measured at the expected market price, or on a contracted forward rate, if applicable, of the additional RINs 
required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the 
month purchased. RINs purchased on a secondary market are measured at cost. RINs are not amortized. A net RIN position is 
presented in other assets and a net RVO position is included in other liabilities.
L) Share Capital and Warrants
Common shares, treasury shares and preferred shares are classified as equity. When the Company purchases its own common 
shares, share capital is reduced by the weighted average carrying value of the shares purchased. Any difference between the 
purchase price and the carrying value is recorded to paid in surplus. No gain or loss is recognized on the purchase, sale, issuance 
or cancellation of equity instruments. Common shares and preferred shares are cancelled upon purchase.
Common shares purchased under the employee benefit plan are measured at their cost to acquire and are recorded as treasury 
shares. When the treasury shares are distributed under the employee benefit plan, the treasury shares are reduced by their 
weighted average carrying value with the excess or deficiency from the settled employee LTI liability recognized in paid in 
surplus.
Transaction costs directly attributable to the issue or repurchase of common shares, treasury shares and preferred shares are 
recognized as a deduction from equity, net of any income taxes.
Warrants are classified as equity and are measured at fair value upon issuance. On exercise, the cash consideration received by 
the Company and the associated carrying value of the warrants are recorded as share capital.
M) Stock-Based Compensation 
Cenovus has a number of stock-based compensation plans that include stock options with associated NSRs, Cenovus 
replacement stock options, PSUs, RSUs and DSUs. Stock-based compensation costs are recorded in general and administrative 
expenses.
Stock Options With Associated Net Settlement Rights
NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-
Merton valuation model, and are not revalued at each reporting date. The fair value is recognized as stock-based compensation 
over the vesting period, with a corresponding increase recorded as paid in surplus. On exercise, the cash consideration received 
by the Company and the associated paid in surplus are recorded as share capital. 
Cenovus Replacement Stock Options 
Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period 
end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting 
period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are 
settled for common shares, the cash consideration received by the Company and the previously recorded liability associated 
with the stock option are recorded as share capital.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
57
CENOVUS ENERGY 2024 ANNUAL REPORT   |   123

Performance, Restricted and Deferred Share Units
PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of 
Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation over the vesting 
period. Fair value fluctuations are recognized in stock-based compensation in the period they occur. Cenovus has certain PSU 
and RSU plans that may be settled in cash or common shares at the Company's option and certain plans that are settled in cash.
N) Financial Instruments
Financial assets are classified and measured as follows based on the objective of the business model for managing the 
instrument or group of instruments, and the contractual terms of the cash flows. Financial liabilities are measured at amortized 
cost or fair value through profit or loss as noted below. 
Classification
Instrument Type
Amortized Cost
Cash and cash equivalents, restricted cash, accounts receivable and accrued revenues, 
accounts payable and accrued liabilities, short-term borrowings, lease liabilities and long-
term debt.
Fair Value Through Profit or Loss
Risk management assets and liabilities, and contingent payments.
Fair Value Through Other Comprehensive
   Income (Loss)
Certain equity investments not held for trading for which an irrevocable election was 
made at initial recognition.
All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on 
the classification of the financial instrument. 
Cenovus uses observable market inputs as much as possible when estimating the fair value of financial instruments. Inputs are 
categorized into the following levels based on how observable the inputs are:
•
Level 1: Quoted prices in active markets for identical assets and liabilities.
•
Level 2: Inputs other than quoted prices included within Level 1, that are observable for the asset or liability either 
directly or indirectly.
•
Level 3: Unobservable inputs for the asset or liability.
Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a 
net basis or settle the asset and liability simultaneously.
Derivatives
Derivative financial instruments are primarily used to manage economic exposure to market risks relating to commodity prices, 
foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation 
and approvals for the use of derivative financial instruments. 
Derivative financial instruments are measured at fair value through profit or loss unless designated for hedge accounting. 
Derivative instruments not designated as hedges are recorded using mark-to-market accounting whereby any changes in fair 
value are recorded as a gain or loss on risk management. The estimated fair value of derivative instruments is based on quoted 
market prices or, in their absence, third-party market indications and forecasts.
O) Recent Accounting Pronouncements
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.
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.  
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2024
Cenovus Energy Inc. – 2024 Consolidated Financial Statements
58
124   |   CENOVUS ENERGY 2024 ANNUAL REPORT

SUPPLEMENTAL INFORMATION (unaudited) 
Financial Statistics
($ millions, except per share amounts)
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30,
Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
Revenues
2024
2024
2024
2024
2023
2024
2023
Upstream
  Oil Sands
6,217 
6,286 
6,739 
5,931 
5,636 
25,173 
23,133 
  Conventional
761 
698 
669 
855 
779 
2,983 
3,161 
  Offshore
348 
346 
448 
331 
480 
1,473 
1,518 
Total Upstream Revenue
7,326 
7,330 
7,856 
7,117 
6,895 
29,629 
27,812 
Downstream
  Canadian Refining
1,263 
1,580 
1,135 
1,332 
1,557 
5,310 
6,233 
  U.S. Refining (1)
6,574 
7,218 
7,615 
6,901 
6,847 
28,308 
26,393 
Total Downstream Revenue (1)
7,837 
8,798 
8,750 
8,233 
8,404 
33,618 
32,626 
Corporate and Eliminations 
(2,350) 
(2,309) 
(2,024) 
(2,287) 
(2,165) 
(8,970) 
(8,234) 
Total Revenues (1)
12,813 
13,819 
14,582 
13,063 
13,134 
54,277 
52,204 
Operating Margin
Upstream
  Oil Sands
2,340 
2,467 
2,748 
2,236 
1,962 
9,791 
8,169 
  Conventional
88 
12 
42 
149 
123 
291 
583 
  Offshore
242 
252 
299 
246 
370 
1,039 
1,118 
Total Upstream Operating Margin (2)
2,670 
2,731 
3,089 
2,631 
2,455 
11,121 
9,870 
Downstream
  Canadian Refining
47 
60 
(255)
68 
126 
(80) 
675 
  U.S. Refining
(443) 
(383)
102 
492 
(430)
(232)
477 
Total Downstream Operating Margin (2)
(396) 
(323)
(153)
560 
(304)
(312)
1,152 
Total Operating Margin (3)
2,274 
2,408 
2,936 
3,191 
2,151 
10,809 
11,022 
Cash From (Used in) Operating Activities and Adjusted Funds Flow 
Cash From (Used in) Operating Activities
2,029 
2,474 
2,807 
1,925 
2,946 
9,235 
7,388 
Deduct (Add Back):
  Settlement of Decommissioning Liabilities
(64) 
(74)
(48)
(48)
(65)
(234) 
(222) 
  Net Change in Non-Cash Working Capital
492 
588  
494 
(269)
949 
1,305 
(1,193) 
Adjusted Funds Flow (3)
1,601 
1,960 
2,361 
2,242 
2,062 
8,164 
8,803 
Per Share - Basic (3)
0.88 
1.06 
1.27 
1.20 
1.10 
4.41 
4.64 
Per Share - Diluted (3)
0.87 
1.05 
1.26 
1.19 
1.08 
4.38 
4.54 
Net Earnings (Loss)
Net Earnings (Loss)
146 
820 
1,000 
1,176 
743 
3,142 
4,109 
Per Share - Basic
0.08 
0.44 
0.53 
0.62 
0.39 
1.68 
2.15 
Per Share - Diluted
0.07 
0.42 
0.53 
0.62 
0.32 
1.67 
2.09 
Capital Investment
Upstream
  Oil Sands
773 
681 
613 
647 
618 
2,714 
2,382 
  Conventional
121 
106 
68 
126 
129 
421 
452 
  Offshore
  Atlantic
312 
341 
266 
158 
161 
1,077 
635 
  Asia Pacific
24 
14 
29 
1 
3 
68 
7 
  Total Offshore
336 
355 
295 
159 
164 
1,145 
642 
Total Upstream Capital Investment
1,230 
1,142 
976 
932 
911 
4,280 
3,476 
Downstream
  Canadian Refining
63 
44 
70 
31 
46 
208 
145 
  U.S. Refining
168 
153 
100 
67 
167 
488 
602 
Total Downstream Capital Investment
231 
197 
170 
98 
213 
696 
747 
Corporate
17 
7 
9 
6 
46 
39 
75 
Total Capital Investment
1,478 
1,346 
1,155 
1,036 
1,170 
5,015 
4,298 
(1)
Comparative periods reflect certain revisions. See the Prior Period Revisions section located in the Advisory for further details.
(2)
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
(3)
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Cenovus Energy Inc. – Q4 2024 Interim Supplemental Information 
1
CENOVUS ENERGY 2024 ANNUAL REPORT   |   125

 
Financial Statistics
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30,
Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
Financial Metrics
2024
2024
2024
2024
2023
2024
2023
Free Funds Flow (1)
 
123 
614
1,206
1,206
892
 
3,149  
4,505 
Excess Free Funds Flow (1) 
 
(416)  
146  
735  
832  
471 
 
1,297  
2,466 
Long-Term Debt, Including Current Portion
 
7,534  
7,199  
7,275  
7,227  
7,108 
 
7,534  
7,108 
Total Debt
 
7,707  
7,300  
7,412  
7,227  
7,287 
 
7,707  
7,287 
Net Debt
 
4,614  
4,196  
4,258  
4,827  
5,060 
 
4,614  
5,060 
Net Debt to Adjusted Funds Flow (2) (times)
0.6  
0.5  
0.4  
0.5  
0.6 
0.6  
0.6 
Net Debt to Adjusted EBITDA (2) (times)
0.5
0.4
0.4
0.4
0.5
0.5
0.5
Income Tax and Exchange Rates
Effective Tax Rate on Net Earnings (Loss) (percent)
22.8
18.5
Foreign Exchange Rates
   US$ per C$1 - Average
 
0.715  
0.733  
0.731  
0.741  
0.734 
0.730
0.741
   US$ per C$1 - Period End
 
0.695  
0.741  
0.731  
0.738  
0.756 
0.695
0.756
   RMB per C$1 - Average
 
5.142  
5.255  
5.293  
5.330  
5.304 
5.255
5.247
Common Share Information
Commons Shares Outstanding (millions)
   Period End
 
1,825  
1,829  
1,857  
1,865  
1,872 
 
1,825  
1,872 
   Weighted Average - Basic
 
1,826  
1,848  
1,859  
1,868  
1,879 
 
1,850  
1,895 
   Weighted Average - Diluted
 
1,839  
1,863  
1,874  
1,878  
1,907 
 
1,863  
1,940 
Base Dividend ($ per share)
 
0.180  
0.180  
0.180  
0.140  
0.140 
 
0.680  
0.525 
Variable Dividend ($ per share)
 
—  
—  
0.135  
—  
— 
 
0.135  
— 
Closing Price
   Toronto Stock Exchange (C$ per share)
21.79  
22.62  
26.88  
27.08  
22.08 
21.79  
22.08 
   New York Stock Exchange (US$ per share)
15.15  
16.73  
19.66  
19.99  
16.65 
15.15  
16.65 
Total Share Volume Traded (millions)
 
1,061  
1,120  
1,210  
1,322  
1,193 
 
4,713  
4,421 
Selected Average Benchmark Prices
(Average US$/bbl, unless otherwise indicated)
Crude Oil Prices
   Dated Brent
 
74.69  
80.18  
84.94  
83.24  
84.05 
 
80.76  
82.62 
   West Texas Intermediate (“WTI”)
 
70.27  
75.09  
80.57  
76.96  
78.32 
 
75.72  
77.62 
   Differential Dated Brent - WTI
 
4.42  
5.09  
4.37  
6.28  
5.73 
 
5.04  
5.00 
   Western Canadian Select (“WCS”) at Hardisty 
 
57.71  
61.54  
66.96  
57.65  
56.43 
 
60.97  
58.97 
   Differential WTI - WCS at Hardisty
 
12.56  
13.55  
13.61  
19.31  
21.89 
 
14.75  
18.65 
   WCS at Nederland
 
65.69  
68.51  
74.69  
69.89  
71.59 
 
69.69  
69.74 
   Differential WTI - WCS at Nederland
 
4.58  
6.58  
5.88  
7.07  
6.73 
 
6.03  
7.88 
   Condensate (C5 at Edmonton)
 
70.66  
71.19  
77.14  
72.78  
76.24 
 
72.94  
76.61 
   Differential Condensate - WTI Premium/(Discount)
 
0.39  
(3.90)  
(3.43)  
(4.18)  
(2.08)  
(2.78)  
(1.01) 
   Differential Condensate - WCS at Hardisty Premium/(Discount)
 
12.95  
9.65  
10.18  
15.13  
19.81 
 
11.97  
17.64 
   Synthetic at Edmonton
 
71.11  
76.41  
83.32  
69.42  
78.64 
 
75.07  
79.61 
   Differential Synthetic - WTI Premium/(Discount)
 
0.84  
1.32  
2.75  
(7.54)  
0.32 
 
(0.65)  
1.99 
Refined Product Prices
   Chicago Regular Unleaded Gasoline
 
78.95  
92.29  
99.09  
89.48  
83.72 
 
89.95  
97.86 
   Chicago Ultra-low Sulphur Diesel
 
89.28  
96.55  
99.80  
104.27  
107.24 
 
97.47  
109.70 
Refining Benchmarks
   Chicago 3-2-1 Crack Spread (3)
 
12.12  
18.62  
18.76  
17.45  
13.24 
 
16.74  
24.19 
   Group 3 3-2-1 Crack Spread (3)
 
12.66  
18.95  
18.13  
17.50  
18.55 
 
16.81  
29.66 
   Renewable Identification Numbers (“RINs”)
 
4.02  
3.89  
3.39  
3.68  
4.77 
 
3.74  
7.04 
   Upgrading Differential (4) (C$/bbl)
 
18.64  
20.26  
22.28  
15.65  
29.97 
 
19.21  
27.55 
Natural Gas Prices
   AECO (5) (C$/Mcf)
 
1.48  
0.69  
1.18  
2.50  
2.30 
 
1.46  
2.64 
   NYMEX (6) (US$/Mcf)
 
2.79  
2.16  
1.89  
2.24  
2.88 
 
2.27  
2.74 
(1)
Non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
(2)
Calculated on a trailing twelve-month basis.
(3)
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. 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.
(4)
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.
(5)
Alberta Energy Company ("AECO") 5A natural gas daily index.
(6)
New York Mercantile Exchange ("NYMEX") natural gas monthly index.
SUPPLEMENTAL INFORMATION (unaudited)
Cenovus Energy Inc. – Q4 2024 Interim Supplemental Information 
2
126   |   CENOVUS ENERGY 2024 ANNUAL REPORT

 
Operating Statistics - Upstream
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30,
Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
Upstream Production Volumes (1)
2024
2024
2024
2024
2023
2024
2023
Crude Oil and Natural Gas Liquids (Mbbls/d)
   Oil Sands Bitumen
      Foster Creek
 
195.2 
198.0  
195.0  
196.0  
198.8 
 
196.0  
186.3 
      Christina Lake
 
251.4 
211.8  
237.1  
236.5  
239.6 
 
234.2  
237.4 
      Sunrise
 
53.1 
50.4  
46.1  
48.8  
50.1 
 
49.6  
48.9 
      Lloydminster Thermal
 
108.9 
109.4  
113.5  
114.1  
106.6 
 
111.5  
104.1 
   Lloydminster Conventional Heavy Oil
 
18.0 
16.3  
18.1  
17.9  
17.5 
 
17.6  
16.7 
Total Oil Sands Production
 
626.6 
585.9  
609.8  
613.3  
612.6 
 
608.9  
593.4 
   Conventional
      Light Crude Oil
 
4.8 
4.6  
5.1  
5.3  
6.1 
 
4.9  
5.9 
      Natural Gas Liquids (2)
 
19.7 
21.1  
21.4  
22.0  
22.8 
 
21.0  
21.7 
Total Conventional Production
 
24.5 
25.7  
26.5  
27.3  
28.9 
 
25.9  
27.6 
   Offshore Natural Gas Liquids
      Asia Pacific - China
 
9.1 
8.8  
9.8  
9.5  
9.5 
 
9.3  
8.8 
      Asia Pacific - Indonesia
 
2.9 
1.1  
1.8  
0.9  
1.9 
 
1.7  
2.0 
   Offshore Light Crude Oil
      Atlantic
 
7.5 
9.0  
8.4  
7.2  
9.7 
 
8.0  
8.2 
Total Offshore Production
 
19.5 
18.9  
20.0  
17.6  
21.1 
 
19.0  
19.0 
Total Liquids Production
 
670.6 
630.5  
656.3  
658.2  
662.6 
 
653.8  
640.0 
Conventional Natural Gas (MMcf/d)
   Oil Sands
 
11.8 
10.4  
10.5  
11.9  
12.3 
 
11.1  
11.9 
   Conventional
 
560.5 
554.8  
579.4  
560.5  
569.6 
 
563.8  
554.1 
   Offshore
      Asia Pacific - China
 
200.8 
190.2  
202.5  
204.7  
207.8 
 
199.5  
190.6 
      Asia Pacific - Indonesia
 
100.2 
89.2  
74.8  
78.7  
86.6 
 
85.8  
76.0 
Total Conventional Natural Gas Production
 
873.3 
844.6  
867.2  
855.8  
876.3 
 
860.2  
832.6 
Total Upstream Production (MBOE/d) (3)
 
816.0 
771.3  
800.8  
800.9  
808.6 
 
797.2  
778.7 
Effective Royalty Rates (4) (percent)
Oil Sands
Foster Creek
24.2
25.9
21.1
24.9
31.7
24.0
25.1
Christina Lake
30.2
27.7
25.9
25.0
28.5
27.3
29.5
Sunrise
5.8
7.0
7.3
3.8
10.6
6.1
6.8
Lloydminster (5)
14.3
14.3
11.2
6.8
11.7
11.7
9.5
Conventional
8.4
10.7
12.4
9.9
10.8
10.3
10.8
Offshore
   Asia Pacific - China
7.8
7.8
7.7
7.6
8.7
7.7
6.9
   Asia Pacific - Indonesia
24.1
11.7
16.8
7.7
19.9
16.1
23.2
   Atlantic
1.0
1.0  
(0.6)  
4.5  
2.6 
0.7
3.7
(1)
Before royalties.
(2)
Natural gas liquids include condensate volumes.
(3)
Natural gas volumes have been converted to barrels of oil equivalent ("BOE") on the basis of six thousand cubic feet ("Mcf") to one barrel ("bbl"). BOE may be misleading, 
particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does 
not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to 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.
(4)
Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(5)
Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets.
SUPPLEMENTAL INFORMATION (unaudited)
Cenovus Energy Inc. – Q4 2024 Interim Supplemental Information 
3
CENOVUS ENERGY 2024 ANNUAL REPORT   |   127

Operating Statistics - Upstream
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30,
Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
Oil Sands - Netbacks (1)
2024
2024
2024
2024
2023
2024
2023
Foster Creek
  Bitumen ($/bbl)
  Sales Price
85.87 
84.72 
90.89 
76.80 
74.06 
84.49 
78.18 
  Royalties
16.73 
18.63 
16.08 
16.61 
19.89 
17.03 
16.61 
  Transportation and Blending
16.61 
12.90 
14.69 
10.25 
11.33 
13.57 
11.98 
  Operating
9.60 
9.01 
10.06 
10.81 
9.82 
9.87 
11.44 
  Netback
42.93 
44.18 
50.06 
39.13 
33.02 
44.02 
38.15 
Christina Lake
  Bitumen ($/bbl) 
  Sales Price
72.86 
79.54 
84.93 
66.90 
65.95 
75.74 
68.38 
  Royalties
20.14 
19.91 
20.17 
15.40 
16.67 
18.86 
18.19 
  Transportation and Blending
6.08 
7.63 
7.16 
5.40 
7.36 
6.53 
6.69 
  Operating
8.25 
9.33 
8.49 
8.51 
7.59 
8.63 
8.52 
  Netback
38.39 
42.67 
49.11 
37.59 
34.33 
41.72 
34.98 
Sunrise
  Bitumen ($/bbl) 
  Sales Price
79.30 
83.02 
94.47 
88.36 
76.55 
86.07 
75.23 
  Royalties
3.86 
4.72 
5.53 
2.62 
6.81 
4.26 
4.28 
  Transportation and Blending
12.32 
15.36 
18.71 
18.51 
12.41 
16.07 
12.47 
  Operating
14.84 
12.97 
13.17 
17.02 
13.92 
14.36 
17.02 
  Netback
48.28 
49.97 
57.06 
50.21 
43.41 
51.38 
41.46 
Lloydminster (2)
  Bitumen and Heavy Crude Oil ($/bbl) 
  Sales Price
75.16 
80.67 
89.90 
72.71 
69.11 
79.65 
73.69 
  Royalties
10.15 
11.23 
9.42 
4.58 
7.59 
8.84 
6.53 
  Transportation and Blending
3.71 
3.63 
4.55 
3.89 
3.42 
3.95 
3.51 
  Operating
17.32 
16.91 
17.81 
18.05 
18.05 
17.52 
20.32 
  Netback
43.98 
48.90 
58.12 
46.19 
40.05 
49.34 
43.33 
Total Oil Sands ($/BOE) (3)
  Sales Price
77.83 
81.77 
88.76 
72.79 
70.00 
80.20 
73.02 
  Royalties
15.64 
16.26 
15.21 
12.60 
15.03 
14.92 
14.20 
  Transportation and Blending
9.31 
9.18 
9.98 
7.54 
8.24 
9.00 
8.18 
  Operating
11.10 
11.17 
11.47 
11.86 
10.96 
11.40 
12.54 
  Netback
41.78 
45.16 
52.10 
40.79 
35.77 
44.88 
38.10 
Conventional - Netbacks (1)
  Total Conventional ($/BOE) (3)
  Sales Price 
25.18 
20.42 
22.20 
32.92 
29.09 
25.18 
31.76 
  Royalties
1.34 
1.38 
2.02 
2.16 
2.34 
1.73 
2.56 
  Transportation and Blending 
4.83 
5.15 
5.25 
4.67 
4.71 
4.98 
4.16 
  Operating
10.91 
12.77 
11.25 
13.05 
12.32 
11.99 
13.02 
  Netback
8.10 
1.12 
3.68 
13.04 
9.72 
6.48 
12.02 
(1)      Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. 
(2)      Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets. 
(3)      See footnote 3 on page 127 for BOE definition.
SUPPLEMENTAL INFORMATION (unaudited)
Cenovus Energy Inc. – Q4 2024 Interim Supplemental Information 
4
128   |   CENOVUS ENERGY 2024 ANNUAL REPORT

 
Operating Statistics - Upstream 
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30,
Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
Offshore - Netbacks (1)
2024
2024
2024
2024
2023
2024
2023
China
   Natural Gas Liquids ($/bbl)
      Sales Price
 
90.91  
96.60  
99.65  
95.20  
109.31 
 
95.64  
98.11 
      Royalties
 
14.28  
14.50  
13.78  
13.30  
18.59 
 
13.95  
11.13 
      Operating
 
8.77  
8.14  
7.24  
6.27  
7.23 
 
7.58  
7.38 
   Conventional Natural Gas ($/Mcf)
      Sales Price
 
12.92  
12.68  
12.59  
12.46  
13.04 
 
12.66  
12.95 
      Royalties
 
0.68  
0.67  
0.67  
0.66  
0.71 
 
0.67  
0.70 
      Operating
 
1.46  
1.37  
1.21  
1.05  
1.21 
 
1.27  
1.26 
   Asia Pacific - China Total ($/BOE) (2)
      Sales Price
 
80.39  
80.52  
80.95  
79.21  
84.94 
 
80.26  
82.14 
      Royalties
 
6.28  
6.31  
6.20  
6.00  
7.36 
 
6.19  
5.68 
      Operating
 
8.77  
8.20  
7.24  
6.28  
7.26 
 
7.61  
7.51 
      Netback
 
65.34  
66.01  
67.51  
66.93  
70.32 
 
66.46  
68.95 
Indonesia
   Natural Gas Liquids ($/bbl)
      Sales Price
 
101.42  
111.68  
117.32  
107.19  
124.02 
 
108.19  
106.87 
      Royalties
 
52.25  
53.07  
56.89  
47.48  
64.60 
 
52.99  
56.84 
      Operating
 
10.69  
10.83  
8.49  
9.21  
10.87 
 
9.93  
11.17 
   Conventional Natural Gas ($/Mcf)
      Sales Price
 
8.97  
8.60  
8.67  
8.21  
8.64 
 
8.63  
8.60 
      Royalties
 
1.35  
0.49  
0.54  
0.17  
0.83 
 
0.68  
1.16 
      Operating
 
1.87  
1.83  
1.64  
2.01  
1.81 
 
1.84  
1.78 
   Asia Pacific - Indonesia Total ($/BOE) (2)
      Sales Price
 
60.88  
55.93  
60.43  
53.05  
60.32 
 
57.82  
59.16 
      Royalties
 
14.66  
6.54  
10.17  
4.10  
11.99 
 
9.32  
13.75 
      Operating
 
11.16  
10.95  
9.68  
11.86  
10.86 
 
10.93  
10.76 
      Netback
 
35.06  
38.44  
40.58  
37.09  
37.47 
 
37.57  
34.65 
Total Asia Pacific (3)
   Natural Gas Liquids ($/bbl)
      Sales Price
 
93.47  
98.35  
102.45  
96.25  
111.78 
 
97.59  
99.73 
      Royalties
 
23.51  
18.97  
20.62  
16.32  
26.35 
 
20.02  
19.61 
      Operating
 
9.24  
8.45  
7.44  
6.53  
7.84 
 
7.95  
8.08 
   Conventional Natural Gas ($/Mcf)
      Sales Price
 
11.60  
11.37  
11.53  
11.28  
11.75 
 
11.45  
11.71 
      Royalties
 
0.91  
0.61  
0.63  
0.53  
0.75 
 
0.67  
0.83 
      Operating
 
1.60  
1.52  
1.32  
1.31  
1.39 
 
1.44  
1.41 
   Asia Pacific - Total ($/BOE) (2)
      Sales Price
 
74.23  
73.55  
75.87  
72.84  
78.28 
 
74.13  
76.04 
      Royalties
 
8.93  
6.37  
7.18  
5.54  
8.61 
 
7.05  
7.83 
      Operating
 
9.53  
8.98  
7.84  
7.64  
8.23 
 
8.52  
8.37 
      Netback
 
55.77  
58.20  
60.85  
59.66  
61.44 
 
58.56  
59.84 
Atlantic
   Light Crude Oil ($/bbl)
Sales Price
 
102.78  
106.56  
112.74  
114.07  
121.88 
 
109.58  
113.74 
Royalties
 
1.00  
1.03  
(0.72)  
5.09  
3.16 
 
0.72  
4.24 
Transportation and Blending
 
4.27  
3.00  
5.60  
(2.14)  
5.10 
 
3.81  
4.44 
Operating
 
114.23  
88.40  
79.03  
158.70  
51.41 
 
97.70  
67.93 
Netback
 
(16.72)  
14.13  
28.83  
(47.58)  
62.21 
 
7.35  
37.13 
(1)
Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
(2)
See footnote 3 on page 3 of this Supplemental for BOE definition.
(3)
Reported sales volumes and associated per-unit values reflect Cenovus’s 40 percent interest in Husky-CNOOC Madura Ltd. (“HCML”). The HCML joint venture is accounted for 
using the equity method in the interim Consolidated Financial Statements.
SUPPLEMENTAL INFORMATION (unaudited)
Cenovus Energy Inc. – Q4 2024 Interim Supplemental Information 
5
CENOVUS ENERGY 2024 ANNUAL REPORT   |   129

 
Operating Statistics - Downstream
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30,
Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
Canadian Refining
2024
2024
2024
2024
2023
2024
2023
Operable Capacity (1) (Mbbls/d)
108.0
108.0
108.0
108.0
108.0
108.0
108.0
Total Processed Inputs (2) (Mbbls/d)
112.1
106.4
58.9
108.8
105.1
96.6
107.1
Crude Oil Unit Throughput (Mbbls/d)
104.4
99.4
53.8
104.1
100.3
90.5
100.7
Crude Unit Utilization (1) (percent)
 97 
 92 
 50 
 96 
 93 
 84 
 93 
Total Refined Product Production  (Mbbls/d)
Synthetic Crude Oil
48.8
47.3
20.7
47.1
46.4
41.0
47.6
Asphalt
16.8
16.5
14.0
15.6
14.9
15.7
15.4
Diesel
13.4
11.8
5.2
12.9
13.2
10.8
12.9
Other
35.6
32.5
19.7
35.2
33.4
30.8
33.3
Total Refined Product Production (Mbbls/d)
114.6
108.1
59.6
110.8
107.9
98.3
109.2
Ethanol (Mbbls/d)
3.8
5.5
4.4
5.4
5.4
4.8
5.0
Total Production (Mbbls/d)
118.4
113.6
64.0
116.2
113.3
103.1
114.2
Refining Margin (3) (4) ($/bbl)
16.95
20.63
25.21
22.68
26.48
20.82
30.13
Operating Expenses - Upgrading and Refining (5)
 
131  
143  
377  
147  
138 
 
798  
524 
Operating Expenses - Excluding Turnaround Costs
 
127  
119  
166  
132  
135 
 
544  
520 
   Operating Expenses - Turnaround Costs
 
4  
24  
211  
15  
3 
 
254  
4 
Per-Unit Operating Expenses (5) (6) ($/bbl)
12.65
14.63
70.44
14.83
14.32
22.56  
13.40 
Per-Unit Operating Expenses - Excluding Turnaround Costs (6)
12.26
12.22
30.92
13.36
14.06
15.38  
13.29 
Per-Unit Operating Expenses - Turnaround Costs (6)
0.39
2.41
39.52
1.47  
0.26 
7.18  
0.11 
U.S. Refining (7)
Operable Capacity (1) (Mbbls/d)
612.3
612.3
612.3
612.3
612.3
612.3
612.3
Total Processed Inputs (2) (Mbbls/d)
588.4
568.0
594.0
575.0
500.6
581.4
479.7
Crude Oil Unit Throughput (Mbbls/d)
562.3
543.5
568.9
551.1
478.8
556.4
459.7
  Heavy Crude Oil
218.7
215.7
219.4
224.7
216.3
219.6
173.9
  Light/Medium Crude Oil
343.6
327.8
349.5
326.4
262.5
336.8
285.8
Crude Unit Utilization (1) (8) (percent)
 92 
 89 
 93 
 90 
 78 
 91 
 78 
Total Refined Product Production (Mbbls/d)
Gasoline
301.8
259.7
278.3
281.9
269.6
280.5
231.2
Distillates (9)
216.2
205.3
216.3
200.1
172.2
209.1
167.0
Asphalt
29.1
29.6
26.2
26.1
21.5
28.3
19.8
Other
57.1
77.0
74.7
77.8
50.8
72.1
67.0
Total Refined Product Production (Mbbls/d)
604.2
571.6
595.5
585.9
514.1
590.0
485.0
Refining Margin (3) (4) ($/bbl)
5.14
6.97
14.69
21.08
4.82
11.93
17.36
Weighted Average Crack Spread, Net of RINs (10) (US$/bbl)
8.20
14.79
15.25
13.78
9.50
13.01
18.15
Weighted Average Crack Spread, Net of RINs (10) (C$/bbl)
11.47
20.18
20.86
18.59
12.94
17.82
24.49
Market Capture (4) (8) (11) (percent)
 45 
 35 
 70 
 113 
 37 
 67 
 71 
Operating Expenses (5)
718
751
684
610
658
2,763
2,562
Operating Expenses - Excluding Turnaround Costs
590
666
626
576
615
2,457
2,454
Operating Expenses - Turnaround Costs
128
85
58
34
43
306
108
Per-Unit Operating Expenses (5) (6) ($/bbl)
13.26
14.37
12.66
11.65
14.29
12.99
14.63
Per-Unit Operating Expenses - Excluding Turnaround Costs (6)
10.89
12.74
11.58
11.01
13.35
11.55
14.01
Per-Unit Operating Expenses - Turnaround Costs (6)
2.37
1.63
1.08
0.64
0.94
1.44
0.62
(1)
Operable capacity is the capacity based on crude oil throughput (or “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. Crude unit utilization is calculated as crude oil unit throughput divided by operable 
capacity. 
(2)
Total processed inputs include crude oil and other feedstocks. Blending is excluded.
(3)
The definition of Refining Margin is gross margin divided by total processed Inputs.
(4)
Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
(5)
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.
(6)
Specified financial measure. Per-unit metrics are calculated on total processed inputs. See the Specified Financial Measures Advisory of this Supplemental.
(7)
Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations.
(8)
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. 
(9)
Includes diesel and jet fuel.
(10)
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.
(11)
The definition of Market Capture is Refining Margin divided by the weighted average crack spread, net of RINs, expressed as a percentage. 
SUPPLEMENTAL INFORMATION (unaudited)
Cenovus Energy Inc. – Q4 2024 Interim Supplemental Information 
6
130   |   CENOVUS ENERGY 2024 ANNUAL REPORT

SUPPLEMENTAL INFORMATION (unaudited)
Advisory
Specified Financial Measures
Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by International 
Financial Reporting Standards, as issued by the International Accounting Standards Board, and are considered specified financial measures. These specified 
financial measures may not be comparable to similar measures presented by other issuers. Commencing June 30, 2024, certain metrics were revised for our 
downstream operations. See the Specified Financial Measures in the Advisory as well as our September 30, 2024, and June 30, 2024, Management’s 
Discussion and Analysis (“MD&A”) for definitions and, when required, reconciliations of certain financial measures and non-GAAP disclosures including 
Refining Margin, Market Capture, per-unit operating expenses, per-unit operating expenses – excluding turnaround costs and per-unit operating expenses – 
turnaround costs. For all other specified financial measures, see the Specified Financial Measures in the Advisory, and our MD&A for the periods ended 
December 31, 2024, September 30, 2024, June 30, 2024 and March 31, 2024 (available on SEDAR+ at sedarplus.ca) for information incorporated by reference 
about these specified financial measures.
Cenovus Energy Inc. – Q4 2024 Interim Supplemental Information 
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   131

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 the MD&A. As a result, the disclosure in the AIF in 
respect to certain equity method investees may differ from corresponding information in the 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 
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
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132   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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 
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   133

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 the Annual Report unless expressly 
incorporated by reference herein.
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ABBREVIATIONS AND DEFINITIONS
Abbreviations
The following abbreviations and definitions are used in this document:
Crude Oil and NGLs
Natural Gas
Other
bbl
barrel
Mcf
thousand cubic feet
BOE
barrel of oil equivalent
Mbbls/d
thousand barrels per day
MMcf
million cubic feet
MBOE
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 Advisory.
Cenovus Energy Inc. – 2024 Management's Discussion and Analysis
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SPECIFIED FINANCIAL MEASURES 
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS Accounting Standards 
including Operating Margin, Operating Margin by asset, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted 
Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, 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 the 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
136   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   137

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
138   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   139

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
140   |   CENOVUS ENERGY 2024 ANNUAL REPORT

($ 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 Advisory.
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
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   141

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
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142   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   143

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
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144   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
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CENOVUS ENERGY 2024 ANNUAL REPORT   |   145

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
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146   |   CENOVUS ENERGY 2024 ANNUAL REPORT

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
CENOVUS ENERGY 2024 ANNUAL REPORT   |   147

148   |   CENOVUS ENERGY 2024 ANNUAL REPORT

CENOVUS ENERGY 2024 ANNUAL REPORT   |   149
Annual Meeting
The meeting will be held virtually only. This allows a broader 
base of shareholders to participate regardless of their location. 
Holders of Cenovus common shares are invited to attend the 
virtual Annual Meeting of Shareholders on Thursday, May 8, 2025 
at 1:00 pm. MT via live webcast accessible online at  
https://meetings.lumiconnect.com/400-451-774-675 
Password: cenovus2025
Please see our Management Information Circular available on  
cenovus.com for additional information. 
Registrar and transfer agent
Computershare Investor Services Inc.  
8th Floor, 100 University Avenue  
Toronto, Ontario M5J 2Y1 Canada 
https://www.cenovus.com/Investors/Shareholder-information 
Shareholder inquiries by phone:  
North America 1.866.332.8898 (English and French)  
Outside North America 1.514.982.8717 (English and French)
Shareholder account matters
For information regarding your shareholdings or to change your 
address, transfer shares, eliminate duplicate mailings, directly 
deposit dividends, etc., please contact Computershare Investor 
Services Inc. If your shares are held by a broker, please contact 
your broker.
Stock exchanges
Cenovus common shares trade on the Toronto Stock Exchange 
(TSX) and the New York Stock Exchange (NYSE) under the symbol 
CVE. Cenovus warrants trade on the TSX and the NYSE under 
the symbols TSX: CVE.WT and NYSE: CVE.WS. Cenovus preferred 
shares Series 1, Series 2, Series 5 and Series 7 trade on the TSX 
under the symbols CVE.PR.A, CVE.PR.B, CVE.PR.E and CVE.PR.G.
Annual Information Form/Form 40‑F
Our Annual Information Form is filed with the Canadian Securities 
Administrators in Canada on SEDAR+ at sedarplus.ca and 
with the U.S. Securities and Exchange Commission under the 
Multi‑Jurisdictional Disclosure System as an Annual Report on 
Form 40‑F on EDGAR at sec.gov.
NYSE corporate governance standards
As a Canadian company listed on the NYSE, we are not required 
to comply with most of the NYSE corporate governance 
standards and instead may comply with Canadian corporate 
governance requirements. We are, however, required to disclose 
the significant differences between our corporate governance 
practices and those required to be followed by U.S. domestic 
companies under the NYSE corporate governance standards. 
Except as summarized on https://www.cenovus.com/Our-
company/Governance, we are in compliance with the NYSE 
corporate governance standards in all significant respects.
Investor Relations
Please visit the Investors section at cenovus.com for  
investor information. 
Investor inquiries should be directed to:  
403.766.7711, investor.relations@cenovus.com
Media inquiries should be directed to: 
403.766.7751, media.relations@cenovus.com
Cenovus head office
Cenovus Energy Inc. 
225 6 Avenue SW 
PO Box 766 
Calgary, Alberta T2P 0M5 Canada 
Phone: 403.766.2000 
cenovus.com
Cenovus’s Leadership Team
(as at March 12, 2025)
Alex Pourbaix, Executive Chair 
Jon McKenzie, President & Chief Executive Officer
Susan Anderson, SVP, Legal, General Counsel & Corporate Secretary
Andrew Dahlin, EVP & Chief Operating Officer
Jeff Lawson, EVP, Corporate Development &  
Chief Sustainability Officer
Geoff Murray, EVP, Commercial
Candace Newman, SVP, People Services
Kam Sandhar, EVP & Chief Financial Officer
John Soini, EVP, Upstream – Thermal & Atlantic Offshore
Eric Zimpfer, Head of Downstream
Cenovus’s Board of Directors
(as at March 12, 2025)
Alex Pourbaix, Executive Chair, Calgary, Alberta (5) 
Claude Mongeau, Lead Independent Director, Montréal, Québec (1,2)
Stephen E. Bradley, Smerillo, Italy (1,4)
Keith M. Casey, San Antonio, Texas (3,4)
Michael J. Crothers, Calgary, Alberta (2,3)
James D. Girgulis, Luxembourg, Grand-Duchy of Luxembourg (4,6)
Jane E. Kinney, Toronto, Ontario (1,4)
Eva L. Kwok, Vancouver, British Columbia (2)
Melanie A. Little, Alpharetta, Georgia (3,4)
Richard J. Marcogliese, Alamo, California (1,4)
Jon McKenzie, Calgary, Alberta (5)
Frank J. Sixt, Hong Kong Special Administrative Region (2)
Rhonda I. Zygocki, Friday Harbor, Washington (2,3)
(1) Member of the Audit Committee. 
(2) Member of the Governance Committee. 
(3) Member of the Human Resources and Compensation Committee.  
(4) Member of the Safety, Sustainability and Reserves Committee. 
(5) As officers and non-independent directors, Messrs. McKenzie and Pourbaix are not 
members of any of the committees of Cenovus’s Board.
(6) Non-independent director.
Information for shareholders

CENOVUS ENERGY INC. 
Cenovus Energy Inc. is an integrated energy company 
with oil and natural gas production operations in 
Canada and the Asia Pacific region, and upgrading, 
refining and marketing operations in Canada and the 
United States. The company is focused on managing 
its assets in a safe, innovative and cost‑efficient 
manner, integrating environmental, social and 
governance considerations into its business plans. 
Cenovus common shares and warrants are listed on 
the Toronto and New York stock exchanges, and the 
company’s preferred shares are listed on the Toronto 
Stock Exchange. 
 
For more information, visit cenovus.com.
© Cenovus Energy Inc. 2025
1.877.766.2066  
(Toll‑free in Canada & U.S.)
225 6 Ave SW PO Box 766 
Calgary, AB T2P 0M5 Canada