6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 

under the Securities Exchange Act of 1934

For November 2023

Commission File Number:  1-34513

CENOVUS ENERGY INC.

(Translation of registrant’s name into English)

4100, 225 6 Avenue S.W.

Calgary, Alberta, Canada T2P 1N2

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F  ☐    Form 40-F  ☒

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):   ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):   ☐

Exhibit 99.2 and 99.3 to this report, furnished on Form 6-K, shall be incorporated by reference into or as an exhibit to, as applicable, each of the registrant’s Registration Statements under the Securities Act of 1933, as amended: Form F-10 (File No. 333-259814), Form S-8 (File Nos. 333-163397 and 333-251886), Form F-3D (File No. 333-202165).

DOCUMENTS FILED AS PART OF THIS FORM 6-K

See the Exhibit Index to this Form 6-K.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:  November 2, 2023

CENOVUS ENERGY INC.

(Registrant)

By:	/s/ Christine D. Lee
	Name:	Christine D. Lee
	Title:	Assistant Corporate Secretary

Form 6-K Exhibit Index

Exhibit No.
99.1	News Release dated November 2, 2023
99.2	Management’s Discussion and Analysis dated November 1, 2023 for the period ended September 30, 2023
99.3	Interim Consolidated Financial Statements (unaudited) for the period ended September 30, 2023
99.4	Form 52-109F2 Full Certificate, dated November 2, 2023, of Jonathan M. McKenzie, President & Chief Executive Officer
99.5	Form 52-109F2 Full Certificate, dated November 2, 2023, of Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer

EX-99.1

	Exhibit 99.1
News release

Cenovus announces 2023 third-quarter results

Calgary, Alberta (November 2, 2023) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) delivered safe, reliable operations and strong financial performance in the third quarter of 2023. The company generated $2.7 billion in cash from operating activities, $3.4 billion in adjusted funds flow and $2.4 billion in free funds flow in the quarter. Total upstream production was 797,000 barrels of oil equivalent per day (BOE/d)1 and downstream throughput averaged over 664,000 barrels per day (bbls/d).

“We were pleased with the improved results that our assets and integrated business produced over the quarter,” said Jon McKenzie, Cenovus President & Chief Executive Officer. “The strong operating performance at our assets, combined with a supportive commodity price environment drove significantly higher financial results compared with the previous quarter.”

Highlights

•Delivered $1.2 billion to shareholders, including $600 million for the partial payment of the common share warrants obligation, $361 million in share buybacks and $264 million through common share dividends.

•Increased U.S. Manufacturing crude oil throughput 26% to 555,900 bbls/d from the second quarter.

•Reduced long-term debt, including current portion, by US$1.0 billion, to $7.2 billion and net debt to $6.0 billion at the end of the quarter.

•Received Board of Directors approval to file an application with the TSX to renew Cenovus’s normal course issuer bid (NCIB) for another year.

Financial, production & throughput summary
(For the period ended September 30)	2023 Q3	2023 Q2	% change	2022 Q3	% change
Financial ($ millions, except per share amounts)
Cash from (used in) operating activities	2,738	1,990	38	4,089	(33)
Adjusted funds flow2	3,447	1,899	82	2,951	17
Per share (basic)2	1.82	1.00		1.53
Per share (diluted)2	1.81	0.98		1.49
Capital investment	1,025	1,002	2	866	18
Free funds flow2	2,422	897	170	2,085	16
Excess free funds flow2	1,989	505	294	1,756	13
Net earnings (loss)	1,864	866	115	1,609	16
Per share (basic)	0.98	0.45		0.83
Per share (diluted)	0.97	0.44		0.81
Long-term debt, including current portion	7,224	8,534	(15)	8,774	(18)
Net debt	5,976	6,367	(6)	5,280	13
Production and throughput (before royalties, net to Cenovus)
Oil and NGLs (bbls/d)1	652,400	608,400	7	633,100	3
Conventional natural gas (MMcf/d)	867.4	729.4	19	868.7
Total upstream production (BOE/d)1	797,000	729,900	9	777,900	2
Total downstream throughput (bbls/d)	664,300	537,800	24	533,500	25

1See Advisory for production by product type.

2 Non-GAAP financial measure or contains a non-GAAP financial measure. See Advisory.

CENOVUS ENERGY NEWS RELEASE | 1

Third-quarter results

Operatingresults1

Cenovus’s total revenues were approximately $14.6 billion in the third quarter, up from $12.2 billion in the second quarter of 2023. Upstream revenues were about $7.6 billion, an increase from $6.6 billion in the previous quarter, and downstream revenues were approximately $9.7 billion, compared with $7.4 billion in the second quarter of 2023. Total operating margin3 was about $4.4 billion, compared with $2.4 billion in the second quarter. Upstream operating margin4 was approximately $3.4 billion, an increase from $2.3 billion in the previous quarter, primarily driven by higher Brent and West Texas Intermediate (WTI) crude oil prices, a tighter light-heavy differential as well as higher production and sales volumes. Downstream operating margin4 was $922 million, compared with $143 million in the second quarter, primarily due to higher refined product volumes as the Toledo Refinery achieved 90% utilization in the quarter, and an increase in refined product pricing. In addition, U.S. Manufacturing operating margin was positively impacted by approximately $400 million due to the cost of processing crude oil purchased in prior periods at lower prices.

Total upstream production was 797,000 BOE/d in the third quarter, an increase of 9% from the second quarter as the company restarted production that had been offline due to Alberta wildfires and planned maintenance activity. Foster Creek volumes increased to 189,300 bbls/d, from 167,000 bbls/d in the second quarter, reflecting production from new well pads and the completion of planned maintenance in the second quarter. Christina Lake production was 237,600 bbls/d, in line with the second quarter. Sunrise output was 54,500 bbls/d, an increase of 17% compared with the second quarter as the company completed its 2023 redevelopment program. At the Lloydminster thermal projects, production of 104,600 bbls/d was in line with the prior quarter, as the company continued to focus on optimization of the asset.

Production in the Conventional segment increased to 127,200 BOE/d in the third quarter, compared with 104,600 BOE/d in the second quarter, as the company resumed normal operations after shutting in several fields and processing plants in response to wildfire activity in Alberta during May and June. Most of the Conventional asset outages were resolved by the end of August.

In the Offshore segment, production was 66,400 BOE/d compared with 51,500 BOE/d in the previous quarter. In Asia Pacific, sales volumes increased compared with the second quarter, which was impacted by a temporary unplanned outage in China. In Indonesia, the company achieved first gas production from the MAC field in September. In the Atlantic region, production was 8,900 bbls/d compared with 5,300 bbls/d in the prior quarter, which was impacted by planned maintenance. During the third quarter, the non-operated Terra Nova floating production, storage and offloading (FPSO) vessel returned to offshore Newfoundland and Labrador and commissioning activities are ongoing with production expected to resume in the fourth quarter.

In U.S. Manufacturing, crude utilization was 88% in the third quarter, with throughput of 555,900 bbls/d, compared with 70% and 442,500 bbls/d in the second quarter. The Toledo Refinery performed well following its restart in the second quarter, and at the Superior Refinery, the full and stable start-up of the fluid catalytic cracking unit was achieved in early October after operational challenges in the second quarter.

Crude utilization in the Canadian Manufacturing segment was 98% with throughput of 108,400 bbls/d in the third quarter, compared with crude utilization and throughput of 86% and 95,300 bbls/d in the second quarter. Both the Lloydminster Upgrader and Lloydminster Refinery operated at or near full

capacity, with utilization rates of 99% and 96%, respectively.

3Non-GAAP financial measure. Total operating margin is the total of Upstream operating margin plus Downstream operating margin. See Advisory.

4 Specified financial measure. See Advisory.     

CENOVUS ENERGY NEWS RELEASE | 2

Financial results

Third-quarter cash from operating activities, which includes changes in non-cash working capital, was about $2.7 billion, compared with $2.0 billion in the second quarter of 2023. Adjusted funds flow was approximately $3.4 billion, compared with $1.9 billion in the prior period, and free funds flow increased to about $2.4 billion from $897 million in the second quarter. Third-quarter financial results improved compared with the second quarter, primarily due to higher price realizations in the Oil Sands segment, driven by narrower light-heavy crude oil differentials and the timing of condensate cost recognition, as well as higher refined product volumes in the downstream business and an increase in refined product pricing. These factors were partially offset by higher cash taxes and royalties, and Oil Sands segment sales volumes lagging production by approximately 6,000 BOE/d in the quarter.

Capital investment of $1.0 billion in the third quarter was primarily directed towards sustaining production in the Oil Sands segment, drilling, completion, tie-in, and infrastructure projects in the Conventional business as well as refining reliability initiatives in the U.S. Manufacturing segment. In addition, the company continues to progress growth and optimization projects. These include the construction of the West White Rose project, including preparation for the asset life extension project at the SeaRose FPSO, which will commence in January 2024, the tie-back of Narrows Lake to Christina Lake, Sunrise optimization and Foster Creek expansion.

Net earnings in the third quarter were almost $1.9 billion, compared with $866 million in the previous quarter. The increase in net earnings was primarily due to higher operating margin and lower financing costs. These factors were partially offset by higher income taxes, an unrealized foreign exchange loss compared with an unrealized gain in the second quarter, and higher general and administrative expenses due to long-term incentive costs.

Long-term debt, including the current portion, was $7.2 billion at September 30, 2023, compared with $8.5 billion at June 30, 2023. The reduction of long-term debt in the quarter was primarily due to the company’s purchase of US$1.0 billion of outstanding notes that were due between 2029 and 2047. Net debt was approximately $6.0 billion at September 30, 2023, a decrease from $6.4 billion at June 30, 2023, primarily due to free funds flow of $2.4 billion in the third quarter, partially offset by a working capital build. In the third quarter, the company built working capital, primarily due to an increase in accounts receivable and inventories and the partial payment of the common share warrants obligation. Cenovus continues to focus on making progress towards its net debt target of $4.0 billion.

CENOVUS ENERGY NEWS RELEASE | 3

Dividend declarations and share purchases

The Board of Directors has declared a quarterly base dividend of $0.14 per common share, payable on December 29, 2023 to shareholders of record as of December 15, 2023. In addition, the Board has declared a quarterly dividend on each of the Cumulative Redeemable First Preferred Shares – Series 1, Series 2, Series 3, Series 5 and Series 7 – payable on January 2, 2024 to shareholders of record as of December 15, 2023 as follows:

Preferred shares dividend summary
Share series	Rate (%)	Amount ($/share)
Series 1	2.577	0.16106
Series 2	6.887	0.43398
Series 3	4.689	0.29306
Series 5	4.591	0.28694
Series 7	3.935	0.24594

All dividends paid on Cenovus’s common and preferred shares will be designated as “eligible dividends” for Canadian federal income tax purposes. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis.

Cenovus’s shareholder returns framework has a target of returning 50% of excess free funds flow to shareholders for quarters where the ending net debt is between $9.0 billion and $4.0 billion. In the third quarter, the company returned $1.2 billion to shareholders composed of $600 million for the partial payment of the common share warrants obligation, the purchase of 13.8 million shares for $361 million through its NCIB and $264 million through common share base dividends.

Since the share buyback program began in November 2021, Cenovus has purchased approximately 162 million common shares, delivering $3.6 billion in returns to shareholders. The current NCIB will expire on November 8, 2023. Cenovus has received approval from the Board of Directors to make an application for another NCIB program. The company will apply for approval to repurchase up to approximately 133 million of the company’s common shares, representing approximately 10% of its public float, as defined by the TSX.

2023 planned maintenance

The following table provides details on planned maintenance activities at Cenovus assets through the remainder of 2023 and anticipated production or throughput impacts.

2023 planned maintenance
Potential quarterly production/throughput impact (Mbbls/d)
	Q4
Downstream
U.S. Manufacturing	55 - 65

Board renewal

Cenovus is pleased to announce that Michael J. Crothers and James D. Girgulis have been appointed to Cenovus’s Board of Directors, effective immediately.

Crothers has over 37 years of operations, commercial and leadership experience in the upstream, downstream and integrated gas businesses, including 34 years with Shell plc, most recently as President

CENOVUS ENERGY NEWS RELEASE | 4

and Country Chair for Shell Canada Ltd. He is currently a member of the Board of Keyera Corp., a publicly traded integrated energy infrastructure company.

Girgulis is currently Managing Director of Hutchison Whampoa Europe Investments S.à r.l., a private investment company, and Managing Director of CK Hutchison Group Telecom Finance S.A., a public limited company. From April 2021 to March 2022, he was Special Advisor to the Executive at Cenovus following the company’s combination with Husky Energy Inc. Prior to that, he held progressively responsible positions with Husky, ultimately serving as Senior Vice-President, General Counsel & Secretary from April 2012 to March 2021.

In accordance with the standstill agreements entered into at the time of the Husky transaction, Girgulis was nominated to replace Canning Fok, who retired from the Cenovus Board effective July 26, 2023.

“We’re extremely pleased to have Michael and James, who each bring extensive oil and gas industry experience, join our Board,” said Alex Pourbaix, Cenovus Executive Chair of the Board. “These appointments support the company's ongoing Board renewal process, which focuses on orderly succession of directors, while maintaining an appropriate balance and diversity of skills, experience and perspectives on the Board.”

Conference call today

8 a.m. Mountain Time (10 a.m. Eastern Time)

Cenovus will host a conference call today, November 2, 2023, starting at 8 a.m. MT (10 a.m. ET).

To join the conference call without operator assistance, please register here approximately 5 minutes in advance to receive an automated call-back when the session begins.

Alternatively, you can dial 888-664-6383 (toll-free in North America) or 416-764-8650 to reach a live operator who will join you into the call. A live audio webcast will also be available and will be archived for approximately 90 days.

Advisory

Basis of Presentation

Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS).

Barrels of Oil Equivalent

Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

CENOVUS ENERGY NEWS RELEASE | 5

Product types

Product type by operating segment
	Three months ended September 30, 2023
Oil Sands
Bitumen (Mbbls/d)	586.0
Heavy crude oil (Mbbls/d)	15.6
Conventional natural gas (MMcf/d)	10.6
Total Oil Sands segment production (MBOE/d)	603.4
Conventional
Light crude oil (Mbbls/d)	6.3
Natural gas liquids (Mbbls/d)	23.9
Conventional natural gas (MMcf/d)	582.1
Total Conventional segment production (MBOE/d)	127.2
Offshore
Light crude oil (Mbbls/d)	8.9
Natural gas liquids (Mbbls/d)	11.7
Conventional natural gas (MMcf/d)	274.7
Total Offshore segment production (MBOE/d)	66.4
Total upstream production (MBOE/d)	797.0

Forward‐looking Information

This news release contains certain forward‐looking statements and forward‐looking information (collectively referred to as “forward‐looking information”) within the meaning of applicable securities legislation about Cenovus’s current expectations, estimates and projections about the future of the company, based on certain assumptions made in light of the company’s experiences and perceptions of historical trends. Although Cenovus believes that the expectations represented by such forward‐looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward‐looking information in this document is identified by words such as “anticipate”, “continue”, “deliver”, “focus”, “progress”, and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: performance for the rest of 2023 and beyond; achieving net debt of $4.0 billion; excess free funds flow under the shareholder returns framework; generating value for shareholders; applying for an NCIB; progressing growth and optimization projects; commissioning the Terra Nova floating production, storage and offloading unit to resume production at the Terra Nova Field in the fourth quarter of 2023; planned turnaround activities; dividend payments; and Cenovus’s 2023 corporate guidance.

Developing forward‐looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward‐looking information in this news release are based include, but are not limited to: the allocation of free funds flow to reducing net debt; commodity prices, inflation and supply chain constraints; Cenovus’s ability to produce on an unconstrained basis; Cenovus’s ability to access sufficient insurance coverage to pursue development plans; Cenovus’s ability to deliver safe and reliable operations and demonstrate strong governance; and the assumptions inherent in Cenovus’s 2023 Guidance available on cenovus.com.

CENOVUS ENERGY NEWS RELEASE | 6

The risk factors and uncertainties that could cause actual results to differ materially from the forward‐looking information in this news release include, but are not limited to: the accuracy of estimates regarding commodity production and operating expenses, inflation, taxes, royalties, capital costs and currency and interest rates; risks inherent in the operation of Cenovus’s business; and risks associated with climate change and Cenovus’s assumptions relating thereto and other risks identified under “Risk Management and Risk Factors” and “Advisory” in Cenovus’s Management’s Discussion and Analysis (MD&A) for the year ended December 31, 2022.

Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward‐looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward‐looking information. For additional information regarding Cenovus’s material risk factors, the assumptions made, and risks and uncertainties which could cause actual results to differ from the anticipated results, refer to “Risk Management and Risk Factors” and “Advisory” in Cenovus’s MD&A for the periods ended December 31, 2022 and September 30, 2023, and to the risk factors, assumptions and uncertainties described in other documents Cenovus files from time to time with securities regulatory authorities in Canada (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus’s website at cenovus.com).

Specified Financial Measures

This news release contains references to certain specified financial measures that do not have standardized meanings prescribed by IFRS. Readers should not consider these measures in isolation or as a substitute for analysis of the company’s results as reported under IFRS. These measures are defined differently by different companies and, therefore, might not be comparable to similar measures presented by other issuers. For information on the composition of these measures, as well as an explanation of how the company uses these measures, refer to the Specified Financial Measures Advisory located in Cenovus’s MD&A for the period ended September 30, 2023 (available on SEDAR at sedar.com, on EDGAR at sec.gov and on Cenovus's website at cenovus.com) which is incorporated by reference into this news release.

Upstream Operating Margin and Downstream Operating Margin

Upstream Operating Margin and Downstream Operating Margin, and the individual components thereof, are included in Note 1 to the interim Consolidated Financial Statements.

CENOVUS ENERGY NEWS RELEASE | 7

Total Operating Margin

Total Operating Margin is the total of Upstream Operating Margin plus Downstream Operating Margin.

	Upstream (1)			Downstream (1)			Total
($ millions)	Q3 2023	Q2 2023	Q3 2022	Q3 2023	Q2 2023	Q3 2022	Q3 2023	Q2 2023	Q3 2022
Revenues
Gross Sales	8,783	7,285	10,250	9,658	7,427	10,873	18,441	14,712	21,123
Less: Royalties	1,135	637	1,226	—	—	—	1,135	637	1,226
	7,648	6,648	9,024	9,658	7,427	10,873	17,306	14,075	19,897
Expenses
Purchased Product	900	751	2,383	7,947	6,447	9,680	8,847	7,198	12,063
Transportation and Blending	2,397	2,770	2,826	—	—	—	2,397	2,770	2,826
Operating	914	883	915	778	843	780	1,692	1,726	1,695
Realized (Gain) Loss on Risk Management	(10)	(13)	51	11	(6)	(77)	1	(19)	(26)
Operating Margin	3,447	2,257	2,849	922	143	490	4,369	2,400	3,339

(1) Foundin the September 30, 2023, interim Consolidated Financial Statements or in the Prior Period Revisions Advisory located in our Management's Discussion and Analysis for the periods ended September 30, 2023.

Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow

The following table provides a reconciliation of cash from (used in) operating activities found in Cenovus’s Consolidated Financial Statements to Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow. Adjusted Funds Flow per Share – Basic and Adjusted Funds Flow per Share – Diluted are calculated by dividing Adjusted Funds Flow by the respective basic or diluted weighted average number of common shares outstanding during the period and may be useful to evaluate a company’s ability to generate cash.

	Three Months Ended
($ millions)	September 30, 2023	June 30, 2023	September 30, 2022
Cash From (Used in) Operating Activities (1)	2,738	1,990	4,089
(Add) Deduct:
Settlement of Decommissioning Liabilities	(68)	(41)	(55)
Net Change in Non-Cash Working Capital	(641)	132	1,193
Adjusted Funds Flow	3,447	1,899	2,951
Capital Investment	1,025	1,002	866
Free Funds Flow	2,422	897	2,085
Add (Deduct):
Base Dividends Paid on Common Shares	(264)	(265)	(205)
Dividends Paid on Preferred Shares	—	(9)	(9)
Settlement of Decommissioning Liabilities	(68)	(41)	(55)
Principal Repayment of Leases	(70)	(76)	(78)
Acquisitions, Net of Cash Acquired	(32)	(4)	(389)
Proceeds From Divestitures	1	3	407
	1,989	505	1,756

(1) Found in the September 30, 2023, or the June 30, 2023, interim Consolidated Financial Statements.

Cenovus Energy Inc.

Cenovus Energy Inc. is an integrated energy company with oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States. The company is focused on managing its assets in a safe, innovative and cost-efficient manner, integrating environmental, social and governance considerations into its business plans.

CENOVUS ENERGY NEWS RELEASE | 8

Cenovus common shares and warrants are listed on the Toronto and New York stock exchanges, and the company’s preferred shares are listed on the Toronto Stock Exchange. For more information, visit cenovus.com.

Find Cenovus on Facebook, X, LinkedIn, YouTube and Instagram.

Cenovus contacts

Investors	Media
Investor Relations general line 403-766-7711	Media Relations general line 403-766-7751

CENOVUS ENERGY NEWS RELEASE | 9

EX-99.2

Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Periods Ended September 30, 2023

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the periods ended September 30, 2023

OVERVIEW OF CENOVUS	3
QUARTERLY RESULTS OVERVIEW	5
OPERATING AND FINANCIAL RESULTS	7
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	14
OUTLOOK	17
REPORTABLE SEGMENTS	18
UPSTREAM	18
OIL SANDS	18
CONVENTIONAL	24
OFFSHORE	27
DOWNSTREAM	32
CANADIAN MANUFACTURING	32
U.S. MANUFACTURING	35
CORPORATE AND ELIMINATIONS	38
LIQUIDITY AND CAPITAL RESOURCES	40
RISK MANAGEMENT AND RISK FACTORS	46
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	46
CONTROL ENVIRONMENT	47
ADVISORY	47
ABBREVIATIONS	50
SPECIFIED FINANCIAL MEASURES	51
PRIOR PERIOD REVISIONS	64

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, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated November 1, 2023, should be read in conjunction with our September 30, 2023 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2022 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2022 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of November 1, 2023, 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 November 1, 2023. 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, does not constitute part of this MD&A.

Basis of Presentation

This MD&A and the interim Consolidated Financial Statements were prepared in Canadian dollars, (which includes references to “dollar” or “$”), except where another currency was indicated, and in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board. Production volumes are presented on a before royalties basis. Refer to the Abbreviations section for commonly used oil and gas terms.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis 2

OVERVIEW OF CENOVUS

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

Our upstream operations include oil sands projects in northern Alberta; thermal and conventional crude oil, natural gas and natural gas liquids (“NGLs”) projects across Western Canada; crude oil production offshore Newfoundland and Labrador; and natural gas and NGLs production offshore China and Indonesia. Our downstream operations include upgrading and refining operations in Canada and the U.S., and commercial fuel operations across Canada.

Our operations involve activities across the full value chain to develop, produce, refine, transport and market crude oil, natural gas and refined petroleum products in Canada and internationally. Our physically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil differentials and contribute to our net earnings by capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels.

Our Strategy and Key Priorities for 2023

At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value through competitive cost structures and optimizing margins, while delivering top-tier safety performance and sustainability leadership. The Company prioritizes Free Funds Flow generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and common share purchases, reinvest in our business and diversify our portfolio. On December 6, 2022, we released our 2023 budget. Our 2023 guidance dated July 26, 2023, is available on our website at cenovus.com. For further details see the Operating and Financial Results section of this MD&A.

In 2023, we are delivering on our strategy through five key objectives.

Top-Tier Safety and Operational Performance

Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, including top-tier health and safety performance.

We continue to target improved operating performance including the safe return of the Superior Refinery to full operations and integration of the Toledo Refinery with a focus on demonstrating consistent and reliable performance at all of our operated assets.

Sustainability Leadership

Sustainability has always been deeply engrained in Cenovus’s culture. We have established ambitious targets in our five environmental, social and governance (“ESG”) focus areas and continue to progress tangible plans to meet these targets. Our five ESG focus areas are:

•Climate & GHG emissions.

•Water stewardship.

•Biodiversity.

•Indigenous reconciliation.

•Inclusion & diversity.

Additional information on Cenovus’s efforts and performance across the ESG focus areas, including our ESG targets and plans to achieve them, are available in Cenovus’s 2022 ESG report on our website at cenovus.com.

Cost Leadership

We aim to maximize shareholder value through competitive cost structures and optimized margins. While we strive to optimize our cost structure in all areas of our business, one of our focus areas is to optimize infrastructure, reduce operating and capital costs, and reduce GHG emissions at our conventional assets.

Financial Discipline and Free Funds Flow Growth

We are focused on achieving and maintaining targeted debt levels while positioning Cenovus for resiliency through all commodity price cycles. We continue to deliver meaningful returns to shareholders in alignment with our financial and shareholder returns framework.

Returns-Focused Capital Allocation

We continue to take a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle and provide opportunities to sustainably grow shareholder returns.

We have materially progressed the West White Rose project to deliver first oil in 2026.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  3

Our Operations

The Company operates through the following reportable segments:

Upstream Segments

•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

•Conventional, includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and 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 China and the east coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

•Canadian Manufacturing, 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. Manufacturing, 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, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel, jet fuel and asphalt.

Corporate and Eliminations

Corporate and Eliminations, primarily 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 internal usage of natural gas and condensate production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on market prices.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  4

QUARTERLY RESULTS OVERVIEW

The third quarter was highlighted by a number of operational milestones, solid operating performance across our assets and an improved commodity price environment from the second quarter, resulting in strong financial results.

•Executed on our number one priority. We delivered safe operations across our integrated upstream and downstream business and strive to continuously improve our safety record.

•Delivered strong upstream performance. Upstream production averaged 797.0 thousand BOE per day, compared with 729.9 thousand BOE per day in the second quarter. We substantially returned to full operations in the Conventional segment following significant wildfire activity in the second quarter. In the Oil Sands segment, we delivered reliable operations following planned turnaround activity in the second quarter, with production starting on two new well pads at Foster Creek and completing the ramp up of three new well pads at Foster Creek and Christina Lake. In the Offshore segment, we delivered reliable operations following planned turnaround activity in the Atlantic region and an unplanned outage in China in the second quarter.

•Achieved Offshore milestones. The West White Rose project is progressing well with construction approximately 75 percent complete. The Terra Nova floating production, storage and offloading unit (“FPSO”) returned to the field in August. Commissioning activities are ongoing with production expected to resume in the fourth quarter. In addition, we achieved first gas production from the MAC field in Indonesia.

•Well positioned in our downstream operated assets. Crude oil unit throughput (or “throughput”) was 664.3 thousand barrels per day in the quarter, an increase of 126.5 thousand barrels per day from the second quarter. The Toledo Refinery performed well following a safe restart in the second quarter. At the Superior Refinery, the start-up of the fluid catalytic cracking unit (“FCCU”) was achieved in early October. Crude utilization in the U.S Manufacturing segment was 88 percent (second quarter – 70 percent). In the Canadian Manufacturing segment, we achieved crude utilization of 98 percent (second quarter – 86 percent). We are well positioned to optimize our integrated network of assets and the heavy oil value chain between our upstream and downstream operations.

•Improved commodity price environment. Global crude oil benchmarks strengthened from the second quarter while at the same time the WTI-WCS at Hardisty differential narrowed 14 percent to US$12.91 per barrel. WCS at Hardisty averaged US$69.35 per barrel, an increase from US$58.74 per barrel in the second quarter. Condensate pricing rose from the second quarter; however, not to the same degree as crude oil benchmarks. Benchmark refined product pricing improved from the second quarter, with diesel pricing increasing 11 percent to US$113.77 per barrel and gasoline pricing increasing three percent to US$105.59 per barrel. Feedstock purchased at lower prices in the second quarter positively impacted our U.S. refining margins in the third quarter.

•Solid financial results. Cash flow from operating activities was $2.7 billion, an increase from $2.0 billion in the second quarter. Adjusted funds flow was $3.4 billion (second quarter – $1.9 billion) mainly due to an improved commodity price environment and the strong operating results discussed above.

•Reduced long-term debt. We purchased US$1.0 billion of long-term debt in the third quarter at a discount of $84 million. Net Debt decreased $391 million to $6.0 billion at September 30, 2023, as we move towards our $4 billion Net Debt target. The decrease was driven by strong financial results, partially offset by shareholder returns and an increase in working capital due primarily to rising commodity prices.

•Delivered significant cash returns to shareholders. We returned $1.2 billion to shareholders, composed of $600 million for the partial payment of our common share warrants obligation (“Cenovus Warrants”), the purchase of 13.8 million common shares for $361 million through our NCIB, and $264 million through common share base dividends. On November 1, 2023, the Board declared a fourth quarter base dividend of $0.140 per common share and dividends for our preferred shares of $9 million.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  5

Summary of Quarterly Results

	Nine Months Ended September 30,		2023			2022				2021
($ millions, except where indicated)	2023	2022	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Upstream Production Volumes (1)(MBOE/d)	768.7	779.2	797.0	729.9	779.0	806.9	777.9	761.5	798.6	825.3	804.8
Downstream Crude Oil Unit Throughput (2)    (Mbbls/d)	554.1	497.8	664.3	537.8	457.9	473.3	533.5	457.3	501.8	469.9	554.1
Downstream Production Volumes (Mbbls/d)	589.8	530.9	706.0	571.9	487.7	506.3	572.6	482.1	538.0	503.4	590.9
Revenues	39,070	52,834	14,577	12,231	12,262	14,063	17,471	19,165	16,198	13,726	12,701
Operating Margin (3)	8,871	11,481	4,369	2,400	2,102	2,782	3,339	4,678	3,464	2,600	2,710
Cash From (Used In) Operating Activities	4,442	8,433	2,738	1,990	(286)	2,970	4,089	2,979	1,365	2,184	2,138
Adjusted Funds Flow (3)	6,741	8,632	3,447	1,899	1,395	2,346	2,951	3,098	2,583	1,948	2,342
Per Share - Basic (3) ($)	3.55	4.40	1.82	1.00	0.73	1.22	1.53	1.57	1.30	0.97	1.16
Per Share - Diluted (3)($)	3.48	4.28	1.81	0.98	0.71	1.19	1.49	1.53	1.27	0.97	1.15
Capital Investment	3,128	2,434	1,025	1,002	1,101	1,274	866	822	746	835	647
Free Funds Flow (3)	3,613	6,198	2,422	897	294	1,072	2,085	2,276	1,837	1,113	1,695
Excess Free Funds Flow (3)	n/a	n/a	1,989	505	(499)	786	1,756	2,020	2,615	1,169	1,626
Net Earnings (Loss)(4)	3,366	5,666	1,864	866	636	784	1,609	2,432	1,625	(408)	551
Per Share - Basic ($)	1.76	2.87	0.98	0.45	0.33	0.40	0.83	1.23	0.81	(0.21)	0.27
Per Share - Diluted ($)	1.72	2.79	0.97	0.44	0.32	0.39	0.81	1.19	0.79	(0.21)	0.27
Total Assets	54,427	55,086	54,427	53,747	54,000	55,869	55,086	55,894	55,655	54,104	54,594
Total Long-Term Liabilities	18,395	19,378	18,395	19,831	19,917	20,259	19,378	20,742	21,889	23,191	22,929
Long-Term Debt, Including Current Portion	7,224	8,774	7,224	8,534	8,681	8,691	8,774	11,228	11,744	12,385	12,986
Net Debt	5,976	5,280	5,976	6,367	6,632	4,282	5,280	7,535	8,407	9,591	11,024
Cash Returns to Shareholders	2,067	2,650	1,225	584	258	807	873	1,233	544	343	44
Common Shares – Base Dividends	729	481	264	265	200	201	205	207	69	70	35
Base Dividends Per Common Share($)	0.385	0.245	0.140	0.140	0.105	0.105	0.105	0.105	0.035	0.035	0.018
Common Shares – Variable Dividends	—	—	—	—	—	219	—	—	—	—	—
Variable Dividends Per Common Share($)	—	—	—	—	—	0.114	—	—	—	—	—
Purchase of Common Shares Under NCIB	711	2,143	361	310	40	387	659	1,018	466	265	—
Payment for Purchase of Warrants	600	—	600	—	—	—	—	—	—	—	—
Preferred Share Dividends	27	26	—	9	18	—	9	8	9	8	9

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

(4)Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  6

OPERATING AND FINANCIAL RESULTS

Selected Operating Results — Upstream

	Three Months Ended September 30,			Nine Months Ended September 30,
		Percent Change			Percent Change
	2023		2022	2023		2022
Upstream Production Volumes by Segment (1) (MBOE/d)
Oil Sands	603.4	3	587.1	589.0	1	580.9
Conventional (2)	127.2	1	126.2	118.5	(7)	128.0
Offshore	66.4	3	64.6	61.2	(13)	70.3
Total Production Volumes	797.0	2	777.9	768.7	(1)	779.2
Upstream Production Volumes by Product
Bitumen (Mbbls/d)	586.0	3	568.2	570.6	1	562.4
Heavy Crude Oil (Mbbls/d)	15.6	(7)	16.8	16.5	—	16.5
Light Crude Oil (Mbbls/d)	15.2	(5)	16.0	13.5	(32)	19.8
NGLs (Mbbls/d)	35.6	11	32.1	31.9	(10)	35.4
Conventional Natural Gas (MMcf/d)	867.4	—	868.7	818.1	(6)	870.9
Total Production Volumes (MBOE/d)	797.0	2	777.9	768.7	(1)	779.2

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

(2)All natural gas produced by the Conventional segment is internally consumed by the Oil Sands and Canadian Manufacturing segments.

Total upstream production increased 19.1 thousand BOE per day in the third quarter of 2023 compared with 2022 due to:

•The acquisition of the remaining 50 percent interest in the Sunrise Oil Sands Partnership (“Sunrise” or the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“bp Canada”) on August 31, 2022, and successful results from the 2023 redevelopment program.

•The impact of well pads brought online at Foster Creek in the second and third quarters of 2023, combined with planned maintenance and an unplanned outage in 2022.

•First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022.

•First oil at the Spruce Lake North thermal plant late in the third quarter of 2022.

The increase was partially offset by lower production at Christina Lake due to flush production following a planned turnaround in the second quarter of 2022, and the timing of new well pads in 2023.

Production decreased 10.5 thousand BOE per day in the first nine months of 2023 compared with 2022 due to:

•The temporary shut-in of a significant portion of production in our Conventional operations in response to wildfire activity in the second quarter of 2023.

•Changes to the Liwan 3-1 gas sales agreement in China in the second quarter of 2022, concluding the amendment that temporarily increased sales volumes.

•A temporary unplanned outage in China in the second quarter of 2023, related to the disconnection of the umbilical cord by a third-party vessel in early April, reconnected in May.

•Lower production at Christina Lake as discussed above, partially offset by turnaround activity in the second quarter of 2022.

•Decreased production at Foster Creek due to a planned turnaround in the second quarter of 2023 having a greater impact than the 2022 planned maintenance and unplanned outage.

The decrease was partially offset by the same factors impacting the third quarter of 2023.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  7

Selected Operating Results — Downstream

	Three Months Ended September 30,			Nine Months Ended September 30,
		Percent Change			Percent Change
	2023		2022	2023		2022
Downstream Crude Oil Unit Throughput (Mbbls/d)
Canadian Manufacturing	108.4	10	98.5	100.8	9	92.5
U.S. Manufacturing	555.9	28	435.0	453.3	12	405.3
Total Crude Oil Unit Throughput	664.3	25	533.5	554.1	11	497.8
Downstream Production Volumes (1)(Mbbls/d)
Canadian Manufacturing	122.4	10	111.0	114.6	10	104.2
U.S. Manufacturing	583.6	26	461.6	475.2	11	426.7
Total Downstream Production	706.0	23	572.6	589.8	11	530.9

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

In the Canadian Manufacturing segment, total throughput and refined product production increased in the three months ended September 30, 2023, compared with 2022. The increases were due to the Lloydminster Upgrader (“Upgrader”) and Lloydminster Refinery running at or near capacity in the third quarter of 2023, combined with temporary unplanned outages in the third quarter of 2022.

Crude throughput and refined product production increased in the nine months ended September 30, 2023, compared with 2022 due the same factors as discussed above, combined with:

•The Lloydminster Refinery running at or near capacity in the first nine months of 2023.

•Additional temporary unplanned outages and planned turnarounds in 2022 at the Upgrader and Lloydminster Refinery.

The increases were partially offset by an unplanned outage at the Upgrader in the second quarter of 2023.

In the U.S. Manufacturing segment, total throughput and refined product production increased significantly in the three months ended September 30, 2023, compared with 2022 due to:

•The purchase of the remaining 50 percent interest in the Toledo Refinery from BP Products North America Inc. (“bp”) on February 28, 2023 (the “Toledo Acquisition”). The refinery partially restarted in April and commenced full operations in June. Crude utilization in the third quarter of 2023 was 90 percent (2022 – 58 percent).

•The introduction of crude oil at the Superior Refinery in mid-March 2023. We safely restarted the FCCU in early October. Crude utilization in the third quarter of 2023 was 66 percent (2022 – nil).

•Strong performance from the Wood River Refinery, combined with the impact of the planned turnaround in the third quarter of 2022. Crude utilization at the Wood River and Borger refineries in the third quarter was 95 percent (2022 – 91 percent).

The increases were partially offset by unplanned outages combined with planned maintenance at the Lima Refinery. In the third quarter, crude utilization at the Lima Refinery was 82 percent (2022 – 94 percent). We continue to find ways to integrate the Lima and Toledo refineries to optimize our operating margin.

Crude throughput and refined product production increased in the nine months ended September 30, 2023, compared with 2022 due the same factors as discussed above, combined with:

•Relatively consistent year-to-date performance at the Lima Refinery. Crude utilization was 89 percent (2022 – 88 percent).

•The planned turnaround completed at the Wood River Refinery in the second quarter of 2023 having less of an impact than the turnaround in 2022 and the decision to operate at reduced rates early in 2022 to optimize margins as market conditions dictated.

The increase was partially offset by:

•A planned turnaround at the Borger Refinery in the spring and temporary unplanned outages in the second quarter. The turnaround and outages had a larger impact on throughput than the turnaround completed in the spring of 2022.

•Unplanned outages at the Wood River and Borger refineries in the fourth quarter of 2022 that were resolved in the first quarter of 2023.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  8

Selected Consolidated Financial Results

Revenues

Revenues decreased 17 percent to $14.6 billion from the third quarter of 2022. Year-to-date, revenues decreased 26 percent to $39.1 billion from 2022. The decreases were primarily due to lower blended crude oil benchmark pricing impacting our Oil Sands segment, and lower natural gas and refined product benchmark pricing, partially offset by a weaker Canadian dollar on average relative to the U.S. dollar.

Operating Margin

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

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Gross Sales (1)	18,441	21,123	47,507	62,599
Less: Royalties	1,135	1,226	2,368	3,993
Revenues	17,306	19,897	45,139	58,606
Expenses
Purchased Product (1)	8,847	12,063	22,874	31,078
Transportation and Blending (1)	2,397	2,826	8,194	9,317
Operating Expenses	1,692	1,695	5,201	5,125
Realized (Gain) Loss on Risk Management Activities	1	(26)	(1)	1,605
Operating Margin	4,369	3,339	8,871	11,481

(1)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

Operating Margin by Segment

Three Months Ended September 30, 2023 and 2022

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  9

Operating Margin increased $1.0 billion to $4.4 billion in the three months ended September 30, 2023, compared with the same period in 2022, primarily due to:

•Higher gross margins in the U.S. Manufacturing segment mainly resulting from the Toledo Refinery being fully operational and the Superior Refinery ramping up operations in the third quarter of 2023, combined with processing feedstock purchased at lower prices in the second quarter positively impacting our U.S. refining margins in the third quarter.

•Increased realized crude oil sales prices from the Oil Sands segment due to a higher percentage of recovered condensate costs through blended sales due to a significantly narrower WCS-Condensate differential. In addition, our Oil Sands segment benefited from blending condensate purchased at lower prices.

•Higher Oil Sands sales volumes mainly driven by higher production.

Operating Margin in the Conventional segment decreased compared with 2022 primarily due to lower realized natural gas prices. The decrease was generally offset by reduced fuel operating costs in the Oil Sands and Canadian Manufacturing segments on natural gas purchased from the Conventional segment.

Nine Months Ended September 30, 2023 and 2022

Operating Margin decreased $2.6 billion to $8.9 billion in the nine months ended September 30, 2023, compared with the same period in 2022, primarily due to:

•Lower realized crude oil and NGLs sales prices resulting from lower benchmark pricing.

•Decreased gross margin from the U.S. Manufacturing segment resulting from lower market crack spreads, partially offset by higher throughput and refined product production with Toledo and Superior refineries being operational.

•Lower sales volumes from our Offshore segment.

•Increased non-fuel operating expenses from the Oil Sands segment primarily due to higher repairs and maintenance costs.

•Higher transportation costs from the Oil Sands segment mainly due to increased tariff rates.

These decreases in Operating Margin were partially offset by:

•Lower royalties in the Oil Sands and Conventional segments, resulting from lower crude oil and natural gas benchmark pricing.

•Minor realized risk management gains in 2023 compared with significant realized risk management losses in 2022.

Operating Margin in the Conventional segment decreased compared with 2022 primarily due to lower realized natural gas prices. The decrease was generally offset by reduced fuel operating costs in the Oil Sands and Canadian Manufacturing segments on natural gas purchased from the Conventional segment.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  10

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

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

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Cash From (Used in) Operating Activities	2,738	4,089	4,442	8,433
(Add) Deduct:
Settlement of Decommissioning Liabilities	(68)	(55)	(157)	(101)
Net Change in Non-Cash Working Capital	(641)	1,193	(2,142)	(98)
Adjusted Funds Flow	3,447	2,951	6,741	8,632

Cash from operating activities decreased in the third quarter of 2023 compared with 2022. Higher Operating Margin was more than offset by changes in non-cash working capital. The net change in non-cash working capital of $641 million was mainly due to an increase in accounts receivable, inventories and higher cash taxes, primarily due to rising commodity prices. The change was partially offset by higher accounts payable primarily due to increased crude throughput.

Adjusted Funds Flow was higher in the third quarter of 2023 compared with 2022, primarily due to increased Operating Margin.

Cash from operating activities decreased in the first nine months of 2023 compared with 2022. The decline was primarily due to lower Operating Margin and changes in non-cash working capital, partially offset by the 2022 contingent payment. The net change in non-cash working capital in the first nine months of 2023 was $2.1 billion, mainly due to paying a $1.2 billion income tax liability and the same factors impacting the third quarter discussed above.

Adjusted Funds Flow was lower in the nine months ended September 30, 2023 compared with 2022, primarily due to decreased Operating Margin.

Net Earnings (Loss)

($ millions)	Three Months Ended	Nine Months Ended
Net Earnings (Loss), for the Periods Ended September 30, 2022	1,609	5,666
Increase (Decrease) due to:
Operating Margin	1,030	(2,610)
Corporate and Eliminations:
General and Administrative	(164)	(72)
Finance Costs	101	138
Integration and Transaction Costs	15	30
Unrealized Foreign Exchange Gain (Loss)	239	518
Revaluation Gain (Loss)	(549)	(582)
Re-measurement of Contingent Payments	(176)	59
Gain (Loss) on Divestiture of Assets	60	(233)
Other Income (Loss), net	(37)	(425)
Other (1)	(214)	(284)
Unrealized Risk Management Gain (Loss)	(54)	(91)
Depreciation, Depletion and Amortization	(150)	(165)
Exploration Expense	71	89
Income Tax (Expense) Recovery	83	1,328
Net Earnings (Loss), for the Periods Ended September 30, 2023	1,864	3,366

(1)Includes Corporate and Eliminations revenues, purchased product, transportation and blending expenses, operating expenses and (gain) loss on risk management; share of income (loss) from equity-accounted affiliates; interest income and realized foreign exchange (gains) losses.

Net earnings in the third quarter of 2023 increased by $255 million compared with the same period in 2022 due to higher Operating Margin, lower unrealized foreign exchange losses and decreased finance costs. The increase was partially offset by the revaluation gain related to the Sunrise Acquisition in the third quarter of 2022, a loss on re-measurement of the Sunrise contingent payment compared with a gain in 2022, higher general and administrative expenses due to long-term incentive costs, and increased DD&A.

Net earnings in the first nine months of 2023 decreased by $2.3 billion compared with the same period in 2022 due to declines in Operating Margin, the revaluation gain related to the Sunrise Acquisition in 2022, lower other income due to the 2022 insurance proceeds related to the Superior Refinery and Atlantic region incidents, higher net gains on asset divestitures in 2022 and higher DD&A. The decrease in net earnings was partially offset by a lower income tax expense, unrealized foreign exchange gains in 2023 compared with losses in 2022, and decreased finance costs.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  11

Net Debt

As at ($ millions)	September 30, 2023	June 30, 2023	December 31, 2022
Short-Term Borrowings	14	—	115
Current Portion of Long-Term Debt	—	—	—
Long-Term Portion of Long-Term Debt	7,224	8,534	8,691
Total Debt	7,238	8,534	8,806
Less: Cash and Cash Equivalents	(1,262)	(2,167)	(4,524)
Net Debt	5,976	6,367	4,282

Long-term debt decreased by $1.3 billion from June 30, 2023, and $1.5 billion from December 31, 2022, primarily due to the purchase of unsecured notes with an aggregate principal amount of US$1.0 billion in the third quarter of 2023. Net Debt decreased by $391 million from June 30, 2023 and increased by $1.7 billion from December 31, 2022. The year-to-date increase is partly due to the payment of a $1.2 billion income tax liability in the first quarter of 2023.

For further details see the Liquidity and Capital Resources section of this MD&A.

Capital Investment (1)

	Three Months Ended September 30,			Nine Months Ended September 30,
($ millions)	2023	2022		2023	2022
Upstream
Oil Sands	590		360	1,764	1,111
Conventional	100		67	323	188
Offshore	194		81	478	225
Total Upstream	884		508	2,565	1,524
Downstream
Canadian Manufacturing	38		24	99	77
U.S. Manufacturing	88		300	435	774
Total Downstream	126		324	534	851
Corporate and Eliminations	15		34	29	59
Total Capital Investment	1,025		866	3,128	2,434

(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes cost incurred in our equity-accounted investment in Indonesia.

Oil Sands capital investment in the first nine months of 2023 was mainly for sustaining activities and the drilling of stratigraphic test wells as part of our integrated winter program in the first quarter, in addition to optimization and growth investment.

Conventional capital investment in the nine months of 2023 continued to focus on drilling, completion, tie-in and infrastructure projects.

Offshore capital investment in the first nine months of 2023 was primarily for the West White Rose project and Terra Nova asset life extension (“ALE”) project in the Atlantic region.

U.S. Manufacturing capital investment in the first nine months of 2023 focused primarily on the Superior Refinery rebuild, and growth and reliability initiatives at the Wood River, Borger, Lima and Toledo refineries.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  12

Drilling Activity

	Net Stratigraphic Test Wells and Observation Wells		Net Production Wells (1)
Nine Months Ended September 30,	2023	2022	2023	2022
Foster Creek	87	52	34	22
Christina Lake	53	—	11	21
Sunrise	38	15	15	2
Lloydminster Thermal	8	1	2	29
Lloydminster Conventional Heavy Oil	1	—	21	—
Other (2)	3	22	—	—
	190	90	83	74

(1)SAGD well pairs in the Oil Sands segment are counted as a single producing well.

(2)Includes new resource plays.

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.

	Nine Months Ended September 30, 2023			Nine Months Ended September 30, 2022
(net wells)	Drilled	Completed	Tied-in	Drilled	Completed	Tied-in
Conventional	30	29	30	19	28	29

In the Offshore segment, we drilled and completed one (0.4 net) planned development well at the MAC field in Indonesia in the first nine months of 2023 (first nine months of 2022 – drilled and completed seven (2.8 net) planned development wells at the MBH and MDA fields in Indonesia).

Future Capital Investment

Future Capital Investment is a specified financial measure. See the Specified Financial Measures Advisory of this MD&A. Our 2023 guidance, as updated on July 26, 2023, is available on our website at cenovus.com.

The following table shows guidance for 2023:

	Capital Investment ($ millions)	Production (MBOE/d)	Crude Oil Unit Throughput (Mbbls/d)
Upstream
Oil Sands	2,200 - 2,400	577 - 637
Conventional	350 - 450	115 - 130
Offshore	600 - 700	55 - 68
Downstream	800 - 900		580 - 610
Corporate and Eliminations	40 - 50

2023 guidance for total capital investment is between $4.0 billion and $4.5 billion. This includes sustaining capital of approximately $2.8 billion, and between $1.2 billion and $1.7 billion in optimization and growth capital.

Further information on the changes in our financial and operating results can be found in the Reportable Segments section of this MD&A. Information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  13

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)

	Nine Months Ended September 30,
(Average US$/bbl, unless otherwise indicated)	2023	Percent Change	2022	Q3 2023	Q2 2023	Q3 2022
Dated Brent	82.14	(22)	105.35	86.76	78.39	100.85
WTI	77.39	(21)	98.09	82.26	73.78	91.55
Differential Dated Brent-WTI	4.75	(35)	7.26	4.50	4.61	9.30
WCS at Hardisty	59.82	(27)	82.36	69.35	58.74	71.69
Differential WTI-WCS	17.57	12	15.73	12.91	15.04	19.86
WCS (C$/bbl)	80.47	(24)	105.54	93.06	78.90	93.53
WCS at Nederland	69.12	(25)	91.81	77.89	66.98	82.91
Differential WTI-WCS at Nederland	8.27	32	6.28	4.37	6.80	8.64
Condensate (C5 @ Edmonton)	76.74	(21)	97.24	77.96	72.39	87.26
Differential WTI-Condensate (Premium)/Discount	0.65	24	0.85	4.30	1.39	4.29
Differential WCS (2)-Condensate (Premium)/Discount	(16.92)	(14)	(14.88)	(8.61)	(13.65)	(15.57)
Condensate (C$/bbl)	103.28	(17)	124.62	104.63	97.25	113.89
Synthetic @ Edmonton	79.93	(22)	102.61	84.95	76.66	100.34
Differential WTI-Synthetic (Premium)/Discount	(2.54)	44	(4.52)	(2.69)	(2.88)	(8.79)
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	102.58	(19)	126.58	105.59	102.32	121.52
Chicago Ultra-low Sulphur Diesel (“ULSD”)	110.52	(24)	144.82	113.77	102.40	148.24
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)	27.83	(19)	34.57	26.06	28.57	38.87
Group 3 3-2-1 Crack Spread (3)	33.36	(3)	34.29	36.96	31.78	38.57
Renewable Identification Numbers (“RINs”)	7.80	5	7.45	7.42	7.72	8.11
Natural Gas Prices
AECO (4)(C$/Mcf)	2.76	(49)	5.38	2.60	2.45	4.16
NYMEX (5)(US$/Mcf)	2.69	(60)	6.77	2.55	2.10	8.20
Foreign Exchange Rates
US$ per C$1 - Average	0.743	(5)	0.780	0.746	0.745	0.766
US$ per C$1 - End of Period	0.740	1	0.730	0.740	0.755	0.730
RMB per C$1 - Average	5.229	2	5.147	5.402	5.228	5.246

(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 Reportable Segments section of this MD&A.

(2)WCS at Hardisty.

(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.

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

(5)NYMEX natural gas monthly index.

Crude Oil and Condensate Benchmarks

In the third quarter of 2023, Brent and WTI prices improved from the second quarter of 2023 mainly due to seasonal demand strength and announcements that Saudi Arabia and Russia will extend voluntary production cuts through the end of 2023. Benchmark prices in the three and nine months ending September 30, 2023, were lower than the same periods in 2022, as the global crude supply deficit put significant upward pressure on prices in 2022, which was exacerbated by risks related to Russian export supply shortfall uncertainty. Global supply growth and resilient Russian exports have resulted in a more balanced crude market in 2023, resulting in prices falling from elevated levels last year.

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.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  14

The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI differential narrowed in the third quarter of 2023 and on a year-to-date basis compared with 2022 as physical supply uncertainty and high marine fuel prices caused the differential to widen significantly in 2022 in the months following Russia’s invasion of Ukraine in February 2022. The Brent-WTI differential was relatively consistent between the second and third quarters of 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 average WTI-WCS differential at Hardisty narrowed from the second quarter of 2023 due to voluntary OPEC+ cuts to medium and heavy crude production. The differential also narrowed compared with the third quarter of 2022, as 2022 saw slightly higher transport costs from increased pipeline utilization and a wider quality differential attributed to high global refining utilization, rising supply of medium and heavy oil barrels into the market from OPEC+, and releases of U.S. government Strategic Petroleum Reserves (“SPRs”).

During the nine months ended September 30, 2023, the WTI-WCS differential at Hardisty widened compared with 2022 primarily as a result of high heavy crude processing utilization in the USGC, planned and unplanned refinery maintenance and volatile refined product pricing.

WCS at Nederland is a heavy oil benchmark for sales of our product at the USGC. The WTI-WCS at Nederland differential is representative of the heavy oil quality discount and is influenced by global heavy oil refining capacity and global heavy oil supply. The WTI-WCS at Nederland differential narrowed from the second quarter of 2023 and the third quarter of 2022, and widened in the nine months ended September 30, 2023, compared with 2022, due to the same factors impacting the WTI-WCS differential at Hardisty discussed above.

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

In the three and nine months ended September 30, 2023, synthetic crude at Edmonton was at a lower premium to WTI compared with the same periods in 2022. Synthetic crude prices were elevated in the second and third quarters of 2022 as a result of upgrader maintenance in Western Canada and strong refinery demand for light crude oil. The premium in the third quarter of 2023 narrowed slightly compared with the second quarter.

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 22 percent to 35 percent. The WCS-Condensate differential is an important benchmark as a wider differential generally results in a decrease in the recovery of condensate costs 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 sales of blended product. The WCS-Condensate differential narrowed in the third quarter of 2023 from the second quarter due to relative strengthening of WCS discussed above.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  15

In the three and nine months ended September 30, 2023, the Edmonton condensate discount to WTI was consistent with the same periods in 2022. The discount widened from the second quarter of 2023, consistent with seasonal pricing patterns and lower heavy crude blending requirements in summer months.

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.

The Chicago 3-2-1 market crack spread reflects the market for the Toledo, Lima and Wood River refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries.

Refined product prices declined in the three and nine months ended September 30, 2023, compared with the same periods in 2022. Market crack spreads also declined during this period as 2022 saw periods of historically high refined product prices and refining margins.

Reduced refinery outages and incremental global capacity additions have resulted in declining refined product prices relative to WTI in 2023, compared with 2022, particularly in diesel markets. The Chicago 3-2-1 market crack spread declined compared with the second quarter of 2023 as regional refining utilization was high and waterway maintenance prevented products from being barged to other markets. Group 3 3-2-1 crack spreads increased from the second quarter of 2023 due to higher diesel pricing amid strong demand and low diesel imports as a result of low global inventories. RINs costs remain high as a result of a tight biofuel market, high feedstock prices and uncertainty around policies that drive RINs demand.

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 many other factors such as the variety of crude oil feedstock, refinery configuration and product output, where feedstocks are acquired and the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock, which 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, however they are used as a general market indicator.

(1)There are no forward prices for RINs.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  16

Natural Gas Benchmarks

Average NYMEX and AECO natural gas prices decreased significantly compared with the three and nine months ended September 30, 2022, due to mild winter conditions weighing on U.S. domestic demand coupled with record high natural gas production and inventories. NYMEX natural gas prices increased marginally compared with the second quarter of 2023 as record high summer natural gas consumption in the U.S. outweighed high production levels. AECO natural gas prices increased slightly compared with the second quarter of 2023 as higher Western Canadian exports and seasonal pipeline maintenance resulted in a widening differential to NYMEX that offset the increase in NYMEX prices. 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. In addition, changes in foreign exchange rates impact the translation of our U.S. and Asia Pacific operations.

In the three and nine months ended September 30, 2023, the Canadian dollar on average weakened relative to the U.S. dollar compared with the same periods in 2022, positively impacting our reported revenues. The Canadian dollar weakened relative to the U.S. dollar as at September 30, 2023, compared with June 30, 2023, resulting in unrealized foreign exchange losses in the third quarter on the translation of our U.S. dollar debt into Canadian dollars. The Canadian dollar was consistent relative to the U.S. dollar as at September 30, 2023, compared with December 31, 2022, resulting in minimal unrealized foreign exchange impacts.

A portion of our long-term sales contracts in the Asia Pacific region are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. In the three and nine months ended September 30, 2023, the Canadian dollar on average was relatively consistent with RMB compared with the same periods in 2022, resulting in minimal impact on our revenues.

Interest Rate Benchmarks

Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. A change in interest rates could change our net interest expense and affect how certain liabilities are measured and impact our cash flow and financial results.

As at September 30, 2023, the Bank of Canada’s Policy Interest Rate was 5.00 percent, an increase from 4.75 percent on June 30, 2023, and from 4.25 percent on December 31, 2022, due to concerns over inflation. On October 25, 2023, the Bank of Canada announced the rate will remain at 5.00 percent.

OUTLOOK

COMMODITY PRICE OUTLOOK

Global crude oil prices increased quarter-over-quarter for the first time since the second quarter of 2022 largely due to production cuts by Saudi Arabia and Russia. Crude oil demand growth has been resilient in 2023 despite weak macroeconomic indicators, supported by the lifting of China’s COVID-19 restrictions earlier in the year.

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. Policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shift global trade patterns. The OPEC+ announced extension of production cuts that will continue to be supportive of pricing, with production quotas being a key driver of crude oil prices. 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 refilling of SPRs, and the crisis in Israel and Gaza. In addition, weakening global economic activity, inflation and rising interest rates, and the potential for a recession remain a risk to the pace of demand growth.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  17

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. We expect the start-up of the Trans Mountain pipeline expansion in 2024 to have a narrowing impact on WTI-WCS differentials.

•We expect refined product prices and market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies could 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.

•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. Weather will continue to be a key driver of demand and impact prices.

•We expect the Canadian dollar to continue to be impacted by crude oil prices, 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, and emerging macro-economic factors.

Most of our upstream crude oil and downstream refined product production are exposed to movements in the WTI crude oil price. Our physically integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Natural gas and NGLs production associated with our Conventional operations provide economic integration for the fuel and blending requirements at our Oil Sands and Canadian Manufacturing operations. Crude oil production in our upstream assets is blended with condensate and used as feedstock by our downstream operations, and condensate extracted from our blended crude oil is sold back to our Oil Sands operations. The restart of the Superior and Toledo refineries provide further integration.

Our refining capacity is focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to the market crack spreads in all of 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 as well as from spreads on refined products.

•Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil price differentials.

•Traditional crude oil storage tanks in various geographic locations.

REPORTABLE SEGMENTS

UPSTREAM

Oil Sands

In the third quarter of 2023, we:

•Delivered safe and reliable operations.

•Produced 601.6 thousand barrels of crude oil per day (2022 – 585.0 thousand barrels of crude oil per day).

•Brought two new well pads on production at Foster Creek.

•Completed the ramp up of one well pad at Foster Creek and two wells pads at Christina Lake that started up in the second quarter.

•Acquired the remaining 10 percent interest in the Ipiatik area at Foster Creek, which will provide additional bitumen reserves to the Foster Creek plant.

•Completed a planned turnaround at Christina Lake with minimal production impacts.

•Generated Operating Margin of $3.0 billion, an increase of $801 million compared with 2022 primarily due to higher average realized sales prices, and higher sales volumes driven by higher production.

•Invested capital of $590 million primarily for sustaining activities.

•Achieved a Netback of $54.78 per BOE (2022 – $41.91 per BOE).

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  18

Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Revenues
Gross Sales (1)	7,571	8,764	19,715	28,030
Less: Royalties	1,082	1,136	2,218	3,709
	6,489	7,628	17,497	24,321
Expenses
Purchased Product (1)	462	1,919	1,231	4,202
Transportation and Blending	2,324	2,758	7,965	9,114
Operating	688	689	2,101	2,197
Realized (Gain) Loss on Risk Management	(6)	42	(7)	1,468
Operating Margin	3,021	2,220	6,207	7,340
Unrealized (Gain) Loss on Risk Management	47	(2)	44	(59)
Depreciation, Depletion and Amortization	785	652	2,230	1,977
Exploration Expense	—	7	4	7
(Income) Loss from Equity-Accounted Affiliates	—	—	6	8
Segment Income (Loss)	2,189	1,563	3,923	5,407

(1)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

Operating Margin Variance

Three Months Ended September 30, 2023

Nine Months Ended September 30, 2023

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

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  19

Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Total Sales Volumes (1)(MBOE/d)	597.2	578.0	584.1	583.8
Total Realized Price (2)($/BOE)	94.45	84.29	74.08	99.78
Crude Oil Production by Asset (Mbbls/d)
Foster Creek	189.3	182.4	182.1	189.3
Christina Lake	237.6	252.8	236.6	245.2
Sunrise (3)	54.5	30.9	48.6	26.8
Lloydminster Thermal	104.6	102.1	103.3	99.0
Lloydminster Conventional Heavy Oil	15.6	16.8	16.5	16.5
Tucker (4)	—	—	—	2.1
Total Crude Oil Production (5) (Mbbls/d)	601.6	585.0	587.1	578.9
Natural Gas (6) (MMcf/d)	10.6	12.6	12.0	12.5
Total Production (MBOE/d)	603.4	587.1	589.0	580.9
Effective Royalty Rate (7) (percent)
Foster Creek	23.4	33.6	22.9	30.0
Christina Lake	33.2	34.8	29.8	31.8
Sunrise	5.6	9.6	5.4	7.3
Lloydminster (8)	8.5	9.7	8.7	10.0
Total Effective Royalty Rate	22.6	27.8	21.1	25.4
Transportation and Blending Expense (2)($/BOE)	7.41	7.72	8.16	7.48
Operating Expense (2)($/BOE)	12.56	13.40	13.09	13.83
Per Unit DD&A (2) ($/BOE)	12.96	11.63	12.90	11.83

(1)Bitumen, heavy crude oil and natural gas.

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

(3)On August 31, 2022, we acquired the remaining 50 percent interest in Sunrise from bp Canada.

(4)The Tucker asset was sold on January 31, 2022.

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

(6)Conventional natural gas product type.

(7)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses.

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

Revenues

Price

Our heavy oil and bitumen 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 heavy oil and bitumen sales price decreases.

In the three and nine months ended September 30, 2023, condensate benchmark pricing was at a US$8.61 per barrel and US$16.92 per barrel premium to WCS at Hardisty, respectively (2022 – US$15.57 and US$14.88 per barrel premium, respectively). The significant quarter-over-quarter narrowing of WCS-condensate differentials had a positive impact on our realized bitumen sales price compared with 2022. Year-to-date, the widening of WCS-condensate differentials had a negative impact on our realized bitumen sales price compared with 2022. Up to three months may lapse from when we purchase condensate to when we sell our blended production.

Our realized sales price averaged $94.45 per BOE in the third quarter of 2023 (2022 – $84.29 per BOE) due to a lower cost of condensate, purchased earlier in the quarter, and a higher recovery of that cost through blended sales, with significantly narrower WCS-Condensate differentials. WTI benchmark pricing averaged US$82.26 per barrel in the third quarter of 2023 (2022 – US$91.55 per barrel). The decrease in WTI was mostly offset by narrower WTI-WCS differentials quarter-over-quarter. The WTI-WCS at Hardisty differential was US$12.91 per barrel in the three months ended September 30, 2023 (2022 – US$19.86 per barrel).

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  20

Our realized sales price decreased to $74.08 per BOE in the nine months ended September 30, 2023 from $99.78 per BOE in 2022 due to lower WTI benchmark prices and wider WTI-WCS differentials. In the nine months ended September 30, 2023, WTI averaged US$77.39 per barrel (2022 – US$98.09 per barrel) and the WTI-WCS at Hardisty differential was US$17.57 per barrel (2022 – US$15.73 per barrel).

For the three and nine months ended September 30, 2023, gross sales included $398 million and $1.0 billion, respectively (2022 – $1.9 billion and $4.0 billion, respectively), from third-party sourced volumes.

For the three and nine months ended September 30, 2023, gross sales included $95 million and $281 million, respectively (2022 – $79 million and $248 million, respectively), relating to construction, transportation and blending activities.

Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including storage and pipeline assets, 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.

Realized (Gain) Loss on Risk Management

In the three and nine months ended September 30, 2023, our realized risk management gains were $6 million and $7 million, respectively (2022 – losses of $42 million and $1.5 billion, respectively). The changes from 2022 are due to management’s decision to liquidate our WTI positions related to crude oil sales price risk management in the second quarter of 2022.

Production Volumes

Oil Sands crude oil production was 601.6 thousand barrels per day and 587.1 thousand barrels per day in the three and nine months ended September 30, 2023, respectively (2022 – 585.0 thousand barrels per day and 578.9 thousand barrels per day, respectively).

In the first nine months of 2023, we sold approximately 25 percent (2022 – 20 percent) of our crude oil volumes to third parties at U.S. destinations and sold approximately 20 percent of our crude oil volumes to our downstream operations.

Production at Foster Creek increased 6.9 thousand barrels per day in the third quarter of 2023 compared with 2022, primarily due to planned maintenance and an unplanned outage in the third quarter of 2022. In addition, we completed ramp up of one new well pad brought online in the second quarter of 2023 and brought two new well pads online in the third quarter of 2023. Year-to-date, production decreased 7.2 thousand barrels per day compared with 2022, primarily due to a planned turnaround that commenced in mid-April and completed in early May 2023, having a greater impact than the 2022 planned maintenance and unplanned outage.

Production at Christina Lake decreased 15.2 thousand barrels per day and 8.6 thousand barrels per day, respectively, in the three and nine months ended September 30, 2023 compared with the same periods in 2022. The decreases were primarily due to flush production following a planned turnaround in the second quarter of 2022 and the timing of new well pads in 2023 compared with the incremental production from development wells drilled in prior years. We brought two new well pads on production in the second quarter of 2023 which partially offset the decreases. We completed a planned turnaround in the third quarter of 2023 that had minimal production impacts.

The Sunrise Acquisition was completed on August 31, 2022. Production at Sunrise increased 23.6 thousand barrels per day and 21.8 thousand barrels per day, respectively, in the three and nine months ended September 30, 2023, compared with 2022. In addition, successful results from our 2023 redevelopment program completed in the third quarter increased production quarter-over-quarter.

Production from our Lloydminster thermal assets increased slightly in the three and nine months ended September 30, 2023, compared with 2022. The increases are due to first oil at the Spruce Lake North thermal plant in August 2022, partially offset by wells taken offline for a redevelopment program and workover activity in the first nine months of 2023.

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.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  21

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 a one percent rate and the post-payout calculation is based on a 20 percent rate. The freehold calculation is limited to post-payout projects and is based on an eight percent rate.

For the three and nine months ended September 30, 2023, royalties were $1.1 billion and $2.2 billion, respectively (2022 – $1.1 billion and $3.7 billion, respectively). In the first nine months of 2023, total Oil Sands effective royalty rates decreased to 21.1 percent from 25.4 percent in 2022 primarily due to lower realized pricing and lower Alberta oil sands sliding scale royalty rates.

Expenses

Transportation and Blending

In the third quarter of 2023, blending costs decreased $432 million to $1.9 billion compared with 2022, as we benefited from blending condensate purchased earlier in the quarter at lower prices as compared to 2022 where the cost of condensate used for blending was higher. In the first nine months of 2023, blending costs decreased $1.3 billion to $6.6 billion compared with 2022. On a year-to-date basis, the declines were largely due to lower condensate prices, partially offset by higher sales volumes.

Transportation costs of $432 million in the third quarter of 2023 were consistent with 2022. In the first nine months of 2023, transportation costs rose $147 million to $1.4 billion, due to higher tariff rates.

Per-unit Transportation Expenses

Transportation costs were $7.41 per BOE and $8.16 per BOE in the three and nine months ended September 30, 2023, respectively (2022 – $7.72 per BOE and $7.48 per BOE, respectively).

At Foster Creek, per-unit transportation costs were $10.55 per barrel and $12.20 per barrel in the three and nine months ended September 30, 2023, respectively (2022 – $11.96 per barrel and $10.71 per barrel, respectively). The quarter-over-quarter decrease was mainly due to higher sales volumes. The year-over-year increase primarily was due to lower sales volumes and higher tariff costs. In the three and nine months ended September 30, 2023, we shipped 44 percent and 46 percent, respectively (2022 – 41 percent and 42 percent, respectively) of our volumes from Foster Creek to U.S. destinations.

At Christina Lake, transportation costs were $5.76 per barrel and $6.46 per barrel in the three and nine months ended September 30, 2023 (2022 – $6.02 per barrel and $6.37 per barrel, respectively). The quarter-over-quarter decrease was primarily due to lower fixed rail costs. The year-over-year increase was mainly due to higher tariff rates, partially offset by lower fixed rail costs. In the three and nine months ended September 30, 2023, we shipped 14 percent and 17 percent, respectively (2022 – 11 percent and 14 percent, respectively) of our volumes from Christina Lake to U.S. destinations.

At Sunrise, transportation costs in the three and nine months ended September 30, 2023, were $12.29 per barrel and $12.49 per barrel, respectively (2022 – $13.17 per barrel and $12.96 per barrel, respectively). The quarter-over-quarter decrease was due to higher gross sales volumes, partially offset by a higher percentage of volumes shipped to U.S. destinations. The year-over-year decrease was mainly due to a lower percentage of volumes shipped to U.S. destinations. In the three and nine months ended September 30, 2023, we shipped 51 percent and 49 percent, respectively (2022 – 39 percent and 51 percent, respectively) of our volumes from Sunrise to U.S. destinations.

At our other Oil Sands assets, transportation costs in the three and nine months ended September 30, 2023, were $3.29 per barrel and $3.54 per barrel, respectively (2022 – $3.57 per barrel and $3.45 per barrel, respectively).

Operating

Primary drivers of our operating expenses in the first nine months of 2023 were fuel, workforce, repairs and maintenance, and chemicals. Total operating expenses were relatively flat in the third quarter of 2023 compared with 2022, and decreased in the first nine months of 2023 compared with 2022. Fuel costs decreased as a result of significant declines in AECO benchmark prices in the three and nine months ended September 30, 2023, compared with 2022. The decreases were offset by higher repairs and maintenance costs in the three and nine months ended September 30, 2023, compared with 2022.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  22

Unit Operating Expenses (1)

	Three Months Ended September 30,			Nine Months Ended September 30,
($/BOE)	2023	Percent Change	2022	2023	Percent Change	2022
Foster Creek
Fuel	2.83	(52)	5.91	3.76	(35)	5.77
Non-Fuel	8.08	7	7.55	8.24	15	7.19
Total	10.91	(19)	13.46	12.00	(7)	12.96
Christina Lake
Fuel	2.87	(36)	4.46	3.13	(37)	5.00
Non-Fuel	6.45	36	4.73	5.71	14	5.01
Total	9.32	1	9.19	8.84	(12)	10.01
Sunrise
Fuel	4.13	(46)	7.58	4.98	(36)	7.78
Non-Fuel	11.81	16	10.16	13.18	22	10.76
Total	15.94	(10)	17.74	18.16	(2)	18.54
Other Oil Sands (2)
Fuel	4.25	(11)	4.77	4.69	(34)	7.13
Non-Fuel	15.82	(2)	16.10	16.42	11	14.85
Total	20.07	(4)	20.87	21.11	(4)	21.98
Total Oil Sands
Fuel	3.24	(37)	5.14	3.79	(35)	5.81
Non-Fuel	9.32	13	8.26	9.30	16	8.02
Total	12.56	(6)	13.40	13.09	(5)	13.83

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

(2)Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.

Per-unit fuel prices decreased due to lower natural gas prices as discussed above. Per-unit fuel prices were also impacted by the timing and value of sales out of inventory.

Foster Creek per-unit non-fuel costs increased in the three and nine months ended September 30, 2023, compared with 2022. The quarter-over-quarter increase was due to higher repairs and maintenance costs, partially offset by higher sales volumes and the impact of the planned maintenance and unplanned outage in the third quarter of 2022. The year-to-date increase was due to lower sales volumes in 2023 combined with costs related to the planned turnaround in the second quarter of 2023, partially offset by the planned maintenance and unplanned outage in the third quarter of 2022.

Christina Lake per-unit non-fuel costs increased in the three and nine months ended September 30, 2023, compared with 2022, primarily due to lower sales volumes in 2023 combined with a planned turnaround completed in the third quarter of 2023. The year-to-date increase was partially offset by the impacts of planned turnaround in the second quarter of 2022.

Sunrise per-unit non-fuel costs increased in the three months ended September 30, 2023, compared with 2022 mainly due to higher workover activity and repairs and maintenance costs, partially offset by higher gross sales volumes in 2023. The per-unit non-fuel costs increased in the nine months ended September 30, 2023, compared with 2022 due to lower gross sales volumes in 2023 combined with higher electricity and repairs and maintenance costs.

Per-unit non-fuel costs at our other Oil Sands assets were relatively consistent in the third quarter of 2023 compared with 2022. Year-to-date, per-unit non-fuel costs increased from 2022, primarily due to higher workover activity and repairs and maintenance costs.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  23

Netbacks (1)

	Three Months Ended September 30,		Nine Months Ended September 30,
($/BOE)	2023	2022	2023	2022
Sales Price	94.45	84.29	74.08	99.78
Royalties	19.70	21.26	13.91	23.20
Transportation	7.41	7.72	8.16	7.48
Operating Expenses	12.56	13.40	13.09	13.83
Netback	54.78	41.91	38.92	55.27

(1)The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

DD&A

In the three months and nine months ended September 30, 2023, DD&A was $785 million and $2.2 billion, respectively (2022 – $652 million and $2.0 billion, respectively). The average depletion rate for the three and nine months ended September 30, 2023, was $12.96 per BOE and $12.90 per BOE, respectively (2022 – $11.63 per BOE and $11.83 per BOE, respectively).

Conventional

In the third quarter of 2023, we:

•Delivered safe and reliable operations.

•Produced 127.2 thousand BOE per day (2022 – 126.2 thousand BOE per day).

•Substantially returned to full operations following significant wildfire activity in the second quarter of 2023. Additional wildfire activity impacted our Rainbow Lake property in September and had minor impacts on production.

•Generated Operating Margin of $126 million, a decrease from $290 million in 2022 due to lower average realized sales prices.

•Invested capital of $100 million with continued focus on drilling, completion, tie-in and infrastructure projects.

•Averaged a Netback of $9.66 per BOE (2022 – $24.06 per BOE).

Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Revenues
Gross Sales (1)	810	1,036	2,467	3,286
Less: Royalties	27	68	85	228
	783	968	2,382	3,058
Expenses
Purchased Product	438	464	1,258	1,460
Transportation and Blending (1)	73	64	220	191
Operating	150	141	444	403
Realized (Gain) Loss on Risk Management	(4)	9	—	17
Operating Margin	126	290	460	987
Unrealized (Gain) Loss on Risk Management	7	8	(14)	7
Depreciation, Depletion and Amortization	104	103	286	282
Exploration Expense	—	—	—	1
Segment Income (Loss)	15	179	188	697

(1)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  24

Operating Margin Variance

Three Months Ended September 30, 2023

Nine Months Ended September 30, 2023

(1)Reflects Operating Margin from processing facilities.

Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Total Sales Volumes(MBOE/d)	127.2	126.2	118.5	128.0
Total Realized Price (1) ($/BOE)	28.13	44.07	32.70	48.17
Light Crude Oil (1)($/bbl)	105.43	132.08	104.19	125.99
NGLs (1)($/bbl)	47.74	55.80	47.52	61.98
Conventional Natural Gas (1)($/Mcf)	3.05	5.93	4.19	6.48
Production by Product
Light Crude Oil (Mbbls/d)	6.3	6.9	5.8	7.8
NGLs(Mbbls/d)	23.9	19.9	21.3	23.0
Conventional Natural Gas (MMcf/d)	582.1	596.1	548.8	583.1
Total Production(MBOE/d)	127.2	126.2	118.5	128.0
Conventional Natural Gas Production (percentage of total)	76	79	77	76
Crude Oil and NGLs Production (percentage of total)	24	21	23	24
Effective Royalty Rate (percent)	9.6	15.9	10.7	15.3
Transportation Expense (1) ($/BOE)	3.82	2.43	3.97	2.85
Operating Expense (1)($/BOE)	12.36	11.77	13.26	11.03
Per Unit DD&A (1) ($/BOE)	8.82	8.51	8.77	8.23

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

Revenues

Price

Our total realized sales price decreased in the three and nine months ended September 30, 2023, due to lower crude oil and natural gas benchmark prices.

For the three and nine months ended September 30, 2023, gross sales included $438 million and $1.3 billion, respectively (2022 – $464 million and $1.5 billion, respectively), relating to third-party sourced volumes.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  25

For the three and nine months ended September 30, 2023, gross sales included amounts relating to processing and transportation activities undertaken for third parties of $42 million and $150 million, respectively (2022 – $60 million and $143 million, respectively).

Production Volumes

Production volumes were relatively consistent in the third quarter of 2023 compared with 2022, and decreased 9.5 thousand BOE per day in the first nine months of 2023 compared with 2022. Third quarter volumes were positively impacted by successful results from our 2023 development program which offset natural declines. The year-over-year decrease was primarily due to the impact of the wildfires in the second quarter of 2023. In early May, approximately 85 thousand BOE per day of production was temporarily shut-in in response to the wildfires. The majority of our wells and facilities impacted by the fires were restarted in June, and the outages were substantially resolved by late August. In late September additional wildfire activity impacted our Rainbow Lake property, from which production impacts on the quarter were minimal. Production was brought back online in October as power infrastructure was restored.

Royalties

The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Effective royalty rates decreased in the three and nine months ended September 30, 2023, compared with the same periods in 2022 primarily due to sharp declines in natural gas pricing and the impact of wildfires. In addition, the year-over-year decrease was impacted by higher gas cost allowance (“GCA”) deductions. In Alberta, natural gas wells benefit from GCA which reduces royalties to account for capital and operating costs incurred to process and transport the Crown’s portion of natural gas production. Total royalties in the three and nine months ended September 30, 2023, decreased compared with the same periods of 2022 due to the same factors impacting effective royalty rates.

Expenses

Transportation

Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. In the third quarter of 2023, transportation costs increased $9 million to $73 million, compared with 2022, and per-unit transportation costs averaged $3.82 per BOE in 2023, compared with $2.43 per BOE in 2022. The increases were due to higher rates and additional storage costs. Year-to-date, transportation costs increased $29 million to $220 million, and per-unit transportation costs averaged $3.97 per BOE, compared with $2.85 per BOE in 2022. The per BOE increases were mainly due to the same factors impacting the third quarter combined with the impacts of the wildfires.

Operating

Primary drivers of operating expenses in the first nine months of 2023 were repairs and maintenance, workforce, property taxes and lease costs, and electricity. Total operating expenses increased $9 million to $150 million quarter-over-quarter and $41 million to $444 million year-over-year due to the higher repairs and maintenance costs. The wildfires had minimal impact on total operating expenses. Operating expenses per BOE increased $0.59 per BOE quarter-over-quarter and $2.23 per BOE year-over-year due to the same factors impacting total operating costs. Year-to-date, operating expenses per BOE also increased due to lower sales volumes as a result of wildfire activity.

Netbacks (1)

	Three Months Ended September 30,		Nine Months Ended September 30,
($/BOE)	2023	2022	2023	2022
Sales Price	28.13	44.07	32.70	48.17
Royalties	2.29	5.81	2.64	6.49
Transportation and Blending	3.82	2.43	3.97	2.85
Operating Expenses	12.36	11.77	13.26	11.03
Netback	9.66	24.06	12.83	27.80

(1)The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  26

DD&A

For the three and nine months ended September 30, 2023, total Conventional DD&A was $104 million and $286 million, respectively (2022 – $103 million and $282 million, respectively). The average depletion rate for the three and nine months ended September 30, 2023, was $8.82 per BOE and $8.77 per BOE, respectively (2022 – $8.51 per BOE and $8.23 per BOE, respectively).

Offshore

In the third quarter of 2023, we:

•Delivered safe and reliable operations.

•Saw the Terra Nova FPSO return to the field in August. Commissioning activities are ongoing with production expected to resume in the fourth quarter.

•Achieved first gas production from the MAC field in Indonesia in September.

•Produced 66.4 thousand BOE per day (2022 – 64.6 thousand BOE per day).

•Generated Operating Margin of $300 million, a decrease of $39 million compared with 2022, largely due to decreased realized light crude oil and NGLs sales prices.

•Earned a Netback of $57.87 per BOE (2022 – $66.81 per BOE).

•Invested capital of $194 million mainly for the West White Rose project and Terra Nova ALE project in the Atlantic region.

The West White Rose project was approximately 75 percent complete as at September 30, 2023. Since our decision to restart the project, we have invested approximately $440 million. We reached a major milestone on the project in the second quarter with the completion of the conical slip form operation for the concrete gravity structure.

Financial Results

	Three Months Ended September 30,
		2023		2022
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Revenues
Gross Sales	78	324	402	113	337	450
Less: Royalties	2	24	26	2	20	22
	76	300	376	111	317	428
Expenses
Transportation and Blending	—	—	—	4	—	4
Operating	47	29	76	53	32	85
Operating Margin (1)	29	271	300	54	285	339
Depreciation, Depletion and Amortization			130			132
Exploration Expense			2			66
(Income) Loss from Equity-Accounted Affiliates			(11)			(9)
Segment Income (Loss)			179			150

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

Operating Margin Variance

Three Months Ended September 30, 2023

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  27

	Nine Months Ended September 30,
	2023			2022
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Revenues
Gross Sales	232	871	1,103	492	1,083	1,575
Less: Royalties	11	54	65	(4)	60	56
	221	817	1,038	496	1,023	1,519
Expenses
Transportation and Blending	9	—	9	12	—	12
Operating	190	91	281	146	88	234
Operating Margin (1)	22	726	748	338	935	1,273
Depreciation, Depletion and Amortization			349			441
Exploration Expense			6			91
(Income) Loss from Equity-Accounted Affiliates			(29)			(19)
Segment Income (Loss)			422			760

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

Operating Margin Variance

Nine Months Ended September 30, 2023

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  28

Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Sales Volumes
Atlantic (Mbbls/d)	7.8	7.8	7.8	12.6
Asia Pacific (MBOE/d)
China	43.8	45.4	39.4	48.6
Indonesia (1)	13.7	10.1	14.1	9.7
Total Asia Pacific	57.5	55.5	53.5	58.3
Total Sales Volumes (MBOE/d)	65.3	63.3	61.3	70.9
Total Realized Price (2)($/BOE)	79.27	88.02	79.42	91.32
Atlantic - Light Crude Oil (2) ($/bbl)	107.99	158.42	108.48	142.96
Asia Pacific (1)(2) ($/BOE)	75.38	78.19	75.18	80.16
NGLs (2)($/bbl)	101.97	108.39	95.36	113.04
Conventional Natural Gas (2)($/Mcf)	11.43	11.62	11.70	11.88
Production by Product
Atlantic - Light Crude Oil (Mbbls/d)	8.9	9.1	7.7	12.0
Asia Pacific (1)
NGLs(Mbbls/d)	11.7	12.2	10.6	12.4
Conventional Natural Gas (MMcf/d)	274.7	260.0	257.3	275.3
Total Asia Pacific (MBOE/d)	57.5	55.5	53.5	58.3
Total Production(MBOE/d)	66.4	64.6	61.2	70.3
Effective Royalty Rate (percent)
Atlantic	2.4	1.8	4.6	(0.8)
Asia Pacific (1)	9.8	11.1	10.0	11.7
Operating Expense (2)($/BOE)	14.66	12.55	17.37	12.24
Atlantic (2)	65.91	47.23	78.61	36.79
Asia Pacific (1)(2)	7.73	7.70	8.42	6.94
Per Unit DD&A (2) ($/BOE)	26.29	30.89	26.00	30.29

(1)Reported sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements.

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

Revenues

Price

The price we receive for natural gas sold in Asia is set under long-term contracts. Our realized sales price on light crude oil and NGLs decreased in the three and nine months ended September 30, 2023, compared with 2022, primarily due to lower Brent benchmark pricing.

Production Volumes

Atlantic production was relatively consistent in the third quarter of 2023 compared with 2022 and decreased 4.3 thousand barrels per day in the nine months ended September 30, 2023, compared with 2022. The decrease was due to turnaround work on the SeaRose FPSO completed in March and April of 2023 having a larger impact than annual planned maintenance completed in the third quarter in 2022. In addition, the decrease in Cenovus’s working interest at the White Rose field and satellite extensions effective May 31, 2022, lowered production year-over-year. Light crude oil from production at the White Rose fields is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  29

Asia Pacific production increased slightly in the third quarter of 2023 compared with 2022 and decreased 4.8 thousand barrels per day in the nine months ended September 30, 2023, compared with 2022. The year-over-year decrease was mainly due to a temporary unplanned outage in the second quarter in China, related to the disconnection of the umbilical cord by a third-party vessel in early April and reconnected in May. Changes to gas sales agreements at Liwan 3-1 and Liuhua 29-1 in the second quarter of 2022 also resulted in a net decrease in production. The decrease was partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022, and planned maintenance in China in the second and third quarters of 2022 having a larger impact than planned maintenance in June 2023. We drilled and completed the third of three planned development wells at the MAC field Indonesia in the first quarter of 2023, and achieved first gas production from the field in September.

Royalties

In the three and nine months ended September 30, 2023, Atlantic royalties were $2 million and $11 million, respectively (2022 – $2 million and recoveries of $4 million, respectively). In 2022, royalties at the White Rose field included year-to-date adjustments based on an amended agreement between our working interest partners and the Government of Newfoundland and Labrador.

Royalty rates in China and Indonesia are governed by production sharing contracts in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for the three and nine months ended September 30, 2023, declined to 9.8 percent and 10.0 percent, respectively (2022 – 11.1 percent and 11.7 percent, respectively), as a result of first gas production at the MBH and MDA fields starting in the fourth quarter of 2022.

Expenses

Operating

Primary drivers of our Atlantic operating expenses in the first nine months of 2023 were repairs and maintenance, vessel and helicopter costs, and workforce. In the third quarter of 2023, operating costs decreased slightly from 2022 to $47 million. Operating expenses in the first nine months of 2023 increased $44 million, to $190 million, due to the ramp-up of the West White Rose project leading up to the start of major construction in late March, costs related to turnaround work on the SeaRose FPSO in the second quarter and costs associated with preparation and maintenance activities for the Terra Nova FPSO. Per-unit operating expenses increased in the nine months ended September 30, 2023, compared with 2022 due to lower sales volumes combined with the same factors that impacted total operating expenses.

Primary drivers of our Asia Pacific operating expenses in the first nine months of 2023 were repairs and maintenance, insurance and workforce. Total operating expenses declined slightly in the three months ended September 30, 2023 and increased slightly on a year-to-date basis, compared with the same periods in 2022. Per-unit operating expenses were consistent in the third quarter of 2023 compared with 2022. Year-to-date, per-unit operating expenses increased compared with 2022 mainly due to lower sales volumes.

Transportation

Transportation costs in the Atlantic region decreased in the three and nine months ended September 30, 2023, compared with the same periods of 2022 and includes the cost of transporting crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  30

Netbacks (1)

	Three Months Ended September 30, 2023
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia (2)		Total Offshore
Sales Price		107.99	80.61		58.68		79.27
Royalties		2.56	6.06		11.59		6.80
Transportation and Blending		(0.53)	—		—		(0.06)
Operating Expenses		65.91	6.51		11.66		14.66
Netback		40.05	68.04		35.43		57.87

	Three Months Ended September 30, 2022
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia (2)		Total Offshore
Sales Price		158.42	80.68		66.97		88.02
Royalties		2.86	4.63		26.80		7.94
Transportation and Blending		5.86	—		—		0.72
Operating Expenses		47.23	6.73		12.05		12.55
Netback		102.47	69.32		28.12		66.81

	Nine Months Ended September 30, 2023
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia (2)		Total Offshore
Sales Price		108.48	81.09		58.71		79.42
Royalties		4.94	5.05		14.44		7.20
Transportation and Blending		4.02	—		—		0.51
Operating Expenses		78.61	7.60		10.72		17.37
Netback		20.91	68.44		33.55		54.34

	Nine Months Ended September 30, 2022
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia (2)		Total Offshore
Sales Price		142.96	81.70		72.50		91.32
Royalties		(1.16)	4.50		33.51		7.47
Transportation and Blending		3.54	—		—		0.63
Operating Expenses		36.79	5.71		13.06		12.24
Netback		103.79	71.49		25.93		70.98

(1)The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

(2)Reported sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.

Exploration Expense

We recorded exploration expense of $6 million in the first nine months of 2023 (2022 – $91 million). Exploration expense in 2022 was primarily due to a $58 million write-off related to our decision not to pursue development at block 15/33 in China.

DD&A

In the three and nine months ended September 30, 2023, total Offshore DD&A was $130 million and $349 million, respectively (2022 – $132 million and $441 million, respectively). The average depletion rate in the three and nine months ended September 30, 2023, was $26.29 per BOE and $26.00 per BOE, respectively (2022 – $30.89 per BOE and $30.29 per BOE, respectively).

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  31

DOWNSTREAM

Canadian Manufacturing

In the third quarter of 2023, we:

•Delivered safe and reliable operations.

•Had very strong performance at the Upgrader and Lloydminster Refinery, achieving crude utilization of 98 percent (2022 – 89 percent).

•Generated Operating Margin of $170 million, a decrease of $76 million compared with 2022, primarily due to lower synthetic crude oil prices relative to crude oil feedstock, and lower refined product prices, partially offset by increased production volumes.

Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Revenues	1,805	2,168	4,676	6,020
Purchased Product	1,480	1,750	3,656	5,065
Gross Margin (1)	325	418	1,020	955
Expenses
Operating	155	172	471	534
Operating Margin	170	246	549	421
Depreciation, Depletion and Amortization	50	42	136	164
Segment Income (Loss)	120	204	413	257

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

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  32

Select Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Total Canadian Manufacturing
Heavy Crude Oil Unit Throughput Capacity (1)(Mbbls/d)	110.5	110.5	110.5	110.5
Heavy Crude Oil Unit Throughput (Mbbls/d)	108.4	98.5	100.8	92.5
Crude Utilization (percent)	98	89	91	84
Total Production (Mbbls/d)	122.4	111.0	114.6	104.2
Synthetic Crude Oil	53.2	47.7	47.9	46.3
Asphalt	15.7	15.5	15.6	13.3
Diesel	13.8	10.5	12.8	9.0
Other	34.1	32.2	33.4	30.8
Ethanol	5.6	5.1	4.9	4.8
Refining Margin (2)($/bbl)	29.17	38.88	33.48	29.69
Unit Operating Expense (3)($/bbl)	11.60	11.72	12.44	13.95
Lloydminster Upgrader
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)	81.5	81.5	81.5	81.5
Heavy Crude Oil Unit Throughput (4)(Mbbls/d)	80.6	71.3	72.9	68.8
Crude Utilization (percent)	99	87	89	84
Production (Mbbls/d)	88.9	78.6	81.8	75.7
Refining Margin (2) ($/bbl)	29.12	38.33	34.82	30.49
Unit Operating Expense (3) ($/bbl)	11.29	11.25	12.35	12.59
Upgrading Differential (5)($/bbl)	22.31	39.36	29.63	28.69
Lloydminster Refinery
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)	29.0	29.0	29.0	29.0
Heavy Crude Oil Unit Throughput (Mbbls/d)	27.8	27.2	27.9	23.7
Crude Utilization(percent)	96	94	96	82
Production (Mbbls/d)	27.9	27.3	27.9	23.7
Refining Margin(2)($/bbl)	29.30	40.33	29.98	27.38
Unit Operating Expense (3) ($/bbl)	12.51	12.96	12.70	17.89
Ethanol
Ethanol Production (Mbbls/d)	5.6	5.1	4.9	4.8
Rail
Volumes Loaded (6) (Mbbls/d)	—	1.4	1.2	1.5

(1)Based on crude oil name plate capacity.

(2)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader and commercial fuels business for the three and nine months ended September 30, 2023, were $1.6 billion and $4.2 billion, respectively (2022 – $998 million and $2.9 billion, respectively, from the Upgrader). Revenues from the Lloydminster Refinery for the three and nine months ended September 30, 2023 were $325 million and $739 million, respectively (2022 – $387 million and $816 million, respectively).

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

(4)Upgrader throughput includes diluent returned to the field.

(5)Based on benchmark price differential between heavy oil feedstock and synthetic crude.

(6)Total crude oil volumes loaded and transported outside of Alberta, Canada.

In the third quarter of 2023, Canadian Manufacturing throughput increased 9.9 thousand barrels per day from 2022 to 108.4 thousand barrels per day, and total production increased 11.4 thousand barrels per day to 122.4 thousand barrels per day due to:

•Strong performance at the Upgrader in 2023 combined with temporary unplanned outages in the third quarter of 2022 resulted in crude utilization of 99 percent (2022 – 87 percent).

•Continued strong performance at the Lloydminster Refinery with throughput of 27.8 thousand barrels per day compared with 27.2 thousand barrels per day.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  33

In the nine months ended September 30, 2023, Canadian Manufacturing throughput increased by 8.3 thousand barrels per day to 100.8 thousand barrels per day, and total production increased by 10.4 thousand barrels per day to 114.6 thousand barrels per day compared with the same period in 2022 due to the same factors as discussed above, combined with:

•Increased throughput at the Upgrader which rose 4.1 thousand barrels per day to 72.9 thousand barrels per day due to planned turnarounds and unplanned outages in 2022, partially offset by an unplanned outage in the second quarter of 2023 and unplanned outages and cold weather impacts in the fourth quarter of 2022 that continued to impact Cenovus in early January 2023.

•Higher crude utilization at the Lloydminster Refinery, which increased to 96 percent (2022 – 82 percent) primarily due to a temporary unplanned outage in the third quarter of 2022 and a planned turnaround in the second quarter of 2022.

Revenues and Gross 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 feedstock.

The Lloydminster Refinery processes blended heavy crude oil into asphalt 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 increase during paving season, which typically runs from May through October each year.

The Upgrader and Lloydminster Refinery source crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil production.

In the third quarter of 2023, total revenues from Canadian Manufacturing decreased by $363 million to $1.8 billion compared with 2022, due to lower synthetic crude, refined product and industrial product pricing and the disposition of our retail fuels business in the third quarter of 2022. The decrease was partially offset by higher production compared with the same period in 2022. In the first nine months of 2023, revenues decreased by $1.3 billion to $4.7 billion due to the reasons discussed above. In the three and nine months ended September 30, 2023, synthetic crude oil benchmark prices decreased 15 percent and 22 percent to US$84.95 per barrel and US$79.93 per barrel, respectively, compared with 2022.

Gross margin decreased $93 million to $325 million in the third quarter of 2023 compared with 2022 due to the factors noted above, in addition to weakened upgrading differentials and lower refining margins.

Gross margin increased $65 million to $1.0 billion in the first nine months of 2023 compared with 2022 due to a higher upgrading differential, improved refining margins and increased throughput at the Upgrader and Lloydminster Refinery. The increase was partially offset by the disposition of our retail fuels network in the third quarter of 2022. Improved refining and upgrading margins were primarily driven by lower heavy crude oil feedstock cost. In the three and nine months ended September 30, 2023, WCS prices decreased by 3 percent and 27 percent to US$69.35 per barrel and US$59.82 per barrel, respectively, compared with 2022.

See the Specified Financial Measures Advisory of this MD&A for revenues and gross margin by asset.

Operating Expenses

Primary drivers of operating expenses in the first nine months of 2023 were repairs and maintenance, workforce, chemical, electricity and energy costs.

Total and per-unit operating costs decreased in the three and nine months ended September 30, 2023, compared with 2022, mainly due to the disposition of our retail fuels network in the third quarter of 2022, lower energy costs and higher throughput. Year-to-date costs also decreased due to planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter of 2022. The decreases were partially offset by higher repairs and maintenance spend at the Upgrader in the third quarter of 2023. Per-unit operating expenses apply only to operating costs and throughput at the Upgrader and Lloydminster Refinery.

DD&A

In the three and nine months ended September 30, 2023, DD&A was $50 million and $136 million, respectively (2022 – $42 million and $164 million, respectively).

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  34

U.S. Manufacturing

In the third quarter of 2023, we:

•Delivered safe operations.

•Generated Operating Margin of $752 million, an increase of $508 million compared with 2022, primarily due to the Toledo Acquisition, higher refining margins and the Toledo and Superior refineries being operational. We continue to find ways to integrate the Lima and Toledo refineries to optimize our operating margin.

•Progressed the restart of the FCCU at the Superior Refinery, which was brought online in early October, and generated crude throughput of 32.2 thousand barrels per day.

•Achieved crude utilization of 88 percent (2022 – 87 percent).

•Commenced a planned turnaround at the Borger Refinery in late September. The turnaround is expected to be completed in the fourth quarter of 2023.

•Invested capital of $88 million.

Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Revenues (1)	7,853	8,705	19,546	23,688
Purchased Product (1)	6,467	7,930	16,729	20,351
Gross Margin (2)	1,386	775	2,817	3,337
Expenses
Operating	623	608	1,904	1,757
Realized (Gain) Loss on Risk Management	11	(77)	6	120
Operating Margin	752	244	907	1,460
Unrealized (Gain) Loss on Risk Management	(2)	(8)	(13)	(22)
Depreciation, Depletion and Amortization	109	91	314	259
Segment Income (Loss)	645	161	606	1,223

(1)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

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

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  35

Select Operating Results

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Total U.S. Manufacturing
Crude Oil Unit Throughput Capacity (1)(Mbbls/d)	635.2	502.5	635.2	502.5
Crude Oil Unit Throughput (Mbbls/d)	555.9	435.0	453.3	405.3
Heavy Crude Oil	210.6	145.2	165.4	135.2
Light and Medium Crude Oil	345.3	289.8	287.9	270.1
Crude Utilization (2)(percent)	88	87	75	81
Total Refined Product Production (Mbbls/d)	583.6	461.6	475.2	426.7
Gasoline	267.6	212.5	218.3	202.0
Distillates (3)	196.1	172.7	165.2	155.3
Asphalt	24.7	10.3	19.2	8.8
Other	95.2	66.1	72.5	60.6
Refining Margin (4)($/bbl)	27.10	18.98	22.77	29.94
Unit Operating Expense (5) ($/bbl)	12.17	14.90	15.39	15.77
Lima Refinery
Crude Oil Unit Throughput Capacity (1)(6)(Mbbls/d)	178.7	175.0	178.7	175.0
Crude Oil Unit Throughput (Mbbls/d)	146.2	164.2	159.7	153.5
Crude Utilization (percent)	82	94	89	88
Toledo Refinery (7)
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)	160.0	80.0	160.0	80.0
Crude Oil Unit Throughput (Mbbls/d)	143.5	46.6	64.5	48.5
Crude Utilization (2) (percent)	90	58	45	61
Superior Refinery
Crude Oil Unit Throughput Capacity (1)(Mbbls/d)	49.0	—	49.0	—
Crude Oil Unit Throughput (Mbbls/d)	32.2	—	19.3	—
Crude Utilization (2) (percent)	66	—	59	—
Wood River and Borger Refineries (8)
Crude Oil Unit Throughput Capacity (1)(Mbbls/d)	247.5	247.5	247.5	247.5
Crude Oil Unit Throughput (Mbbls/d)	234.0	224.2	209.8	203.3
Crude Utilization(percent)	95	91	85	82

(1)Based on crude oil name plate capacity.

(2)The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023.

(3)Includes diesel and jet fuel.

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

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

(6)The name plate capacity at the Lima Refinery increased effective January 1, 2023.

(7)On February 28, 2023, we purchased the remaining 50 percent interest in BP-Husky Refining LLC.

(8)Represents Cenovus’s 50 percent interest in the non-operated Wood River and Borger refinery operations.

In the third quarter of 2023, U.S. Manufacturing throughput increased 120.9 thousand barrels per day from 2022 to 555.9 thousand barrels per day, and total refined product production increased 122.0 thousand barrels per day to 583.6 thousand barrels per day due to:

•Full ownership of the Toledo Refinery, that occurred on February 28, 2023. Crude throughput increased 96.9 thousand barrels per day to 143.5 thousand barrels per day in the third quarter of 2023 compared with the same period in 2022. The increase was also due to a significant planned turnaround in the second quarter of 2022 that was completed in the third quarter of 2022 and the incident that occurred in September 2022. Crude utilization at the Toledo Refinery was 90 percent (2022 – 58 percent).

•Continued work on the restart of the FCCU at the Superior Refinery, which was brought online in early October. Refined product output averaged 33.1 thousand barrels per day in the third quarter of 2023.

•Strong performance from the Wood River Refinery, combined with a planned turnaround that commenced in September 2022. Total throughput for the Wood River and Borger refineries increased by 9.8 thousand barrels per day to 234.0 thousand barrels per day in the third quarter of 2023.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  36

The increases were partially offset by unplanned outages and planned maintenance at the Lima Refinery in the third quarter of 2023.

In the first nine months of 2023, U.S. Manufacturing crude throughput increased 48.0 thousand barrels per day to 453.3 thousand barrels per day, and total refined product production increased 48.5 thousand barrels per day to 475.2 thousand barrels per day primarily related to operations at the Toledo and Superior refineries and for the same reasons discussed above, as well as:

•Increased throughput at the Wood River Refinery primarily due to the turnarounds in 2022 having a larger impact than in 2023 and the decision in the first quarter of 2022 to operate at reduced rates to optimize margins as market conditions dictated. Combined crude utilization for the Wood River and Borger refineries for the nine months ended September 30, 2023, was 85 percent (2022 – 82 percent).

•Lima Refinery’s performance, achieving crude utilization of 89 percent during the nine months ended September 30 (2022 – 88 percent). Crude throughput increased 6.2 thousand barrels per day compared with the first nine months of 2022. The increase was due to feedstock pipeline and other temporary outages in 2022 and the decision to operate the refinery at reduced rates in early 2022 due to low market crack spreads. The increase was partially offset by the planned and unplanned outages discussed above.

Increased throughput was partially offset by a planned turnaround at the Borger Refinery in March and April 2023 and temporary unplanned outages in the second quarter of 2023. The turnaround and outages had a larger impact on throughput than the turnaround completed in the spring of 2022.

Revenues and Gross Margin

Market crack spreads do not precisely mirror the configuration and product output of our refineries; 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. 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. In the three and nine months ended September 30, 2023, the Chicago 3-2-1 crack spread decreased 33 percent and 19 percent, respectively, to US$26.06 per barrel and US$27.83 per barrel, respectively, compared with 2022. In the three and nine months ended September 30, 2023, the Group 3 crack spread declined 4 percent and 3 percent, respectively, to US$36.96 per barrel and US$33.36 per barrel, respectively, compared with 2022.

Revenues decreased $852 million and $4.1 billion, respectively, in the three and nine months ended September 30, 2023, compared with 2022. The decreases were primarily due to lower refined product pricing, partially offset by higher production, primarily related to our Toledo and Superior refineries. Benchmark gasoline prices fell 13 percent and 19 percent, respectively, in the three and nine months ended September 30, 2023, compared with the same periods in 2022. Benchmark diesel prices also fell in the quarter and on a year-to-date basis, by US$34.47 and US$34.30, respectively, compared with the same periods in 2022.

Gross margin increased $611 million in the three months ended September 30, 2023 compared with the same period in 2022. The increase was largely due to higher refined product production, lower cost of feedstock processed and weakened RINs pricing of US$7.42 per barrel (2022 – US$8.11 per barrel). Gross margin decreased by $520 million in the nine months ended September 30, 2023 primarily due to lower market crack spreads, partially offset by higher production.

Operating Expenses

Primary drivers of operating expenses in the first nine months of 2023 were repairs and maintenance, and workforce.

Operating expenses increased $15 million in the three months ended September 30, 2023 compared with the same period in 2022 primarily due to operations at the Toledo and Superior refineries. The increases were due to:

•Higher chemical costs primarily due to increased consumption at the Toledo and Superior refineries and higher chemical pricing.

•Increased workforce costs at the Superior Refinery for restart and ramp-up activities and higher overall workforce costs related to the Toledo Acquisition, partially offset by increased workforce costs at the Toledo Refinery during the significant planned turnaround in 2022.

•Increased repairs and maintenance spend at the Lima Refinery.

The increases were partially offset by lower energy costs related to the decline in natural gas benchmark pricing.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  37

Operating expenses increased by $147 million in the nine months ended September 30, 2023, compared with the same period in 2022 due to the reasons discussed above. The increase was partially offset by lower repairs and maintenance costs due to the significant planned turnaround at the Toledo Refinery in the second and third quarters of 2022 and lower energy costs, primarily due to the decline in natural gas benchmark pricing discussed above.

Per-unit operating expenses decreased $2.73 per barrel and $0.38 per barrel, respectively, in the three and nine months ended September 30, 2023, compared with the same period in 2022, primarily due to higher throughput and lower energy costs as noted above.

(Gain) Loss on Risk Management

In the three and nine months ended September 30, 2023, we incurred realized risk management losses of $11 million and $6 million, respectively (2022 – gains of $77 million and losses of $120 million, respectively), due to the settlement of benchmark prices relative to our risk management contract prices. In the three and nine months ended September 30, 2023, we recorded unrealized risk management gains of $2 million and $13 million, respectively (2022 – $8 million and $22 million, respectively), on our crude oil and refined products financial instruments primarily due to changes to forward benchmark pricing relative to our risk management contract prices that related to future periods.

DD&A

U.S. Manufacturing DD&A in the three and nine months ended September 30, 2023, was $109 million and $314 million, respectively, compared with $91 million and $259 million, respectively, in 2022. The increase is primarily due to the Toledo Acquisition.

CORPORATE AND ELIMINATIONS

Risk Management

In the three and nine months ended September 30, 2023, our corporate risk management activities resulted in:

•A realized risk management gain of $1 million and a loss of $2 million, respectively (2022 – losses of $16 million and $23 million, respectively), related to foreign exchange risk management contracts.

•Unrealized risk management losses of $20 million and $71 million, respectively (2022 – gains of $16 million $14 million, respectively), related to renewable power contracts and foreign exchange risk management contracts.

Financial Results

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
General and Administrative	292	128	617	545
Finance Costs	106	207	493	631
Interest Income	(33)	(21)	(100)	(44)
Integration and Transaction Costs	12	27	49	79
Foreign Exchange (Gain) Loss, Net	133	316	7	406
Revaluation (Gain) Loss	—	(549)	33	(549)
Re-measurement of Contingent Payments	67	(109)	83	142
(Gain) Loss on Divestiture of Assets	—	60	(11)	(244)
Other (Income) Loss, Net	(22)	(59)	(42)	(467)
	555	—	1,129	499

General and Administrative

Primary drivers of our general and administrative expenses in the first nine months of 2023 were employee long-term incentive costs, workforce costs and information technology costs. General and administrative expenses increased in the three months ended September 30, 2023, compared with 2022 primarily due to higher long-term incentive costs of $151 million (2022 – recovery of $1 million). In the nine months ended September 30, 2023, general and administrative expenses increased compared with 2022 due to higher information technology, building operating costs, workforce, indigenous housing initiative costs and long-term incentive costs of $196 million (2022 – $184 million).

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  38

Finance Costs

Finance costs were lower in the three and nine months ended September 30, 2023, compared with the same periods in 2022, primarily due to debt purchases in 2022 that lowered the Company’s average long-term debt and interest expenses. In the third quarter of 2023, we purchased long-term debt with an aggregate principal amount of US$1.0 billion at a discount of $84 million compared with a purchase of long-term debt with an aggregate principal amount of US$2.2 billion at a discount of $4 million in the third quarter of 2022. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.

The weighted average interest rate on outstanding debt for the three and nine months ended September 30, 2023, was 4.7 percent (2022 – 4.8 percent and 4.7 percent, respectively).

Integration and Transaction Costs

In the three and nine months ended September 30, 2023, we incurred integration and transaction costs of $12 million and $49 million, respectively, associated with the Toledo Acquisition.

We incurred integration and transaction costs of $27 million and $79 million in the three and nine months ended September 30, 2022, respectively, not including capital expenditures, primarily related to the integration of Cenovus and Husky Energy Inc.

Foreign Exchange (Gain) Loss, Net

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Unrealized Foreign Exchange (Gain) Loss	59	298	(99)	419
Realized Foreign Exchange (Gain) Loss	74	18	106	(13)
	133	316	7	406

In the third quarter of 2023, unrealized foreign exchange losses were mainly related to the translation of U.S. denominated debt. In the first nine months of 2023, unrealized foreign exchange gains were primarily caused by the translation of U.S. denominated debt. Realized foreign exchange losses in both periods in 2023 were mainly related to the settlement of fixed-term debt.

Revaluation (Gain) Loss

Cenovus recognized a revaluation loss of $33 million in the first quarter of 2023 as part of the Toledo Acquisition. In the third quarter of 2022, Cenovus recognized a revaluation gain of $549 million as part of the Sunrise Acquisition. As required by IFRS 3, “Business Combinations”, when an acquirer achieves control in stages, the previously held interest is remeasured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). Refer to Note 3 of the interim Consolidated Financial Statements for further details.

Re-measurement of Contingent Payments

In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments to bp Canada for up to eight quarters subsequent to August 31, 2022, if the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The maximum cumulative variable payment is $600 million. Refer to Note 15 of the interim Consolidated Financial Statements for further details.

The contingent payment is accounted for as a financial option with changes in fair value recognized in net earnings (loss). As at September 30, 2023, the fair value of the variable payment was estimated to be $295 million, resulting in non-cash re-measurement losses of $67 million and $83 million in the three and nine months ended September 30, 2023, respectively (three months ended September 30, 2022 – gains of $109 million).

In the nine months ended September 30, 2023, we paid $207 million under this agreement. The latest quarterly payment of $92 million was made on October 30, 2023. The payments are recognized in cash from (used in) investing activities with no impact to Adjusted Funds Flow. As of September 30, 2023, average estimated WCS forward pricing for the remaining term of the variable payment is approximately $89.81 per barrel. As at September 30, 2023, the remaining payments are considered current liabilities. The maximum payment over the remaining four quarters of the contract is $301 million.

The contingent payment associated with the transaction with ConocoPhillips related to its 50 percent interest in the FCCL Partnership ended on May 17, 2022, and the final payment was made in July 2022.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  39

(Gain) Loss on Divestiture of Assets

We had no material divestitures in the three and nine months ended September 30, 2023. In the three months ended September 30, 2022, we recognized a loss on divestiture of assets of $60 million primarily related to the disposition of our retail fuels network. In the nine months ended September 30, 2022, we recognized a gain on divestiture of assets of $244 million due to the sale of our Tucker and Wembley assets, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions, and the retail divestiture.

Other (Income) Loss, Net

In the three and nine months ended September 30, 2023, other income was $22 million and $42 million, respectively (2022 – $59 million and $467 million, respectively). Other income in the first nine months of 2022 was primarily due to insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region.

DD&A

DD&A for the three and nine months ended September 30, 2023, was $19 million and $59 million, respectively (2022 – $27 million and $86 million, respectively).

Income Taxes

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Current Tax
Canada	484	187	941	1,124
United States	4	(185)	4	96
Asia Pacific	68	64	152	173
Other International	7	10	19	10
Total Current Tax Expense (Recovery)	563	76	1,116	1,403
Deferred Tax Expense (Recovery)	(2)	568	(416)	625
	561	644	700	2,028

For the nine months ended September 30, 2023, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The decline in current income tax expense for the nine months ended September 30, 2023, was due to lower earnings compared with 2022. The effective tax rate in the first nine months of 2023 was 17.2 percent (2022 – 26.4 percent). The lower rate is primarily due to the deferred tax recovery recorded in the first quarter of 2023 related to the step-up in the tax basis on the Toledo Acquisition. Excluding the impact of the Toledo Acquisition, the effective tax rate in 2023 would be consistent with the statutory rate.

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.

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 rates and other legislation.

LIQUIDITY AND CAPITAL RESOURCES

Our capital allocation framework enables us to strengthen our balance sheet, provide flexibility in both high and low commodity price environments, and deliver value to shareholders. The framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to common shareholders, with lower leverage and a lower risk profile.

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 Investor Service, DBRS Morningstar and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  40

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Cash From (Used In)
Operating Activities	2,738	4,089	4,442	8,433
Investing Activities	(1,101)	(690)	(4,015)	(1,144)
Net Cash Provided (Used) Before Financing Activities	1,637	3,399	427	7,289
Financing Activities	(2,600)	(3,822)	(3,674)	(6,926)
Effect of Foreign Exchange on Cash and Cash Equivalents	58	224	(15)	258
Increase (Decrease) in Cash and Cash Equivalents	(905)	(199)	(3,262)	621
As at ($ millions)			September 30, 2023	December 31, 2022
Cash and Cash Equivalents			1,262	4,524
Total Debt			7,238	8,806

Cash From (Used in) Operating Activities

For the three months ended September 30, 2023, cash from operating activities was $2.7 billion compared with $4.1 billion in the same period in 2022. The decrease was mainly due to changes in non-cash working capital, partially offset by higher Operating Margin. During the three months ended September 30, 2023, the net change in non-cash working capital decreased cash by $641 million primarily due to higher accounts receivable, inventories and higher cash taxes, mainly related to rising commodity pricing. The change was partially offset by higher accounts payable, primarily due to higher crude throughput. During the same period in 2022, the net change in non-cash working capital resulted in an increase in cash from operating activities of $1.2 billion.

For the nine months ended September 30, 2023, cash from operating activities was $4.4 billion (2022 – $8.4 billion). The significant decrease was primarily due to lower Operating Margin and a working capital build. During the nine months ended September 30, 2023, the net change in non-cash working capital decreased cash by $2.1 billion, related primarily to higher commodity pricing and driven largely by the payment of the December 31, 2022, income tax liability of $1.2 billion in the first quarter of 2023.

Cash From (Used in) Investing Activities

Cash used in investing activities increased in the third quarter of 2023 compared with 2022 due to no divestitures in the third quarter of 2023 compared with the sale of our retail fuels network in the third quarter of 2022, higher capital spending in the third quarter of 2023 and a decrease in non-cash working capital. The increase was partially offset by lower acquisition costs in 2023 with the Sunrise Acquisition in the third quarter of 2022.

Cash used in investing activities increased significantly in the first nine months of 2023 compared with 2022. The increase was due to higher capital spending, the closing of the Toledo Acquisition in the first quarter of 2023 and lower proceeds from divestitures as 2022 included the sales of our retail fuels network, Tucker and Wembley assets. The increase was partially offset by the Sunrise Acquisition in the third quarter of 2022. Additionally, non-cash working capital decreased in 2023 primarily due to the Sunrise contingent payment.

Cash From (Used in) Financing Activities

Cash used in financing activities decreased in the third quarter of 2023, largely due to lower purchases of unsecured notes compared with the same period in 2022, partially offset by the payment of the warrant obligation. In the third quarter of 2023, we purchased US$1.0 billion of unsecured notes due between 2029 and 2047 at a discount of $84 million. In the third quarter of 2022, we purchased US$2.2 billion of unsecured notes due between 2025 and 2043 at a discount of $4 million.

Cash used in financing activities decreased in the nine months ended September 30, 2023, compared with the same period in 2022 primarily due to reasons noted above, combined with additional long-term debt purchases in 2022 of $750 million and US$402 million. The decreases were also caused by higher common share purchases through our NCIB in 2022, partially offset by an increase in common share base dividend payments in 2023. In 2023, we paid base dividends of $0.385 per share on our common shares (2022 – $0.245 per share).

In the three months ended September 30, 2023, we issued net short-term borrowings of $14 million (2022 – net payments of $2 million). In the nine months ended September 30, 2023, we made net payments of $101 million on short-term borrowings (2022 – $81 million, net).

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  41

Working Capital

Excluding the contingent payment, our adjusted working capital at September 30, 2023, was $3.8 billion (December 31, 2022 – $4.7 billion).

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

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. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds Cenovus has after financing its capital programs. 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 plan.

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Cash From (Used in) Operating Activities	2,738	4,089	4,442	8,433
(Add) Deduct:
Settlement of Decommissioning Liabilities	(68)	(55)	(157)	(101)
Net Change in Non-Cash Working Capital	(641)	1,193	(2,142)	(98)
Adjusted Funds Flow	3,447	2,951	6,741	8,632
Capital Investment	1,025	866	3,128	2,434
Free Funds Flow	2,422	2,085	3,613	6,198
Add (Deduct):
Base Dividends Paid on Common Shares	(264)	(205)
Dividends Paid on Preferred Shares	—	(9)
Settlement of Decommissioning Liabilities	(68)	(55)
Principal Repayment of Leases	(70)	(78)
Acquisitions, Net of Cash Acquired	(32)	(389)
Proceeds From Divestitures	1	407
Excess Free Funds Flow	1,989	1,756

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. We have set an ultimate Net Debt Target of $4 billion, which serves as our floor on Net Debt. Our $4 billion Net Debt Target represents a Net Debt to Adjusted Funds Flow Ratio Target of approximately 1.0 times at the bottom of the commodity pricing cycle. We plan to return incremental value to shareholders through share buybacks and/or variable dividends as follows:

•When Net Debt is less than $9 billion and above $4 billion at quarter-end, we will target to allocate 50 percent of the Excess Free Funds Flow achieved in the following quarter to shareholder returns, while still continuing to deleverage the balance sheet until we reach the Net Debt Target of $4 billion.

•When Net Debt is above $9 billion at quarter-end, we plan to allocate all of the following quarter’s Excess Free Funds Flow to deleveraging the balance sheet.

•When Net Debt is at the $4 billion floor at quarter-end, we will target to return 100 percent of the following quarter’s Excess Free Funds Flow to shareholder returns.

Share buybacks are executed opportunistically, driven by return thresholds. Where the value of share buybacks in a quarter is less than the targeted value of returns, the remainder will be delivered through a variable dividend payable for that quarter, if the remainder is greater than $50 million. Where the value of share buybacks in a quarter is greater than or equal to the targeted value of returns, no variable dividend will be paid for that quarter.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  42

On June 30, 2023, our long-term debt was $8.5 billion, resulting in a Net Debt position of $6.4 billion. Therefore, our returns to shareholders target for the three months ended September 30, 2023, was 50 percent of the current quarter’s Excess Free Funds Flow of $2.0 billion. As such, our Target Return was $1.0 billion. We made returns to shareholders through share buybacks of $361 million and warrant purchase payments of $600 million. Returns to shareholders were within $50 million of our Target Return, as such no variable dividend was declared for the fourth quarter.

	Three Months Ended
($ millions)	September 30, 2023	June 30, 2023	March 31, 2023
Excess Free Funds Flow	1,989	505	(499)
Target Return	995	253	—
Less: Purchase of Common Shares Under NCIBs	(361)	(310)	(40)
Less: Payment for Purchase of Warrants	(600)	—	—
Amount Available for Variable Dividend	34	—	—

At September 30, 2023, our Net Debt position was $6.0 billion and as a result our returns to shareholders target for the three months ended December 31, 2023, will be 50 percent of the fourth quarter’s Excess Free Funds Flow.

Short-Term Borrowings

As at September 30, 2023, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$10 million (C$14 million) (December 31, 2022 – the Company’s proportionate share drawn was US$85 million (C$115 million)). There were no direct borrowings on our uncommitted demand facilities as at September 31, 2023, or December 31, 2022.

Long-Term Debt, Including Current Portion

Long-term debt, including the current portion, as at September 30, 2023, was $7.2 billion (December 31, 2022 – $8.7 billion). This includes U.S. dollar denominated unsecured notes of US$3.8 billion, or C$5.1 billion (December 31, 2022 – US$4.8 billion, or C$6.5 billion) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2022 – $2.0 billion). The decrease in long‑term debt was primarily due to the third quarter purchase of unsecured notes with an aggregate principal amount of US$1.0 billion at a discount of $84 million.

As at September 30, 2023, 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 September 30, 2023:

($ millions)	Maturity	Amount Available
Cash and Cash Equivalents	n/a	1,262
Committed Credit Facility (1)
Revolving Credit Facility – Tranche A	November 10, 2026	3,700
Revolving Credit Facility – Tranche B	November 10, 2025	1,800
Uncommitted Demand Facilities
Cenovus Energy Inc. (2)	n/a	1,082
WRB (3)	n/a	291

(1)No amounts were drawn on the committed credit facility as at September 30, 2023 (December 31, 2022 - $nil).

(2)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 September 30, 2023, there were outstanding letters of credit aggregating to $353 million (December 31, 2022 – $490 million) and no direct borrowings (December 31, 2022 – $nil).

(3)Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at September 30, 2023, US$10 million (C$14 million) of this capacity was drawn (December 31, 2022 – US$85 million (C$115 million)).

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 well below this limit.

Base Shelf Prospectus

We have a base shelf prospectus that allows us to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere, where permitted by law. We plan to renew the base shelf prospectus that will expire in November 2023. As at September 30, 2023, US$4.7 billion remained available under the base shelf prospectus for permitted offerings (December 31, 2022 – US$4.7 billion). Offerings under the base shelf prospectus are subject to market availability.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  43

Financial Metrics

We monitor our capital structure and financing requirements using the Net Debt to Capitalization Ratio, Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio. Refer to Note 13 of the interim Consolidated Financial Statements for further details.

We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholders 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 of capitalized interest, interest income, 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, revaluation (gain) loss, re-measurement of contingent payments, (gain) loss on divestiture of assets, 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	September 30, 2023	December 31, 2022
Net Debt to Capitalization Ratio (percent)	17	13
Net Debt to Adjusted Funds Flow Ratio (times)	0.7	0.4
Net Debt to Adjusted EBITDA Ratio (times)	0.6	0.3

Our Net Debt to Adjusted Funds Flow Ratio and our Net Debt to Adjusted EBITDA Ratio Targets are approximately 1.0 times at the bottom of the commodity price cycle, which we believe is approximately US$45 per barrel WTI. This ratio may fluctuate periodically outside the range due to factors such as persistently high or low commodity prices. 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, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares.

Our Net Debt to Capitalization Ratio as at September 30, 2023, increased compared with December 31, 2022, primarily due to higher Net Debt.

Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at September 30, 2023, increased compared with December 31, 2022, as a result of higher Net Debt and lower Operating Margin. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt.

Share Capital and Stock-Based Compensation Plans

Our common shares and Cenovus Warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”). Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX.

As at September 30, 2023, there were approximately 1,885.6 million common shares outstanding (December 31, 2022 – 1,909.2 million common shares) and 36 million preferred shares outstanding (December 31, 2022 – 36 million preferred shares). Refer to Note 18 of the interim Consolidated Financial Statements for further details.

Cenovus has an NCIB program to purchase up to 136.7 million common shares during the period from November 9, 2022, to November 8, 2023.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
Common Shares Purchased Under NCIBs (millions of common shares) (1)	14	29.1	29	96.9
Weighted Average Price per Common Share ($)	26.18	22.60	24.19	22.10
Purchase of Common Shares Under NCIB ($ millions)	(361)	(659)	(711)	(2,143)

(1)Common shares were subsequently cancelled after purchase.

From October 1, 2023, to October 30, 2023, the Company purchased an additional 3.3 million common shares for $89 million. As at October 30, 2023, the Company can further purchase up to 92.5 million common shares under the existing NCIB. The current NCIB will expire on November 8, 2023.

On November 1, 2023, we received approval from the Board of Directors to apply to the TSX for an additional NCIB program. Subject to acceptance by the TSX, the Company will be able to purchase up to approximately 133 million common shares for a period of twelve months.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  44

As at September 30, 2023, there were approximately 7.9 million Cenovus Warrants outstanding (December 31, 2022 – 55.7 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 18 of the interim Consolidated Financial Statements for further details.

On June 14, 2023, we purchased and cancelled 45.5 million outstanding Cenovus Warrants. The price for each warrant purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million. We also recorded $2 million of transaction costs. This purchase represented 84 percent of Cenovus’s outstanding warrants. During the three months ended September 30, 2023, we paid $600 million related to the purchased warrants. The remaining amount must be paid by January 5, 2024.

Refer to Note 20 of the interim Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans.

Our outstanding share data is as follows:

As at October 30, 2023	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	1,883,596	n/a
Cenovus Warrants	7,917	n/a
Series 1 First Preferred Shares	10,740	n/a
Series 2 First Preferred Shares	1,260	n/a
Series 3 First Preferred Shares	10,000	n/a
Series 5 First Preferred Shares	8,000	n/a
Series 7 First Preferred Shares	6,000	n/a
Stock Options	12,922	7,646
Other Stock-Based Compensation Plans	19,048	1,662

Common Share Dividends

In the third quarter of 2023, we paid base dividends of $264 million or $0.140 per common share (2022 – $205 million or $0.105 per common share). In the first nine months of 2023, we paid base dividends of $729 million or $0.385 per common share (2022 – $481 million or $0.245 per common share). No variable dividend was declared for the third quarter of 2023.

The Board declared a fourth quarter base dividend of $0.140 per common share, payable on December 29, 2023, to common shareholders of record as at December 15, 2023.

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

Cumulative Redeemable Preferred Share Dividends

In the three and nine months ended September 30, 2023, dividends of $nil and $27 million, respectively, were paid on the series 1, 2, 3, 5 and 7 preferred shares (2022 – $9 million and $26 million, respectively). The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly. The Board declared a fourth quarter dividend on the series 1, 2, 3, 5 and 7 preferred shares of $9 million, payable on January 2, 2024, to preferred shareholders of record as at December 15, 2023.

Capital Investment Decisions

Our 2023 capital program is forecast to be between $4.0 billion and $4.5 billion, including approximately $2.8 billion of sustaining capital and between $1.2 billion to $1.7 billion of optimization and growth capital. Our Future Capital Investment is focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost control and positioning the Company for continued growth in shareholder returns. We expect our annual upstream production to average between 775 thousand BOE per day and 795 thousand BOE per day and our downstream crude oil unit throughput average between 580 thousand barrels per day to 610 thousand barrels per day in 2023. Our guidance as updated on July 26, 2023, is available at our website at cenovus.com.

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. For further information, see Note 25 to the interim Consolidated Financial Statements.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  45

Our total commitments were $24.7 billion as at September 30, 2023 (December 31, 2022 – $33.0 billion), of which $20.2 billion of our commitments are for various transportation and storage commitments and $1.2 billion are for product purchase commitments. Transportation commitments include $9.1 billion that are subject to regulatory approval or were approved, but are not yet in service. Terms are up to 20 years subsequent to the date of commencement and should help align with the Company’s future transportation requirements. Total commitments decreased from December 31, 2022, primarily due to the reduction in the contract terms of certain product purchase contracts.

As at September 30, 2023, our total commitments included commitments with HMLP of $2.1 billion related to long-term transportation and storage services.

As at September 30, 2023, outstanding letters of credit issued as security for performance under certain contracts totaled $353 million.

Legal Proceedings

We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our interim Consolidated Financial Statements.

Transactions with Related Parties

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 three and nine months ended September 30, 2023, we charged HMLP $49 million and $112 million, respectively, for construction and management services (three and nine months ended September 30, 2022 – $56 million and $133 million, respectively).

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. For the three and nine months ended September 30, 2023, we incurred costs of $67 million and $205 million, respectively, for the use of HMLP’s pipeline systems, as well as for transportation and storage services (three and nine months ended September 30, 2022 – $64 million and $197 million, respectively).

RISK MANAGEMENT AND RISK FACTORS

For a full understanding of the risks that impact us, the following discussion should be read in conjunction with the Risk Management and Risk Factors section of our 2022 annual MD&A.

We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the energy industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, our business, reputation, financial condition, results of operations and cash flows, which may, without limitation, reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, respond to changes in our operating environment, repurchase our shares, pay dividends to our shareholders, and fulfill our obligations (including debt servicing requirements) and may materially affect the market price of our securities.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, as well as use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2022.

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

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements. A full list of the critical judgments used in applying accounting policies and key sources of estimation uncertainty can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2022. There were no changes to our critical judgments used in applying accounting policies and key sources of measurement uncertainty during the nine months ended September 30, 2023.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  46

New Accounting Standards and Interpretations Not Yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that were effective for annual periods beginning on or after January 1, 2023, but are not material to Cenovus’s operations. There were no new or amended accounting standards or interpretations issued during the nine months ended September 30, 2023, that are expected to have a material impact on the Company’s interim 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 internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at September 30, 2023. 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 September 30, 2023.

On February 28, 2023, Cenovus closed the Toledo Acquisition. As permitted by and in accordance with, National Instrument 52-109, “Certification of Disclosure in Issuers’ Annual and Interim Filings”, and guidance issued by the U.S. Securities and Exchange Commission, Management has limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures in respect of the business acquired from bp. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P relating to the business acquired from bp in a manner consistent with our other operations. Further integration will take place throughout the remainder of the year as processes and systems align.

Assets acquired from bp represented approximately one percent of Cenovus’s total assets at September 30, 2023. Revenues attributable to assets acquired from bp were less than seven percent of Cenovus’s total revenues for the three and nine months ended September 30, 2023. Operating expenses attributable to assets acquired from bp were approximately five percent of Cenovus’s total operating expenses for the three and nine months ended September 30, 2023.

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

ADVISORY

Oil and Gas Information

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

Forward-looking Information

This document contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “capacity”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “may”, “objective”, “opportunities”, “plan”, “position”, “prioritize”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: shareholder value and returns; cost structure; margins; safety performance; sustainability and sustainability leadership; using the Company’s integrated network of assets to maximize value; delivering on our strategy; returning incremental value to shareholders through share buybacks and/or variable dividends in accordance with the capital allocation framework; GHG emissions; interest expense; infrastructure; operating and capital costs; capital investment, allocation, and structure; capital discipline; Free Funds Flow generation; resiliency; Excess Free Funds Flow allocation; balance sheet management and strength; flexibility in both high and low commodity price environments; funding near-term cash requirements; managing capital structure; dividends of any kind; share repurchases under the NCIB and renewal of same; full payment of the aggregate warrant purchase price; reinvestment in the business; diversifying the portfolio; deleveraging; near-term funding requirements; meeting payment obligations; maintaining credit ratings; debt levels; Net Debt; Net Debt to Adjusted Funds Flow Ratio; Net Debt to Adjusted EBITDA Ratio; adjusting capital and operating spending; drawing down credit

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  47

facilities; repaying existing debt; adjusting dividends; purchasing Cenovus common shares; issuing new debt; issuing new shares; renewing our Base Shelf prospectus; maintaining liquidity; capital expenditures; production and production rates; crude oil unit throughput or throughput; consistent and reliable operations at all operated assets; operating performance; liabilities from legal proceedings; cash flow; financial results; variable payments; provision for income taxes; financial resilience; capturing value; monitoring market fundamentals; mitigating the impact of crude oil and refined product differentials; plans to achieve targets for the Company’s five ESG focus areas: climate and GHG emissions, water stewardship, biodiversity, indigenous reconciliation, inclusion and diversity; the focus of our 2023 budget; business and asset integration; integrating the Toledo and Lima refineries; optimizing run rates at the Company’s refineries; completion of the planned turnaround at the Borger Refinery; pad construction and first steam in the Ipiatik area at Foster Creek; adding additional bitumen reserves to the Foster Creek plant through the acquisition of the Ipiatik area; full ramp-up of the Superior Refinery; integration of the Toledo Refinery; transportation and storage commitments; commissioning the Terra Nova floating production, storage and offloading unit to resume production at the Terra Nova Field in the fourth quarter of 2023; progressing the West White Rose project to deliver first oil in 2026; Indonesia; and the Company’s outlook for commodities and the Canadian dollar 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, light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits and anticipated cost synergies of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude oil unit throughput volumes and timing thereof; 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, interest rates, inflation, foreign exchange rates, 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, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company’s share price and market capitalization over the long term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the 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, sustainability and development plans and dividends, including any increase thereto; production from the Company’s Conventional segment providing an economic hedge for the natural gas required as a fuel source at both the Company’s oil sands and refining operations; 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 our 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 ability of the Company’s refining capacity, dynamic storage, existing pipeline commitments, crude-by-rail loading capacity and financial hedge transactions to partially mitigate a portion of the Company’s WCS crude oil volumes against wider differentials; 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 dispositions, 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; alignment of realized WCS and WCS prices used to calculate the variable payment to bp Canada; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2023 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.

2023 guidance dated July 26, 2023, and available on cenovus.com, assumes: Brent prices of US$76.00 per barrel, WTI prices of US$71.00 per barrel; WCS of US$54.50 per barrel; Differential WTI-WCS of US$16.50 per barrel; AECO natural gas prices of $2.90 per Mcf; Chicago 3-2-1 crack spread of US$26.50 per barrel; and an exchange rate of $0.75 US$/C$.

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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 effect of the COVID-19 pandemic, including any variants thereof, on the Company’s business, including any related restrictions, containment, and treatment measures taken by varying levels of government in the jurisdictions in which the Company operates; the success of the Company’s COVID-19 workplace policies; the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and dispositions; 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 climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; the development and execution of implementing strategies to meet climate and GHG emissions targets and ambitions; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; 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 will remain 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 cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to recalculate the variable payment to bp Canada; 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; 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; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing 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 or 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 manufacturing 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

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

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

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

ABBREVIATIONS

The following abbreviations and definitions are used in this document:

Crude Oil		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
WTI	West Texas Intermediate	MMcf/d	million cubic feet per day	MBOE/d	thousand barrels of oil    equivalent per day
WCS	Western Canadian Select			OPEC	Organization of Petroleum    Exporting Countries
				OPEC+	OPEC and a group of 10    non-OPEC members
				GHG	Greenhouse Gas
				AECO	Alberta Energy Company
				NCIB	Normal Course Issuer Bid
				NYMEX	New York Mercantile Exchange
				SAGD	steam-assisted gravity drainage
				USGC	U.S. Gulf Coast

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SPECIFIED FINANCIAL MEASURES

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS including Operating Margin, Operating Margin for the Upstream or Downstream operations, 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, Gross Margin, Refining Margin, Unit Operating Expense, Per Unit DD&A and Netbacks (including the total netbacks 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. The definition and reconciliation, if applicable, of each specified financial measure is presented in this Advisory and may also be presented in the Operating and Financial Results or Liquidity and Capital Resources sections of this MD&A. Refer to the Specified Financial Measures Advisory of our 2022 annual MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow for quarters in 2022 and 2021 not found below.

Operating Margin

Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for the Upstream or Downstream segment 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.

	Three Months Ended September 30,
	2023	2022	2023	2022	2023	2022
($ millions)	Upstream (1)		Downstream (1)		Total
Revenues
Gross Sales (2)	8,783	10,250	9,658	10,873	18,441	21,123
Less: Royalties	1,135	1,226	—	—	1,135	1,226
	7,648	9,024	9,658	10,873	17,306	19,897
Expenses
Purchased Product (2)	900	2,383	7,947	9,680	8,847	12,063
Transportation and Blending (2)	2,397	2,826	—	—	2,397	2,826
Operating	914	915	778	780	1,692	1,695
Realized (Gain) Loss on Risk Management	(10)	51	11	(77)	1	(26)
Operating Margin	3,447	2,849	922	490	4,369	3,339

	Nine Months Ended September 30,
	2023	2022	2023	2022	2023	2022
($ millions)	Upstream (1)		Downstream (1)		Total
Revenues
Gross Sales (2)	23,285	32,891	24,222	29,708	47,507	62,599
Less: Royalties	2,368	3,993	—	—	2,368	3,993
	20,917	28,898	24,222	29,708	45,139	58,606
Expenses
Purchased Product (2)	2,489	5,662	20,385	25,416	22,874	31,078
Transportation and Blending (2)	8,194	9,317	—	—	8,194	9,317
Operating	2,826	2,834	2,375	2,291	5,201	5,125
Realized (Gain) Loss on Risk Management	(7)	1,485	6	120	(1)	1,605
Operating Margin	7,415	9,600	1,456	1,881	8,871	11,481

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

(2)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

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	Three Months Ended March 31, 2023 (1)			Three Months Ended June 30, 2023 (1)			Six Months Ended June 30, 2023 (1)
($ millions)	Upstream	Downstream	Total	Upstream	Downstream	Total	Upstream	Downstream	Total
Revenues
Gross Sales	7,217	7,137	14,354	7,285	7,427	14,712	14,502	14,564	29,066
Less: Royalties	596	—	596	637	—	637	1,233	—	1,233
	6,621	7,137	13,758	6,648	7,427	14,075	13,269	14,564	27,833
Expenses
Purchased Product	838	5,991	6,829	751	6,447	7,198	1,589	12,438	14,027
Transportation and Blending	3,027	—	3,027	2,770	—	2,770	5,797	—	5,797
Operating	1,029	754	1,783	883	843	1,726	1,912	1,597	3,509
Realized (Gain) Loss on Risk Management	16	1	17	(13)	(6)	(19)	3	(5)	(2)
Operating Margin	1,711	391	2,102	2,257	143	2,400	3,968	534	4,502

	2022
	Upstream							Downstream
	Three Months Ended				Year-to-Date			Three Months Ended				Year-to-Date
($ millions)	Q1	Q2	Q3	Q4	Q2	Q3	Q4	Q1	Q2	Q3	Q4	Q2	Q3	Q4
Revenues
Gross Sales (1)	10,922	11,719	10,250	8,251	22,641	32,891	41,142	8,116	10,719	10,873	8,302	18,835	29,708	38,010
Less: Royalties	1,185	1,582	1,226	875	2,767	3,993	4,868	—	—	—	—	—	—	—
	9,737	10,137	9,024	7,376	19,874	28,898	36,274	8,116	10,719	10,873	8,302	18,835	29,708	38,010
Expenses
Purchased Product (1)	1,818	1,461	2,383	1,079	3,279	5,662	6,741	6,817	8,919	9,680	6,993	15,736	25,416	32,409
Transportation and Blending (1)	3,219	3,272	2,826	2,984	6,491	9,317	12,301	—	—	—	—	—	—	—
Operating	909	1,010	915	955	1,919	2,834	3,789	645	866	780	759	1,511	2,291	3,050
Realized (Gain) Loss on Risk Management	871	563	51	134	1,434	1,485	1,619	110	87	(77)	(8)	197	120	112
Operating Margin	2,920	3,831	2,849	2,224	6,751	9,600	11,824	544	847	490	558	1,391	1,881	2,439
	2022
	Total
	Three Months Ended				Year-to-Date
($ millions)	Q1	Q2	Q3	Q4	Q2	Q3	Q4
Revenues
Gross Sales (1)	19,038	22,438	21,123	16,553	41,476	62,599	79,152
Less: Royalties	1,185	1,582	1,226	875	2,767	3,993	4,868
	17,853	20,856	19,897	15,678	38,709	58,606	74,284
Expenses
Purchased Product (1)	8,635	10,380	12,063	8,072	19,015	31,078	39,150
Transportation and Blending (1)	3,219	3,272	2,826	2,984	6,491	9,317	12,301
Operating	1,554	1,876	1,695	1,714	3,430	5,125	6,839
Realized (Gain) Loss on Risk Management	981	650	(26)	126	1,631	1,605	1,731
Operating Margin	3,464	4,678	3,339	2,782	8,142	11,481	14,263

(1)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

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	2021
	Upstream				Downstream
	Three Months Ended		Year-to-Date		Three Months Ended		Year-to-Date
($ millions)	Q3	Q4	Q3	Q4	Q3	Q4	Q3	Q4
Revenues
Gross Sales (1)	7,375	8,258	19,667	27,925	7,422	8,010	18,248	26,258
Less: Royalties	733	815	1,639	2,454	—	—	—	—
	6,642	7,443	18,028	25,471	7,422	8,010	18,248	26,258
Expenses
Purchased Product (1)	1,074	1,198	2,861	4,059	6,600	7,223	15,888	23,111
Transportation and Blending (1)	2,158	2,620	6,175	8,795	—	—	—	—
Operating	800	865	2,376	3,241	537	689	1,569	2,258
Realized (Gain) Loss on Risk Management	168	202	586	788	17	56	48	104
Operating Margin	2,442	2,558	6,030	8,588	268	42	743	785
	2021
	Total
	Three Months Ended		Year-to-Date
($ millions)	Q3	Q4	Q3	Q4
Revenues
Gross Sales (1)	14,797	16,268	37,915	54,183
Less: Royalties	733	815	1,639	2,454
	14,064	15,453	36,276	51,729
Expenses
Purchased Product (1)	7,674	8,421	18,749	27,170
Transportation and Blending (1)	2,158	2,620	6,175	8,795
Operating	1,337	1,554	3,945	5,499
Realized (Gain) Loss on Risk Management	185	258	634	892
Operating Margin	2,710	2,600	6,773	9,373

Operating Margin by Asset

	Three Months Ended September 30, 2023			Nine Months Ended September 30, 2023
($ millions)	Atlantic	Asia Pacific	Offshore (1)	Atlantic	Asia Pacific	Offshore (1)
Revenues
Gross Sales	78	324	402	232	871	1,103
Less: Royalties	2	24	26	11	54	65
	76	300	376	221	817	1,038
Expenses
Transportation and Blending	—	—	—	9	—	9
Operating	47	29	76	190	91	281
Operating Margin	29	271	300	22	726	748

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

	Three Months Ended September 30, 2022			Nine Months Ended September 30, 2022
($ millions)	Atlantic	Asia Pacific	Offshore (1)	Atlantic	Asia Pacific	Offshore (1)
Revenues
Gross Sales	113	337	450	492	1,083	1,575
Less: Royalties	2	20	22	(4)	60	56
	111	317	428	496	1,023	1,519
Expenses
Transportation and Blending	4	—	4	12	—	12
Operating	53	32	85	146	88	234
Operating Margin	54	285	339	338	935	1,273

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

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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 non-cash working capital. 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 non-cash working capital minus capital investment.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Cash From (Used in) Operating Activities	2,738	4,089	4,442	8,433
(Add) Deduct:
Settlement of Decommissioning Liabilities	(68)	(55)	(157)	(101)
Net Change in Non-Cash Working Capital	(641)	1,193	(2,142)	(98)
Adjusted Funds Flow	3,447	2,951	6,741	8,632
Capital Investment	1,025	866	3,128	2,434
Free Funds Flow	2,422	2,085	3,613	6,198
Add (Deduct):
Base Dividends Paid on Common Shares	(264)	(205)
Dividends Paid on Preferred Shares	—	(9)
Settlement of Decommissioning Liabilities	(68)	(55)
Principal Repayment of Leases	(70)	(78)
Acquisitions, Net of Cash Acquired	(32)	(389)
Proceeds From Divestitures	1	407
Excess Free Funds Flow	1,989	1,756

Gross Margin, Refining Margin and Unit Operating Expense

Gross Margin and Refining Margin are non-GAAP financial measures, or contain a non-GAAP financial measure, 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 divided by barrels of crude oil unit throughput. Unit Operating Expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. We define Unit Operating Expense as operating expenses from our refineries and upgrader divided by barrels of crude oil unit throughput.

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Canadian Manufacturing

	Three Months Ended September 30, 2023
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Manufacturing (2)
Revenues	1,573	325	1,898	(93)	1,805
Purchased Product	1,357	250	1,607	(127)	1,480
Gross Margin	216	75	291	34	325
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Unit Throughput (Mbbls/d)	80.6	27.8	108.4
Refining Margin ($/bbl)	29.12	29.30	29.17

(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 September 30, 2022
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Manufacturing (2)
Revenues	998	387	1,385	783	2,168
Purchased Product	747	286	1,033	717	1,750
Gross Margin	251	101	352	66	418
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Unit Throughput (Mbbls/d)	71.3	27.2	98.5
Refining Margin ($/bbl)	38.33	40.33	38.88

(1)Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business.

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

	Nine Months Ended September 30, 2023
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Manufacturing (2)
Revenues	4,177	739	4,916	(240)	4,676
Purchased Product	3,484	511	3,995	(339)	3,656
Gross Margin	693	228	921	99	1,020
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Unit Throughput (Mbbls/d)	72.9	27.9	100.8
Refining Margin ($/bbl)	34.82	29.98	33.48

(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.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  55

	Nine Months Ended September 30, 2022
	Basis of Refining Margin Calculation
($ millions)	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Manufacturing (2)
Revenues	2,917	816	3,733	2,287	6,020
Purchased Product	2,344	639	2,983	2,082	5,065
Gross Margin	573	177	750	205	955
	Operating Statistics
	Lloydminster Upgrader	Lloydminster Refinery	Lloydminster Upgrader and Lloydminster Refinery Total
Heavy Crude Oil Unit Throughput (Mbbls/d)	68.8	23.7	92.5
Refining Margin ($/bbl)	30.49	27.38	29.69

(1)Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business.

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

U.S. Manufacturing

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2023	2022	2023	2022
Revenues (1)	7,853	8,705	19,546	23,688
Purchased Product (1)	6,467	7,930	16,729	20,351
Gross Margin	1,386	775	2,817	3,337
Crude Oil Unit Throughput (Mbbls/d)	555.9	435.0	453.3	405.3
Refining Margin ($/bbl)	27.10	18.98	22.77	29.94

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

Per Unit DD&A

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 asset retirement costs divided by sales volumes.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  56

Netback Reconciliations

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance and is also presented on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending and operating expenses, and Netback per BOE is divided by sales volumes. 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. The sales price, transportation and blending expense, and sales volumes exclude the impact of purchased condensate. Condensate is blended with crude oil to transport it to market.

The following tables provide a reconciliation of the items comprising Netbacks, and Netbacks per BOE to Operating Margin found in our interim Consolidated Financial Statements.

Oil Sands

	Basis of Netback Calculation
Three Months Ended September 30, 2023 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	1,798	1,936	456	998	5,188	1	5,189
Royalties	375	603	22	81	1,081	1	1,082
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	192	122	58	36	408	—	408
Operating	198	197	75	218	688	2	690
Netback	1,033	1,014	301	663	3,011	(2)	3,009
Realized (Gain) Loss on Risk Management							(6)
Operating Margin							3,015

	Basis of Netback Calculation	Adjustments
Three Months Ended September 30, 2023 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	5,189		1,889	398	95	7,571
Royalties	1,082		—	—	—	1,082
Purchased Product	—		—	398	64	462
Transportation and Blending	408		1,889	—	27	2,324
Operating	690		—	—	(2)	688
Netback	3,009		—	—	6	3,015
Realized (Gain) Loss on Risk Management	(6)		—	—	—	(6)
Operating Margin	3,015		—	—	6	3,021

	Basis of Netback Calculation
Three Months Ended September 30, 2022 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	1,486	1,847	218	929	4,480	4	4,484
Royalties	432	594	18	82	1,126	4	1,130
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	199	137	36	38	410	—	410
Operating	224	209	49	229	711	4	715
Netback	631	907	115	580	2,233	(4)	2,229
Realized (Gain) Loss on Risk Management							42
Operating Margin							2,187

	Basis of Netback Calculation	Adjustments
Three Months Ended September 30, 2022 ($ millions)	Total Oil Sands	Condensate	Third-party Sourced (4)	Other (2)	Total Oil Sands (3) (4)
Gross Sales	4,484	2,333	1,868	79	8,764
Royalties	1,130	—	—	6	1,136
Purchased Product	—	—	1,868	51	1,919
Transportation and Blending	410	2,333	—	15	2,758
Operating	715	—	—	(26)	689
Netback	2,229	—	—	33	2,262
Realized (Gain) Loss on Risk Management	42	—	—	—	42
Operating Margin	2,187	—	—	33	2,220

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

(2)Other includes construction, transportation and blending margin.

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

(4)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  57

	Basis of Netback Calculation
Nine Months Ended September 30, 2023 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	4,035	4,401	941	2,430	11,807	6	11,813
Royalties	783	1,190	42	199	2,214	4	2,218
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	619	411	157	114	1,301	—	1,301
Operating	608	562	229	681	2,080	8	2,088
Netback	2,025	2,238	513	1,436	6,212	(6)	6,206
Realized (Gain) Loss on Risk Management							(7)
Operating Margin							6,213

	Basis of Netback Calculation	Adjustments
Nine Months Ended September 30, 2023 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales	11,813		6,578	1,043	281	19,715
Royalties	2,218		—	—	—	2,218
Purchased Product	—		—	1,043	188	1,231
Transportation and Blending	1,301		6,578	—	86	7,965
Operating	2,088		—	—	13	2,101
Netback	6,206		—	—	(6)	6,200
Realized (Gain) Loss on Risk Management	(7)		—	—	—	(7)
Operating Margin	6,213		—	—	(6)	6,207

	Basis of Netback Calculation
Nine Months Ended September 30, 2022 ($ millions)	Foster Creek	Christina Lake	Sunrise	Other Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	5,441	6,498	728	3,222	15,889	14	15,903
Royalties	1,445	1,900	46	302	3,693	5	3,698
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	559	431	93	110	1,193	—	1,193
Operating	676	677	133	703	2,189	17	2,206
Netback	2,761	3,490	456	2,107	8,814	(8)	8,806
Realized (Gain) Loss on Risk Management							1,468
Operating Margin							7,338

	Basis of Netback Calculation	Adjustments
Nine Months Ended September 30, 2022 ($ millions)	Total Oil Sands	Condensate	Third-party Sourced (4)	Other (2)	Total Oil Sands (3) (4)
Gross Sales	15,903	7,892	3,987	248	28,030
Royalties	3,698	—	—	11	3,709
Purchased Product	—	—	3,987	215	4,202
Transportation and Blending	1,193	7,892	—	29	9,114
Operating	2,206	—	—	(9)	2,197
Netback	8,806	—	—	2	8,808
Realized (Gain) Loss on Risk Management	1,468	—	—	—	1,468
Operating Margin	7,338	—	—	2	7,340

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

(2)Other includes construction, transportation and blending margin.

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

(4)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  58

Conventional

	Basis of Netback Calculation	Adjustments
Three Months Ended September 30, 2023 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	330	438	42	810
Royalties	26	—	1	27
Purchased Product	—	438	—	438
Transportation and Blending	44	—	29	73
Operating	144	—	6	150
Netback	116	—	6	122
Realized (Gain) Loss on Risk Management	(4)	—	—	(4)
Operating Margin	120	—	6	126

	Basis of Netback Calculation	Adjustments
Three Months Ended September 30, 2022 ($ millions)	Conventional	Third-party Sourced (3)	Other (1)	Conventional (2) (3)
Gross Sales	512	464	60	1,036
Royalties	68	—	—	68
Purchased Product	—	464	—	464
Transportation and Blending	29	—	35	64
Operating	137	—	4	141
Netback	278	—	21	299
Realized (Gain) Loss on Risk Management	9	—	—	9
Operating Margin	269	—	21	290

	Basis of Netback Calculation	Adjustments
Nine Months Ended September 30, 2023 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales	1,059	1,258	150	2,467
Royalties	85	—	—	85
Purchased Product	—	1,258	—	1,258
Transportation and Blending	128	—	92	220
Operating	429	—	15	444
Netback	417	—	43	460
Realized (Gain) Loss on Risk Management	—	—	—	—
Operating Margin	417	—	43	460

	Basis of Netback Calculation	Adjustments
Nine Months Ended September 30, 2022 ($ millions)	Conventional	Third-party Sourced (3)	Other (1)	Conventional (2) (3)
Gross Sales	1,683	1,460	143	3,286
Royalties	228	—	—	228
Purchased Product	—	1,460	—	1,460
Transportation and Blending	100	—	91	191
Operating	385	—	18	403
Netback	970	—	34	1,004
Realized (Gain) Loss on Risk Management	9	8	—	17
Operating Margin	961	(8)	34	987

(1)Reflects Operating Margin from processing facilities.

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

(3)Comparative periods reflect certain revisions. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  59

Offshore

	Basis of Netback Calculation					Adjustments
Three Months Ended September 30, 2023 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	78	324	74	398	476	(74)	—	402
Royalties	2	24	15	39	41	(15)	—	26
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	—	—	—	—	—	—	—	—
Operating	47	27	15	42	89	(12)	(1)	76
Netback	29	273	44	317	346	(47)	1	300
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					346	(47)	1	300

	Basis of Netback Calculation					Adjustments
Three Months Ended September 30, 2022 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	113	337	63	400	513	(63)	—	450
Royalties	2	20	25	45	47	(25)	—	22
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	4	—	—	—	4	—	—	4
Operating	34	28	10	38	72	(6)	19	85
Netback	73	289	28	317	390	(32)	(19)	339
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					390	(32)	(19)	339

	Basis of Netback Calculation					Adjustments
Nine Months Ended September 30, 2023 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	232	871	226	1,097	1,329	(226)	—	1,103
Royalties	11	54	56	110	121	(56)	—	65
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	9	—	—	—	9	—	—	9
Operating	168	82	41	123	291	(32)	22	281
Netback	44	735	129	864	908	(138)	(22)	748
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					908	(138)	(22)	748

	Basis of Netback Calculation					Adjustments
Nine Months Ended September 30, 2022 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	492	1,083	194	1,277	1,769	(194)	—	1,575
Royalties	(4)	60	89	149	145	(89)	—	56
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	12	—	—	—	12	—	—	12
Operating	127	75	34	109	236	(21)	19	234
Netback	357	948	71	1,019	1,376	(84)	(19)	1,273
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					1,376	(84)	(19)	1,273

(1)Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements.

(2)Relates to West White Rose project expenses.

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

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  60

Upstream Sales Volumes (1)

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(MBOE/d)	2023	2022	2023	2022
Oil Sands
Foster Creek	197.6	180.7	185.6	190.9
Christina Lake	229.4	247.2	232.9	247.8
Sunrise	51.2	29.7	46.1	26.3
Other Oil Sands	119.0	120.4	119.5	118.8
Total Oil Sands	597.2	578.0	584.1	583.8
Conventional	127.2	126.2	118.5	128.0
Sales Before Internal Consumption	724.4	704.2	702.6	711.8
Less: Internal Consumption (2)	(87.9)	(80.7)	(88.5)	(84.3)
Sales After Internal Consumption	636.5	623.5	614.1	627.5
Offshore
Atlantic	7.8	7.8	7.8	12.6
Asia Pacific
China	43.8	45.4	39.4	48.6
Indonesia	13.7	10.1	14.1	9.7
Total Asia Pacific	57.5	55.5	53.5	58.3
Total Offshore	65.3	63.3	61.3	70.9
Total Sales Volumes	701.8	686.8	675.4	698.4

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

(2)Represents natural gas volumes produced by the Oil Sands and Conventional segment used for internal consumption by the Oil Sands segment.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  61

Netbacks for the three months ended March 31, 2023, June 30, 2023 and December 31, 2022 and the twelve months ended December 31, 2022 were revised below. Comparative periods reflect certain reclassifications. See Note 26 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

Oil Sands

	Basis of Netback Calculation	Adjustments
Three Months Ended March 31, 2023 ($ millions)	Total Oil Sands	Condensate	Third-party Sourced	Other	Total Oil Sands
Gross Sales	2,888	2,445	294	80	5,707
Royalties	516	—	—	—	516
Purchased Product	—		294	61	355
Transportation and Blending	470	2,445	—	26	2,941
Operating	729	—	—	8	737
Netback	1,173	—	—	(15)	1,158
Realized (Gain) Loss on Risk Management	7	—	—	1	8
Operating Margin	1,166	—	—	(16)	1,150

	Basis of Netback Calculation	Adjustments
Three Months Ended June 30, 2023 ($ millions)	Total Oil Sands	Condensate	Third-party Sourced	Other	Total Oil Sands
Gross Sales	3,736	2,244	351	106	6,437
Royalties	621	—	—	(1)	620
Purchased Product	—	—	351	63	414
Transportation and Blending	424	2,244	—	32	2,700
Operating	669	—	—	7	676
Netback	2,022	—	—	5	2,027
Realized (Gain) Loss on Risk Management	(8)	—	—	(1)	(9)
Operating Margin	2,030	—	—	6	2,036

	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2022 ($ millions)	Total Oil Sands	Condensate	Third-party Sourced	Other	Total Oil Sands
Gross Sales	3,706	2,415	422	110	6,653
Royalties	784	—	—	—	784
Purchased Product	—	—	422	94	516
Transportation and Blending	493	2,415	—	14	2,922
Operating	735	—	—	(2)	733
Netback	1,694	—	—	4	1,698
Realized (Gain) Loss on Risk Management	59	—	—	—	59
Operating Margin	1,635	—	—	4	1,639

	Basis of Netback Calculation	Adjustments
Twelve Months Ended December 31, 2022 ($ millions)	Total Oil Sands	Condensate	Third-party Sourced	Other	Total Oil Sands
Gross Sales	19,609	10,307	4,409	358	34,683
Royalties	4,482	—	—	11	4,493
Purchased Product	—	—	4,409	309	4,718
Transportation and Blending	1,686	10,307	—	43	12,036
Operating	2,941	—	—	(11)	2,930
Netback	10,500	—	—	6	10,506
Realized (Gain) Loss on Risk Management	1,527	—	—	—	1,527
Operating Margin	8,973	—	—	6	8,979

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  62

Conventional

	Basis of Netback Calculation	Adjustments
Three Months Ended March 31, 2023 ($ millions)	Conventional	Third-party Sourced	Other	Conventional
Gross Sales	491	483	63	1,037
Royalties	54	—	—	54
Purchased Product	—	483	—	483
Transportation and Blending	45	—	36	81
Operating	146	—	4	150
Netback	246	—	23	269
Realized (Gain) Loss on Risk Management	8	—	—	8
Operating Margin	238	—	23	261

	Basis of Netback Calculation	Adjustments
Three Months Ended June 30, 2023 ($ millions)	Conventional	Third-party Sourced	Other	Conventional
Gross Sales	238	337	45	620
Royalties	5	—	(1)	4
Purchased Product	—	337	—	337
Transportation and Blending	39	—	27	66
Operating	139	—	5	144
Netback	55	—	14	69
Realized (Gain) Loss on Risk Management	(4)	—	—	(4)
Operating Margin	59	—	14	73

	Basis of Netback Calculation	Adjustments
Three Months Ended December 31, 2022 ($ millions)	Conventional	Third-party Sourced	Other	Conventional
Gross Sales	555	563	35	1,153
Royalties	69	—	1	70
Purchased Product	—	563	—	563
Transportation and Blending	47	—	12	59
Operating	135	—	3	138
Netback	304	—	19	323
Realized (Gain) Loss on Risk Management	75	—	—	75
Operating Margin	229	—	19	248

	Basis of Netback Calculation	Adjustments
Twelve Months Ended December 31, 2022 ($ millions)	Conventional	Third-party Sourced	Other	Conventional
Gross Sales	2,238	2,023	178	4,439
Royalties	297	—	1	298
Purchased Product	—	2,023	—	2,023
Transportation and Blending	147	—	103	250
Operating	520	—	21	541
Netback	1,274	—	53	1,327
Realized (Gain) Loss on Risk Management	84	8	—	92
Operating Margin	1,190	(8)	53	1,235

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  63

Prior Period Revisions

Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was revised.

Classification Revisions

During the three months ended September 30, 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made:

•Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense.

•Report sales of feedstock between the Oil Sands, Conventional and U.S. Manufacturing segments on a net basis, which resulted in a reclassification between gross sales and purchased product.

Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position.

It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position.

Change to Reporting Segments

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. In December 2022, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods were reclassified to reflect this change, with no impact to net earnings (loss), cash flows or financial position.

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

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  64

	Three Months Ended March 31, 2023
($ millions)	Previously Reported	Revisions	Revised Balance
Oil Sands Segment
Gross Sales (1)	5,911	(204)	5,707
Purchased Product (1)	559	(204)	355
	5,352	—	5,352
Conventional Segment
Gross Sales (1)	1,031	6	1,037
Purchased Product (1)	510	(27)	483
Transportation and Blending	48	33	81
	473	—	473
U.S. Manufacturing Segment
Gross Sales (1)	5,860	(231)	5,629
Purchased Product (1)	5,129	(231)	4,898
	731	—	731
Corporate and Eliminations Segment
Gross Sales (1)	(1,925)	429	(1,496)
Purchased Product (1)	(1,499)	479	(1,020)
Transportation and Blending	(141)	(134)	(275)
Operating	(231)	84	(147)
	(54)	—	(54)
Consolidated
Purchased Product	5,792	17	5,809
Transportation and Blending	2,853	(101)	2,752
Operating	1,552	84	1,636
	2,661	—	2,661

(1)Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in the U.S. Manufacturing segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting adjustment to the Corporate and Eliminations segment.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  65

	Three Months Ended June 30, 2023			Six Months Ended June 30, 2023
($ millions)	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Oil Sands Segment
Gross Sales	6,556	(119)	6,437	12,467	(323)	12,144
Purchased Product	533	(119)	414	1,092	(323)	769
	6,023	—	6,023	11,375	—	11,375
Conventional Segment
Gross Sales	615	5	620	1,646	11	1,657
Purchased Product	352	(15)	337	862	(42)	820
Transportation and Blending	46	20	66	94	53	147
	217	—	217	690	—	690
U.S. Manufacturing Segment
Gross Sales	6,198	(134)	6,064	12,058	(365)	11,693
Purchased Product	5,498	(134)	5,364	10,627	(365)	10,262
	700	—	700	1,431	—	1,431
Corporate and Eliminations Segment
Gross Sales (1)	(2,092)	248	(1,844)	(4,017)	677	(3,340)
Purchased Product (1)	(1,757)	287	(1,470)	(3,256)	766	(2,490)
Transportation and Blending	(109)	(98)	(207)	(250)	(232)	(482)
Operating	(185)	59	(126)	(416)	143	(273)
	(41)	—	(41)	(95)	—	(95)
Consolidated
Purchased Product	5,709	19	5,728	11,501	36	11,537
Transportation and Blending	2,641	(78)	2,563	5,494	(179)	5,315
Operating	1,541	59	1,600	3,093	143	3,236
	9,891	—	9,891	20,088	—	20,088

(1)The three and six months ended June 30, 2023, includes revisions to gross sales and purchased product of $119 million and $323 million in the Oil Sands segment, $15 million and $42 million in the Conventional segment and $134 million and $365 million in the U.S. Manufacturing segment for the reasons noted above with an offsetting adjustment to the Corporate and Eliminations segment.

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  66

	Three Months Ended March 31, 2022
($ millions)	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Conventional Segment
Gross Sales	1,112	25	—	1,137
Transportation and Blending	34	25	—	59
	1,078	—	—	1,078
Canadian Manufacturing Segment
Gross Sales	1,044	—	563	1,607
Purchased Product	804	2	529	1,335
Transportation and Blending	2	(2)	—	—
Operating	124	—	27	151
Depreciation, Depletion and    Amortization	42	—	8	50
	72	—	(1)	71
Retail Segment
Gross Sales	694	—	(694)	—
Purchased Product	660	—	(660)	—
Operating	27	—	(27)	—
Depreciation, Depletion and    Amortization	8	—	(8)	—
	(1)	—	1	—
Corporate and Eliminations Segment
Gross Sales	(1,761)	(25)	131	(1,655)
Purchased Product	(1,282)	39	131	(1,112)
Transportation and Blending	(221)	(110)	—	(331)
Operating	(267)	46	—	(221)
	9	—	—	9
Consolidated
Purchased Product	7,482	41	—	7,523
Transportation and Blending	2,975	(87)	—	2,888
Operating	1,287	46	—	1,333
	11,744	—	—	11,744

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  67

	Three Months Ended June 30, 2022				Six Months Ended June 30, 2022
($ millions)	Previously Reported	Revisions	Segment Aggregation	Revised Balance	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Conventional Segment
Gross Sales	1,079	34	—	1,113	2,191	59	—	2,250
Transportation and Blending	34	34	—	68	68	59	—	127
	1,045	—	—	1,045	2,123	—	—	2,123
Canadian Manufacturing Segment
Gross Sales	1,521	—	724	2,245	2,565	—	1,287	3,852
Purchased Product	1,296	(2)	686	1,980	2,100	—	1,215	3,315
Transportation and Blending	(2)	2	—	—	—	—	—	—
Operating	180	—	31	211	304	—	58	362
Depreciation, Depletion and    Amortization	64	—	8	72	106	—	16	122
	(17)	—	(1)	(18)	55	—	(2)	53
Retail Segment
Gross Sales	849	—	(849)	—	1,543	—	(1,543)	—
Purchased Product	811	—	(811)	—	1,471	—	(1,471)	—
Operating	31	—	(31)	—	58	—	(58)	—
Depreciation, Depletion and    Amortization	8	—	(8)	—	16	—	(16)	—
	(1)	—	1	—	(2)	—	2	—
Corporate and Eliminations Segment
Gross Sales	(1,782)	(34)	125	(1,691)	(3,543)	(59)	256	(3,346)
Purchased Product	(1,111)	69	125	(917)	(2,393)	108	256	(2,029)
Transportation and Blending	(188)	(145)	—	(333)	(409)	(255)	—	(664)
Operating	(395)	42		(353)	(662)	88	—	(574)
	(88)	—	—	(88)	(79)	—	—	(79)
Consolidated
Purchased Product	9,396	67	—	9,463	16,878	108	—	16,986
Transportation and Blending	3,048	(109)	—	2,939	6,023	(196)	—	5,827
Operating	1,481	42	—	1,523	2,768	88	—	2,856
	13,925	—	—	13,925	25,669	—	—	25,669

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  68

	Three Months Ended September 30, 2022				Nine Months Ended September 30, 2022
($ millions)	Previously Reported	Revisions	Segment Aggregation	Revised Balance	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Oil Sands Segment
Gross Sales	8,778	(14)	—	8,764	28,044	(14)	—	28,030
Purchased Product	1,933	(14)	—	1,919	4,216	(14)	—	4,202
	6,845	—	—	6,845	23,828	—	—	23,828
Conventional Segment
Gross Sales	1,010	26	—	1,036	3,201	85	—	3,286
Transportation and Blending	38	26	—	64	106	85	—	191
	972	—	—	972	3,095	—	—	3,095
Canadian Manufacturing Segment
Gross Sales	1,478	—	690	2,168	4,043	—	1,977	6,020
Purchased Product	1,092	3	655	1,750	3,192	3	1,870	5,065
Transportation and Blending	3	(3)	—	—	3	(3)	—	—
Operating	134	—	38	172	438	—	96	534
Depreciation, Depletion and    Amortization	37	—	5	42	143	—	21	164
	212	—	(8)	204	267	—	(10)	257
Retail Segment
Gross Sales	881	—	(881)	—	2,424	—	(2,424)	—
Purchased Product	846	—	(846)	—	2,317	—	(2,317)	—
Operating	38	—	(38)	—	96	—	(96)	—
Depreciation, Depletion and    Amortization	5	—	(5)	—	21	—	(21)	—
	(8)	—	8	—	(10)	—	10	—
U.S. Manufacturing Segment
Gross Sales	8,719	(14)	—	8,705	23,702	(14)	—	23,688
Purchased Product	7,944	(14)	—	7,930	20,365	(14)	—	20,351
	775	—	—	775	3,337	—	—	3,337
Corporate and Eliminations Segment
Gross Sales	(2,619)	2	191	(2,426)	(6,162)	(57)	447	(5,772)
Purchased Product	(2,267)	65	191	(2,011)	(4,660)	173	447	(4,040)
Transportation and Blending	(119)	(128)	—	(247)	(528)	(383)	—	(911)
Operating	(256)	65	—	(191)	(918)	153	—	(765)
	23	—	—	23	(56)	—	—	(56)
Consolidated
Purchased Product	10,012	40	—	10,052	26,890	148	—	27,038
Transportation and Blending	2,684	(105)	—	2,579	8,707	(301)	—	8,406
Operating	1,439	65	—	1,504	4,207	153	—	4,360
	14,135	—	—	14,135	39,804	—	—	39,804

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  69

	Three Months Ended December 31, 2022				Twelve Months Ended December 31, 2022
($ millions)	Previously Reported	Revisions	Segment Aggregation	Revised Balance	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Oil Sands Segment
Gross Sales	6,731	(78)	—	6,653	34,775	(92)	—	34,683
Purchased Product	594	(78)	—	516	4,810	(92)	—	4,718
	6,137	—	—	6,137	29,965	—	—	29,965
Conventional Segment
Gross Sales	1,131	22	—	1,153	4,332	107	—	4,439
Transportation and Blending	37	22	—	59	143	107	—	250
	1,094	—	—	1,094	4,189	—	—	4,189
U.S. Manufacturing Segment
Gross Sales	6,608	(78)	—	6,530	30,310	(92)	—	30,218
Purchased Product	5,747	(78)	—	5,669	26,112	(92)	—	26,020
	861	—	—	861	4,198	—	—	4,198
Corporate and Eliminations Segment
Gross Sales	(1,749)	134	—	(1,615)	(7,464)	77	—	(7,387)
Purchased Product	(1,320)	168	—	(1,152)	(5,533)	341	—	(5,192)
Transportation and Blending	(136)	(128)	—	(264)	(664)	(511)	—	(1,175)
Operating	(352)	94	—	(258)	(1,270)	247	—	(1,023)
	59	—	—	59	3	—	—	3
Consolidated
Purchased Product	6,908	12	—	6,920	33,801	157	—	33,958
Transportation and Blending	2,826	(106)	—	2,720	11,530	(404)	—	11,126
Operating	1,362	94	—	1,456	5,569	247	—	5,816
	11,096	—	—	11,096	50,900	—	—	50,900

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  70

	Three Months Ended September 30, 2021				Three Months Ended December 31, 2021
($ millions)	Previously Reported	Revisions	Segment Aggregation	Revised Balance	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Conventional Segment
Gross Sales	833	21	—	854	1,000	21	—	1,021
Transportation and Blending	20	21	—	41	17	21	—	38
	813	—	—	813	983	—	—	983
Canadian Manufacturing Segment
Gross Sales	1,215	—	484	1,699	1,363	—	493	1,856
Purchased Product	986	—	443	1,429	1,128	—	460	1,588
Operating	99	—	25	124	104	—	25	129
Depreciation, Depletion and    Amortization	41	—	11	52	40	—	23	63
	89	—	5	94	91	—	(15)	76
Retail Segment
Gross Sales	592	—	(592)	—	618	—	(618)	—
Purchased Product	551	—	(551)	—	585	—	(585)	—
Operating	25	—	(25)	—	25	—	(25)	—
Depreciation, Depletion and    Amortization	11	—	(11)	—	23	—	(23)	—
	5	—	(5)	—	(15)	—	15	—
Corporate and Eliminations Segment
Gross Sales	(1,450)	(21)	108	(1,363)	(1,831)	(21)	125	(1,727)
Purchased Product	(1,091)	46	108	(937)	(1,369)	39	125	(1,205)
Transportation and Blending	(171)	(94)	—	(265)	(200)	(105)	—	(305)
Operating	(187)	27	—	(160)	(266)	45	—	(221)
	(1)	—	—	(1)	4	—	—	4
Consolidated
Purchased Product	6,691	46	—	6,737	7,177	39	—	7,216
Transportation and Blending	1,966	(73)	—	1,893	2,399	(84)	—	2,315
Operating	1,150	27	—	1,177	1,288	45	—	1,333
	9,807	—	—	9,807	10,864	—	—	10,864

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  71

	Twelve Months Ended December 31, 2021
($ millions)	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Conventional Segment
Gross Sales	3,235	81	—	3,316
Transportation and Blending	74	81	—	155
	3,161	—	—	3,161
Canadian Manufacturing Segment
Gross Sales	4,472	—	1,743	6,215
Purchased Product	3,552	—	1,604	5,156
Operating	388	—	98	486
Depreciation, Depletion and    Amortization	167	—	59	226
	365	—	(18)	347
Retail Segment
Gross Sales	2,158	—	(2,158)	—
Purchased Product	2,019	—	(2,019)	—
Operating	98	—	(98)	—
Depreciation, Depletion and    Amortization	59	—	(59)	—
	(18)	—	18	—
Corporate and Eliminations Segment
Gross Sales	(5,706)	(81)	415	(5,372)
Purchased Product	(4,259)	163	415	(3,681)
Transportation and Blending	(676)	(363)	—	(1,039)
Operating	(783)	119	—	(664)
	12	—	—	12
Consolidated
Purchased Product	23,326	163	—	23,489
Transportation and Blending	8,038	(282)	—	7,756
Operating	4,716	119	—	4,835
	36,080	—	—	36,080

Cenovus Energy Inc. – Q3 2023 Management's Discussion and Analysis  72

EX-99.3

Exhibit 99.3

Cenovus Energy Inc.

Interim Consolidated Financial Statements (unaudited)

For the Periods Ended September 30, 2023

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

For the periods ended September 30, 2023

TABLE OF CONTENTS

CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) (UNAUDITED)	3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)	4
CONSOLIDATED BALANCE SHEETS (UNAUDITED)	5
CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)	6
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)	7
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)	8
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES	8
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE	15
3. ACQUISITIONS	15
4. FINANCE COSTS	17
5. FOREIGN EXCHANGE (GAIN) LOSS, NET	17
6. INCOME TAXES	17
7. PER SHARE AMOUNTS	18
8. EXPLORATION AND EVALUATION ASSETS, NET	19
9. PROPERTY, PLANT AND EQUIPMENT, NET	19
10. RIGHT-OF-USE ASSETS, NET	20
11. JOINT ARRANGEMENTS	20
12. OTHER ASSETS	22
13. DEBT AND CAPITAL STRUCTURE	22
14. LEASE LIABILITIES	25
15. CONTINGENT PAYMENTS	25
16. DECOMMISSIONING LIABILITIES	26
17. OTHER LIABILITIES	26
18. SHARE CAPITAL AND WARRANTS	27
19. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	28
20. STOCK-BASED COMPENSATION PLANS	28
21. RELATED PARTY TRANSACTIONS	30
22. FINANCIAL INSTRUMENTS	30
23. RISK MANAGEMENT	32
24. SUPPLEMENTARY CASH FLOW INFORMATION	34
25. COMMITMENTS AND CONTINGENCIES	36
26. PRIOR PERIOD REVISIONS	36

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 2

CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) (unaudited)

For the periods ended September 30,

($ millions, except per share amounts)

		Three Months Ended		Nine Months Ended
	Notes	2023	2022	2023	2022
Revenues	1
Gross Sales		15,712	18,697	41,438	56,827
Less: Royalties		1,135	1,226	2,368	3,993
		14,577	17,471	39,070	52,834
Expenses	1
Purchased Product (1)		6,620	10,052	18,157	27,038
Transportation and Blending (1)		2,164	2,579	7,479	8,406
Operating (1)		1,553	1,504	4,789	4,360
(Gain) Loss on Risk Management	22	72	(28)	89	1,540
Depreciation, Depletion and Amortization	9,10	1,197	1,047	3,374	3,209
Exploration Expense		2	73	10	99
(Income) Loss From Equity-Accounted Affiliates	11	(11)	(9)	(23)	(11)
General and Administrative		292	128	617	545
Finance Costs	4	106	207	493	631
Interest Income		(33)	(21)	(100)	(44)
Integration and Transaction Costs	3	12	27	49	79
Foreign Exchange (Gain) Loss, Net	5	133	316	7	406
Revaluation (Gain) Loss	3	—	(549)	33	(549)
Re-measurement of Contingent Payments	15	67	(109)	83	142
(Gain) Loss on Divestiture of Assets		—	60	(11)	(244)
Other (Income) Loss, Net		(22)	(59)	(42)	(467)
Earnings (Loss) Before Income Tax		2,425	2,253	4,066	7,694
Income Tax Expense (Recovery)	6	561	644	700	2,028
Net Earnings (Loss)		1,864	1,609	3,366	5,666
Net Earnings (Loss) Per Common Share ($)	7
Basic		0.98	0.83	1.76	2.87
Diluted		0.97	0.81	1.72	2.79

(1)Comparative periods reflect certain revisions. See Note 26.

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

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 3

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)

For the periods ended September 30,

($ millions)

		Three Months Ended		Nine Months Ended
	Notes	2023	2022	2023	2022
Net Earnings (Loss)		1,864	1,609	3,366	5,666
Other Comprehensive Income (Loss), Net of Tax	19
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-    Employment Benefits		19	1	15	58
Change in the Fair Value of Equity Instruments at FVOCI (1)		1	2	—	2
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		253	724	(31)	896
Total Other Comprehensive Income (Loss), Net of Tax		273	727	(16)	956
Comprehensive Income (Loss)		2,137	2,336	3,350	6,622

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

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

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 4

CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)

	Notes	September 30, 2023	December 31, 2022
Assets
Current Assets
Cash and Cash Equivalents		1,262	4,524
Accounts Receivable and Accrued Revenues		4,534	3,473
Income Tax Receivable		133	121
Inventories		4,816	4,312
Total Current Assets		10,745	12,430
Restricted Cash	16	209	209
Exploration and Evaluation Assets, Net	1,8	796	685
Property, Plant and Equipment, Net	1,9	36,727	36,499
Right-of-Use Assets, Net	1,10	1,738	1,845
Income Tax Receivable		25	25
Investments in Equity-Accounted Affiliates	11	356	365
Other Assets	12	266	342
Deferred Income Taxes		642	546
Goodwill	1	2,923	2,923
Total Assets		54,427	55,869
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		6,435	6,124
Income Tax Payable		146	1,211
Short-Term Borrowings	13	14	115
Lease Liabilities	14	315	308
Contingent Payments	15	295	263
Total Current Liabilities		7,205	8,021
Long-Term Debt	13	7,224	8,691
Lease Liabilities	14	2,418	2,528
Contingent Payments	15	—	156
Decommissioning Liabilities	16	3,603	3,559
Other Liabilities	17	1,183	1,042
Deferred Income Taxes		3,967	4,283
Total Liabilities		25,600	28,280
Shareholders’ Equity		28,814	27,576
Non-Controlling Interest		13	13
Total Liabilities and Equity		54,427	55,869
Commitments and Contingencies	25

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

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 5

CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

($ millions)

	Shareholders’ Equity
	Common Shares	Preferred Shares	Warrants	Paid in Surplus	Retained Earnings	AOCI (1)	Total	Non-Controlling Interest
	(Note 18)	(Note 18)	(Note 18)			(Note 19)
As at December 31, 2021	17,016	519	215	4,284	878	684	23,596	12
Net Earnings (Loss)	—	—	—	—	5,666	—	5,666	—
Other Comprehensive Income   (Loss), Net of Tax	—	—	—	—	—	956	956	—
Total Comprehensive Income (Loss)	—	—	—	—	5,666	956	6,622	—
Common Shares Issued Under    Stock Option Plans	165	—	—	(32)	—	—	133	—
Purchase of Common Shares Under    NCIBs (2)	(826)	—	—	(1,317)	—	—	(2,143)	—
Warrants Exercised	76	—	(25)	—	—	—	51	—
Stock-Based Compensation    Expense	—	—	—	10	—	—	10	—
Base Dividends on Common Shares	—	—	—	—	(481)	—	(481)	—
Dividends on Preferred Shares	—	—	—	—	(26)	—	(26)	—
As at September 30, 2022	16,431	519	190	2,945	6,037	1,640	27,762	12
As at December 31, 2022	16,320	519	184	2,691	6,392	1,470	27,576	13
Net Earnings (Loss)	—	—	—	—	3,366	—	3,366	—
Other Comprehensive Income    (Loss), Net of Tax	—	—	—	—	—	(16)	(16)	—
Total Comprehensive Income (Loss)	—	—	—	—	3,366	(16)	3,350	—
Common Shares Issued Under    Stock Option Plans	54	—	—	(11)	—	—	43	—
Purchase of Common Shares Under    NCIBs (2)	(251)	—	—	(460)	—	—	(711)	—
Warrants Exercised	23	—	(7)	—	—	—	16	—
Warrants Purchased and Cancelled	—	—	(151)	—	(562)	—	(713)	—
Stock-Based Compensation    Expense	—	—	—	9	—	—	9	—
Base Dividends on Common Shares	—	—	—	—	(729)	—	(729)	—
Dividends on Preferred Shares	—	—	—	—	(27)	—	(27)	—
As at September 30, 2023	16,146	519	26	2,229	8,440	1,454	28,814	13

(1)Accumulated other comprehensive income (loss) (“AOCI”).

(2)Normal course issuer bids (“NCIBs”).

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

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 6

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the periods ended September 30,

($ millions)

		Three Months Ended		Nine Months Ended
	Notes	2023	2022	2023	2022
Operating Activities
Net Earnings (Loss)		1,864	1,609	3,366	5,666
Depreciation, Depletion and Amortization	9,10	1,197	1,047	3,374	3,209
Deferred Income Tax Expense (Recovery)	6	(2)	568	(416)	625
Unrealized (Gain) Loss on Risk Management	22	72	(18)	88	(88)
Unrealized Foreign Exchange (Gain) Loss	5	59	298	(99)	419
Realized Foreign Exchange (Gain) Loss on Non-Operating Items		98	120	98	146
Revaluation (Gain) Loss	3	—	(549)	33	(549)
Re-measurement of Contingent Payments, Net of Cash Paid		67	(286)	83	(489)
(Gain) Loss on Divestiture of Assets		—	60	(11)	(244)
Unwinding of Discount on Decommissioning Liabilities	16	55	43	165	132
(Income) Loss From Equity-Accounted Affiliates	11	(11)	(9)	(23)	(11)
Distributions Received From Equity-Accounted Affiliates	11	23	13	117	54
Other		25	55	(34)	(238)
Settlement of Decommissioning Liabilities	16	(68)	(55)	(157)	(101)
Net Change in Non-Cash Working Capital	24	(641)	1,193	(2,142)	(98)
Cash From (Used in) Operating Activities		2,738	4,089	4,442	8,433
Investing Activities
Acquisitions, Net of Cash Acquired	3	(32)	(389)	(501)	(390)
Capital Investment	1	(1,025)	(866)	(3,128)	(2,434)
Proceeds From Divestitures		1	407	12	1,469
Payment on Divestiture of Assets		—	—	—	(50)
Net Change in Investments and Other		(8)	51	(101)	(185)
Net Change in Non-Cash Working Capital	24	(37)	107	(297)	446
Cash From (Used in) Investing Activities		(1,101)	(690)	(4,015)	(1,144)
Net Cash Provided (Used) Before Financing Activities		1,637	3,399	427	7,289
Financing Activities	24
Net Issuance (Repayment) of Short-Term Borrowings		14	(2)	(101)	(81)
(Repayment) of Long-Term Debt	13	(1,346)	(2,889)	(1,346)	(4,149)
Principal Repayment of Leases	14	(70)	(78)	(216)	(228)
Common Shares Issued Under Stock Option Plans		25	13	43	133
Purchase of Common Shares Under NCIBs	18	(361)	(659)	(711)	(2,143)
Payment for Purchase of Warrants	18	(600)	—	(600)	—
Proceeds From Exercise of Warrants		5	7	16	51
Base Dividends Paid on Common Shares	7	(264)	(205)	(729)	(481)
Dividends Paid on Preferred Shares	7	—	(9)	(27)	(26)
Other		(3)	—	(3)	(2)
Cash From (Used in) Financing Activities		(2,600)	(3,822)	(3,674)	(6,926)
Effect of Foreign Exchange on Cash and Cash Equivalents		58	224	(15)	258
Increase (Decrease) in Cash and Cash Equivalents		(905)	(199)	(3,262)	621
Cash and Cash Equivalents, Beginning of Period		2,167	3,693	4,524	2,873
Cash and Cash Equivalents, End of Period		1,262	3,494	1,262	3,494

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

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 7

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc., including its subsidiaries, (together “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, 3, 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 interim Consolidated Financial Statements is found in Note 2.

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin.

The Company operates through the following reportable segments:

Upstream Segments

•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 within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and 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 China and the east coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

•Canadian Manufacturing, 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. Manufacturing, 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, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus also markets some of its own and third-party volumes of refined petroleum 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 internal usage of natural gas and condensate production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on market prices.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 8

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

In December 2022, Management elected to aggregate the commercial fuels business and the historical retail fuels business with the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. Prior period results were reclassified; see Note 26.

The following tabular financial information presents segmented information first by segment, then by product and geographic location.

A) Results of Operations – Segment and Operational Information

i) Results for the Three Months Ended September 30

	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2023	2022	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	7,571	8,764	810	1,036	402	450	8,783	10,250
Less: Royalties	1,082	1,136	27	68	26	22	1,135	1,226
	6,489	7,628	783	968	376	428	7,648	9,024
Expenses
Purchased Product (1)	462	1,919	438	464	—	—	900	2,383
Transportation and Blending (1)	2,324	2,758	73	64	—	4	2,397	2,826
Operating	688	689	150	141	76	85	914	915
Realized (Gain) Loss on Risk    Management	(6)	42	(4)	9	—	—	(10)	51
Operating Margin	3,021	2,220	126	290	300	339	3,447	2,849
Unrealized (Gain) Loss on Risk    Management	47	(2)	7	8	—	—	54	6
Depreciation, Depletion and    Amortization	785	652	104	103	130	132	1,019	887
Exploration Expense	—	7	—	—	2	66	2	73
(Income) Loss From Equity-    Accounted Affiliates	—	—	—	—	(11)	(9)	(11)	(9)
Segment Income (Loss)	2,189	1,563	15	179	179	150	2,383	1,892

(1)Comparative periods reflect certain revisions. See Note 26.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 9

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

	Downstream
For the three months ended	Canadian Manufacturing		U.S. Manufacturing		Total
September 30,	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	1,805	2,168	7,853	8,705	9,658	10,873
Less: Royalties	—	—	—	—	—	—
	1,805	2,168	7,853	8,705	9,658	10,873
Expenses
Purchased Product (1)	1,480	1,750	6,467	7,930	7,947	9,680
Transportation and Blending (1)	—	—	—	—	—	—
Operating	155	172	623	608	778	780
Realized (Gain) Loss on Risk Management	—	—	11	(77)	11	(77)
Operating Margin	170	246	752	244	922	490
Unrealized (Gain) Loss on Risk Management	—	—	(2)	(8)	(2)	(8)
Depreciation, Depletion and Amortization	50	42	109	91	159	133
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	120	204	645	161	765	365

For the three months ended	Corporate and Eliminations		Consolidated
September 30,	2023	2022	2023	2022
Revenues
Gross Sales (1)	(2,729)	(2,426)	15,712	18,697
Less: Royalties	—	—	1,135	1,226
	(2,729)	(2,426)	14,577	17,471
Expenses
Purchased Product (1)	(2,227)	(2,011)	6,620	10,052
Transportation and Blending (1)	(233)	(247)	2,164	2,579
Operating (1)	(139)	(191)	1,553	1,504
Realized (Gain) Loss on Risk Management	(1)	16	—	(10)
Unrealized (Gain) Loss on Risk Management	20	(16)	72	(18)
Depreciation, Depletion and Amortization	19	27	1,197	1,047
Exploration Expense	—	—	2	73
(Income) Loss From Equity-Accounted Affiliates	—	—	(11)	(9)
Segment Income (Loss)	(168)	(4)	2,980	2,253
General and Administrative	292	128	292	128
Finance Costs	106	207	106	207
Interest Income	(33)	(21)	(33)	(21)
Integration and Transaction Costs	12	27	12	27
Foreign Exchange (Gain) Loss, Net	133	316	133	316
Revaluation (Gain) Loss	—	(549)	—	(549)
Re-measurement of Contingent Payments	67	(109)	67	(109)
(Gain) Loss on Divestiture of Assets	—	60	—	60
Other (Income) Loss, Net	(22)	(59)	(22)	(59)
	555	—	555	—
Earnings (Loss) Before Income Tax			2,425	2,253
Income Tax Expense (Recovery)			561	644
Net Earnings (Loss)			1,864	1,609

(1)Comparative periods reflect certain revisions. See Note 26.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 10

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

ii) Results for the Nine Months Ended September 30

	Upstream
For the nine months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2023	2022	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	19,715	28,030	2,467	3,286	1,103	1,575	23,285	32,891
Less: Royalties	2,218	3,709	85	228	65	56	2,368	3,993
	17,497	24,321	2,382	3,058	1,038	1,519	20,917	28,898
Expenses
Purchased Product (1)	1,231	4,202	1,258	1,460	—	—	2,489	5,662
Transportation and Blending (1)	7,965	9,114	220	191	9	12	8,194	9,317
Operating	2,101	2,197	444	403	281	234	2,826	2,834
Realized (Gain) Loss on Risk    Management	(7)	1,468	—	17	—	—	(7)	1,485
Operating Margin	6,207	7,340	460	987	748	1,273	7,415	9,600
Unrealized (Gain) Loss on Risk    Management	44	(59)	(14)	7	—	—	30	(52)
Depreciation, Depletion and    Amortization	2,230	1,977	286	282	349	441	2,865	2,700
Exploration Expense	4	7	—	1	6	91	10	99
(Income) Loss From Equity-    Accounted Affiliates	6	8	—	—	(29)	(19)	(23)	(11)
Segment Income (Loss)	3,923	5,407	188	697	422	760	4,533	6,864

(1)Comparative periods reflect certain revisions. See Note 26.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 11

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

	Downstream
For the nine months ended	Canadian Manufacturing		U.S. Manufacturing		Total
September 30,	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	4,676	6,020	19,546	23,688	24,222	29,708
Less: Royalties	—	—	—	—	—	—
	4,676	6,020	19,546	23,688	24,222	29,708
Expenses
Purchased Product (1)	3,656	5,065	16,729	20,351	20,385	25,416
Transportation and Blending (1)	—	—	—	—	—	—
Operating	471	534	1,904	1,757	2,375	2,291
Realized (Gain) Loss on Risk Management	—	—	6	120	6	120
Operating Margin	549	421	907	1,460	1,456	1,881
Unrealized (Gain) Loss on Risk Management	—	—	(13)	(22)	(13)	(22)
Depreciation, Depletion and Amortization	136	164	314	259	450	423
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	413	257	606	1,223	1,019	1,480

For the nine months ended	Corporate and Eliminations		Consolidated
September 30,	2023	2022	2023	2022
Revenues
Gross Sales (1)	(6,069)	(5,772)	41,438	56,827
Less: Royalties	—	—	2,368	3,993
	(6,069)	(5,772)	39,070	52,834
Expenses
Purchased Product (1)	(4,717)	(4,040)	18,157	27,038
Transportation and Blending (1)	(715)	(911)	7,479	8,406
Operating (1)	(412)	(765)	4,789	4,360
Realized (Gain) Loss on Risk Management	2	23	1	1,628
Unrealized (Gain) Loss on Risk Management	71	(14)	88	(88)
Depreciation, Depletion and Amortization	59	86	3,374	3,209
Exploration Expense	—	—	10	99
(Income) Loss From Equity-Accounted Affiliates	—	—	(23)	(11)
Segment Income (Loss)	(357)	(151)	5,195	8,193
General and Administrative	617	545	617	545
Finance Costs	493	631	493	631
Interest Income	(100)	(44)	(100)	(44)
Integration and Transaction Costs	49	79	49	79
Foreign Exchange (Gain) Loss, Net	7	406	7	406
Revaluation (Gain) Loss	33	(549)	33	(549)
Re-measurement of Contingent Payments	83	142	83	142
(Gain) Loss on Divestiture of Assets	(11)	(244)	(11)	(244)
Other (Income) Loss, Net	(42)	(467)	(42)	(467)
	1,129	499	1,129	499
Earnings (Loss) Before Income Tax			4,066	7,694
Income Tax Expense (Recovery)			700	2,028
Net Earnings (Loss)			3,366	5,666

(1)Comparative periods reflect certain revisions. See Note 26.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 12

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

B) Revenues by Product

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Upstream
Crude Oil (1) (2)	6,666	7,384	17,671	24,143
Natural Gas (2)	563	973	1,975	2,740
NGLs (1)	382	571	1,088	1,684
Other	37	96	183	331
Total Upstream	7,648	9,024	20,917	28,898
Downstream
Canadian Manufacturing
Synthetic Crude Oil	657	657	1,607	1,786
Diesel	460	567	1,286	1,544
Gasoline	162	298	410	837
Asphalt	200	248	431	482
Other Products and Services	326	398	942	1,371
U.S. Manufacturing
Gasoline	3,822	3,919	9,336	11,180
Distillates	2,871	3,384	7,169	8,535
Asphalt	326	196	610	402
Other Products (2)	834	1,206	2,431	3,571
Total Downstream	9,658	10,873	24,222	29,708
Corporate and Eliminations (2)	(2,729)	(2,426)	(6,069)	(5,772)
Consolidated	14,577	17,471	39,070	52,834

(1)Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.

(2)Comparative periods reflect certain revisions. See Note 26.

C) Geographical Information

	Revenues (1)
	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Canada (2)	6,666	7,999	18,828	26,471
United States (2)	7,611	9,155	19,425	25,340
China	300	317	817	1,023
Consolidated	14,577	17,471	39,070	52,834

(1)Revenues by country are classified based on where the operations are located.

(2)Comparative periods reflect certain revisions. See Note 26.

	Non-Current Assets (1)
	September 30,	December 31,
As at	2023	2022
Canada	35,257	35,194
United States	5,284	4,824
China	1,758	2,064
Indonesia	356	365
Consolidated	42,655	42,447

(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.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 13

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
	September 30,	December 31,	September 30,	December 31,	September 30,	December 31,
As at	2023	2022	2023	2022	2023	2022
Oil Sands	785	674	24,271	24,657	687	638
Conventional	5	6	2,045	2,020	2	2
Offshore	6	5	2,679	2,549	103	152
Canadian Manufacturing	—	—	2,438	2,466	220	252
U.S. Manufacturing	—	—	4,981	4,482	286	329
Corporate and Eliminations	—	—	313	325	440	472
Consolidated	796	685	36,727	36,499	1,738	1,845

	Goodwill		Total Assets
	September 30,	December 31,	September 30,	December 31,
As at	2023	2022	2023	2022
Oil Sands	2,923	2,923	32,481	32,248
Conventional	—	—	2,278	2,410
Offshore	—	—	3,416	3,339
Canadian Manufacturing	—	—	3,320	3,172
U.S. Manufacturing	—	—	9,728	8,324
Corporate and Eliminations	—	—	3,204	6,376
Consolidated	2,923	2,923	54,427	55,869

E) Capital Expenditures (1)

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Capital Investment
Oil Sands	590	360	1,764	1,111
Conventional	100	67	323	188
Offshore
Asia Pacific	3	3	4	5
Atlantic	191	78	474	220
Total Upstream	884	508	2,565	1,524
Canadian Manufacturing	38	24	99	77
U.S. Manufacturing	88	300	435	774
Total Downstream	126	324	534	851
Corporate and Eliminations	15	34	29	59
	1,025	866	3,128	2,434
Acquisitions (Note 3)
Oil Sands	32	1,596	35	1,596
Conventional	1	5	5	6
U.S. Manufacturing (2)	—	—	337	—
	33	1,601	377	1,602
Total Capital Expenditures	1,058	2,467	3,505	4,036

(1)Includes expenditures on PP&E, E&E assets and capitalized interest.

(2)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 $320 million.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 14

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these interim Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These interim Consolidated Financial Statements were prepared in accordance with IFRS, as issued by the International Accounting Standards Board (“IASB”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting”, and were prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2022, except for income taxes. Income taxes on earnings or loss in the interim period are accrued using the income tax rate that would be applicable to the expected total annual earnings or loss.

Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements were condensed or disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2022, which were prepared in accordance with IFRS as issued by the IASB.

These interim Consolidated Financial Statements were approved by the Board of Directors effective November 1, 2023.

3. ACQUISITIONS

A) BP-Husky Refining LLC

i) Summary of the Acquisition

On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from BP Products North America Inc. (“bp”), a joint operation (the “Toledo Acquisition”). It provided 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$369 million (C$502 million) in cash, including 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

The preliminary purchase price allocation is based on Management’s best estimate of fair value. Upon finalizing the fair value of net assets acquired, adjustments to initial estimates, including goodwill, may be required.

The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition.

As at	February 28, 2023
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	69
Accounts Receivable and Accrued Revenues	3
Inventories	453
Property, Plant and Equipment	674
Right-of-Use Assets	33
Other Assets	10
Accounts Payable and Accrued Liabilities	(138)
Lease Liabilities	(33)
Decommissioning Liabilities	(5)
Other Liabilities	(70)
Total Identifiable Net Assets	996

The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which was collected.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 15

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

iii) Goodwill

As at	February 28, 2023
Total Purchase Consideration	502
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo	494
Fair Value of Identifiable Net Assets	(996)
Goodwill	—

Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC

Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11, “Joint Arrangements”; therefore, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, “Consolidated Financial Statements”, and, accordingly Toledo was consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized as a revaluation (gain) loss in the Consolidated Statements of Earnings (Loss). When a disposition includes a foreign operation, the associated cumulative amount of foreign exchange differences are reclassified to earnings as part of the revaluation (gain) loss.

The acquisition-date fair value of the previously held interest was estimated to be $494 million and the net carrying value of Toledo assets was $539 million. On February 28, 2023, Cenovus recognized a non-cash revaluation loss of $33 million ($22 million, after tax) on the re-measurement of its existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign exchange differences.

iv) Integration and Transaction Costs

For the three and nine months ended September 30, 2023, integration costs of $10 million and $38 million respectively (three and nine months ended September 30, 2022 – $nil), and transaction costs of $2 million and $11 million, respectively, (three and nine months ended September 30, 2022 – $2 million), associated with the Toledo Acquisition were recognized in the Consolidated Statements of Earnings (Loss).

v) Revenue and Profit Contribution

The acquired business contributed revenues of $2.4 billion and net loss of $84 million for the period from February 28, 2023, to September 30, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The Toledo Refinery was fully operational in June. If the closing of the Toledo Acquisition had occurred on January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the nine months ended September 30, 2023, would be $39.1 billion and $3.3 billion, respectively. These amounts were calculated using results from the acquired business, adjusting them for:

•Additional Depreciation, Depletion and Amortization (“DD&A”) that would be charged assuming the fair value adjustments to PP&E had applied from January 1, 2023.

•Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023.

•The consequential tax effects.

This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had actually occurred on January 1, 2023.

B) Sunrise Oil Sands Partnership

On August 31, 2022, Cenovus closed a transaction with BP Canada Energy Group ULC (“bp Canada”) to purchase the remaining 50 percent interest in Sunrise Oil Sands Partnership (“SOSP”), previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core strength in the oil sands.

The final purchase price allocation was based on Management’s best estimate of the assets acquired and liabilities assumed. No additional adjustments were made to the purchase price allocation in the period. For more details, see Note 5 of the annual Consolidated Financial Statements for the year ended December 31, 2022.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 16

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

4. FINANCE COSTS

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Interest Expense – Short-Term Borrowings and Long-Term Debt	94	121	285	381
Net Premium (Discount) on Redemption of Long-Term Debt (1)	(84)	(4)	(84)	(29)
Interest Expense – Lease Liabilities (Note 14)	41	40	121	123
Unwinding of Discount on Decommissioning Liabilities (Note 16)	55	43	165	132
Other	5	9	18	27
	111	209	505	634
Capitalized Interest	(5)	(2)	(12)	(3)
	106	207	493	631

(1)Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.

5. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	28	324	(119)	444
Other	31	(26)	20	(25)
Unrealized Foreign Exchange (Gain) Loss	59	298	(99)	419
Realized Foreign Exchange (Gain) Loss	74	18	106	(13)
	133	316	7	406

6. INCOME TAXES

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Current Tax
Canada	484	187	941	1,124
United States	4	(185)	4	96
Asia Pacific	68	64	152	173
Other International	7	10	19	10
Total Current Tax Expense (Recovery)	563	76	1,116	1,403
Deferred Tax Expense (Recovery)	(2)	568	(416)	625
	561	644	700	2,028

For the nine months ended September 30, 2023, Cenovus incurred a deferred tax recovery of $416 million of which $176 million related to a step-up in the tax basis on the Toledo Acquisition on February 28, 2023.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 17

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

7. PER SHARE AMOUNTS

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

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Net Earnings (Loss)	1,864	1,609	3,366	5,666
Effect of Cumulative Dividends on Preferred Shares	(9)	(9)	(27)	(26)
Net Earnings (Loss) – Basic and Diluted	1,855	1,600	3,339	5,640
Basic – Weighted Average Number of Shares (thousands)	1,891,937	1,927,864	1,900,952	1,962,813
Dilutive Effect of Warrants	6,408	41,956	27,491	45,002
Dilutive Effect of Net Settlement Rights	6,752	7,188	7,643	10,657
Dilutive Effect of Cenovus Replacement Stock Options	—	1,637	630	—
Diluted – Weighted Average Number of Shares (thousands)	1,905,097	1,978,645	1,936,716	2,018,472
Net Earnings (Loss) Per Common Share – Basic ($)	0.98	0.83	1.76	2.87
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)	0.97	0.81	1.72	2.79

(1)For the three months ended September 30, 2023, net earnings of $6 million and common shares of 0.6 million related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the impact was anti-dilutive. For the nine months ended September 30, 2022, net earnings of $35 million and common shares of 1.6 million related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive.

(2)For the three and nine months ended September 30, 2023, net settlement rights (“NSRs”) of 1.5 million and 1.5 million, respectively, (three and nine months ended September 30, 2022 – 2.0 million and 2.0 million, respectively) were excluded from the calculation of diluted weighted average number of shares as the effect was anti-dilutive.

B) Common Share Dividends

	2023		2022
For the nine months ended September 30,	Per Share	Amount	Per Share	Amount
Base Dividends	0.385	729	0.245	481
Variable Dividends	—	—	—	—
Total Common Share Dividends Declared and Paid	0.385	729	0.245	481

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

On November 1, 2023, the Company’s Board of Directors declared a fourth quarter base dividend of $0.140 per common share, payable on December 29, 2023, to common shareholders of record as at December 15, 2023.

C) Preferred Share Dividends

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Series 1 First Preferred Shares	2	1	5	5
Series 2 First Preferred Shares	1	1	2	1
Series 3 First Preferred Shares	3	3	9	9
Series 5 First Preferred Shares	2	3	7	7
Series 7 First Preferred Shares	1	1	4	4
Total Preferred Share Dividends Declared	9	9	27	26

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

In the three and nine months ended September 30, 2023, the Company paid $nil and $27 million, respectively, in preferred share dividends (three and nine months ended September 30, 2022 – $9 million and $26 million, respectively).

On November 1, 2023, the Company’s Board of Directors declared fourth quarter dividends of $9 million payable on January 2, 2024, to preferred shareholders of record as at December 15, 2023.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 18

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

8. EXPLORATION AND EVALUATION ASSETS, NET

	Total
As at December 31, 2022	685
Acquisition	31
Additions	80
As at September 30, 2023	796

9. PROPERTY, PLANT AND EQUIPMENT, NET

	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Manufacturing Assets	Other Assets (1)	Total
COST
As at December 31, 2022	43,528	254	12,132	1,825	57,739
Acquisitions (Note 3) (2)	9	—	674	—	683
Additions	2,485	19	508	36	3,048
Change in Decommissioning Liabilities	42	—	2	—	44
Divestitures (Note 3) (2)	(17)	—	(633)	(17)	(667)
Exchange Rate Movements and Other	(19)	5	(39)	(8)	(61)
As at September 30, 2023	46,028	278	12,644	1,836	60,786
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2022	14,302	106	5,547	1,285	21,240
Depreciation, Depletion and Amortization (3)	2,726	16	366	42	3,150
Divestitures (Note 3) (2)	(8)	—	(299)	(12)	(319)
Exchange Rate Movements and Other	13	4	(23)	(6)	(12)
As at September 30, 2023	17,033	126	5,591	1,309	24,059
CARRYING VALUE
As at December 31, 2022	29,226	148	6,585	540	36,499
As at September 30, 2023	28,995	152	7,053	527	36,727

(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.

(3)DD&A includes asset write-downs of $20 million in the Oil Sands segment and $8 million in the Canadian Manufacturing segment.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 19

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

10. RIGHT-OF-USE ASSETS, NET

	Real Estate	Transportation and Storage Assets (1)	Manufacturing Assets	Other Assets (2)	Total
COST
As at December 31, 2022	599	1,840	174	74	2,687
Acquisitions (Note 3) (3)	1	24	8	—	33
Additions	1	44	—	—	45
Modifications	(4)	37	1	—	34
Re-measurements	—	(11)	—	5	(6)
Divestitures (Note 3) (3)	—	—	(19)	—	(19)
Terminations	(3)	(1)	—	(2)	(6)
Exchange Rate Movements and Other	(4)	24	—	3	23
As at September 30, 2023	590	1,957	164	80	2,791
ACCUMULATED DEPRECIATION
As at December 31, 2022	127	645	58	12	842
Depreciation	27	170	17	10	224
Divestitures (Note 3) (3)	—	—	(12)	—	(12)
Terminations	(1)	(1)	—	(1)	(3)
Exchange Rate Movements and Other	(3)	8	(2)	(1)	2
As at September 30, 2023	150	822	61	20	1,053
CARRYING VALUE
As at December 31, 2022	472	1,195	116	62	1,845
As at September 30, 2023	440	1,135	103	60	1,738

(1)Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.

(2)Includes assets in the commercial fuels business, fleet vehicles 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.

11. JOINT ARRANGEMENTS

A) Joint Operations

Cenovus has a number of joint operations in the Upstream segments. The Company also holds the following joint operation in the U.S. Manufacturing segment.

WRB Refining LP (“WRB”)

Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. 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.

B) Joint Ventures

Husky-CNOOC Madura Ltd.

The Company holds a 40 percent interest in the jointly controlled entity, HCML, which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia. The Company’s share of equity investment income (loss) related to the joint venture, distributions received and contributions paid are recorded in (income) loss from equity-accounted affiliates in the Offshore segment.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 20

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations

	Nine Months Ended
For the periods ended September 30,	2023	2022
Revenue	439	256
Expenses	373	247
Net Earnings (Loss)	66	9

Balance Sheet

	September 30,	December 31,
As at	2023	2022
Current Assets (1)	285	247
Non-Current Assets	1,767	1,926
Current Liabilities	127	160
Non-Current Liabilities	1,114	1,293
Net Assets	811	720

(1)Includes cash and cash equivalents of $76 million (December 31, 2022 – $64 million).

For the nine months ended September 30, 2023, the Company’s share of income from the equity-accounted affiliate was $29 million (2022 – $19 million). As at September 30, 2023, the carrying amount of the Company’s share of net assets was $356 million (December 31, 2022 – $365 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 nine months ended September 30, 2023, the Company received $61 million of distributions from HCML (2022 – $32 million) and paid $31 million in contributions (2022 – $41 million).

Husky Midstream Limited Partnership

The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power Assets Holdings Limited holding a 49 percent interest and CK Infrastructure Holdings Limited holding a 16 percent interest in HMLP. The Company’s share of equity investment income related to the joint venture, only in excess of the cumulated unrecognized loss, distributions received and contributions paid, is recorded in (income) loss from equity-accounted affiliates in the Oil Sands segment.

For the nine months ended September 30, 2023, HMLP had net earnings of $118 million (2022 – $112 million). The Company’s share of (income) loss from the equity-accounted affiliate does not equal the 35 percent of the net earnings of HMLP due to the nature of the profit-sharing arrangement as set forth in the partnership agreement. The Company’s share of earnings will fluctuate depending on certain income thresholds of HMLP. For the nine months ended September 30, 2023, the Company did not record its share of pre-tax loss relating to HMLP of $20 million (2022 – pre-tax loss of $14 million). The carrying value was $nil at September 30, 2023 (December 31, 2022 – $nil).

As at September 30, 2023, the Company had $42 million in cumulative unrecognized losses and other comprehensive income (“OCI”), net of tax (December 31, 2022 – $28 million).

For the nine months ended September 30, 2023, the Company received $56 million of distributions from HMLP (2022 – $22 million) and paid $62 million in contributions (2022 – $30 million). The net amount of the distributions received and contributions paid is recorded in (income) loss from equity-accounted affiliates in the Oil Sands segment.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 21

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

12. OTHER ASSETS

	September 30,	December 31,
As at	2023	2022
Long-Term Receivables and Prepaids	48	120
Precious Metals	79	86
Net Investment in Finance Leases	62	62
Private Equity Investments (Note 22)	66	55
Intangible Assets	11	19
	266	342

13. DEBT AND CAPITAL STRUCTURE

A) Short-Term Borrowings

		September 30,	December 31,
As at	Notes	2023	2022
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	14	115
Total Debt Principal		14	115

i) Uncommitted Demand Facilities

As at September 30, 2023, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2022 – $1.9 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 September 30, 2023, there were outstanding letters of credit aggregating to $353 million (December 31, 2022 – $490 million) and no direct borrowings.

ii) WRB Uncommitted Demand Facilities

WRB has uncommitted demand facilities of 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 September 30, 2023, US$20 million was drawn on these facilities, of which Cenovus’s proportionate share was US$10 million (C$14 million). As at December 31, 2022, Cenovus’s proportionate share of the capacity was US$225 million and US$85 million (C$115 million) of this capacity was drawn.

B) Long-Term Debt

	September 30,	December 31,
As at	2023	2022
Committed Credit Facility (1)	—	—
U.S. Dollar Denominated Unsecured Notes	5,140	6,537
Canadian Dollar Unsecured Notes	2,000	2,000
Total Debt Principal	7,140	8,537
Debt Premiums (Discounts), Net, and Transaction Costs	84	154
Long-Term Debt	7,224	8,691

(1) The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

i) Committed Credit Facility

As at September 30, 2023, the Company had in place a committed credit facility that consists of a $1.8 billion tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at September 30, 2023, no amount was drawn on the credit facility (December 31, 2022 – $nil).

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 22

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes

In September 2023, the Company purchased outstanding principal amounts of the following unsecured notes.

	US$ Principal
U.S. Dollar Unsecured Notes
4.40% due April 15, 2029	57
5.25% due June 15, 2037	250
6.80% due September 15, 2037	196
6.75% due November 15, 2039	283
4.45% due September 15, 2042	6
5.20% due September 15, 2043	2
5.40% due June 15, 2047	231
	1,025

The principal amounts of the Company’s outstanding unsecured notes are:

	September 30, 2023		December 31, 2022
	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Unsecured Notes
5.38% due July 15, 2025	133	181	133	181
4.25% due April 15, 2027	373	505	373	505
4.40% due April 15, 2029	183	247	240	324
2.65% due January 15, 2032	500	676	500	677
5.25% due June 15, 2037	333	450	583	790
6.80% due September 15, 2037	191	259	387	524
6.75% due November 15, 2039	652	881	935	1,267
4.45% due September 15, 2042	91	123	97	131
5.20% due September 15, 2043	27	36	29	39
5.40% due June 15, 2047	569	768	800	1,083
3.75% due February 15, 2052	750	1,014	750	1,016
	3,802	5,140	4,827	6,537
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		7,140		8,537

As at September 30, 2023, 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 well below this limit.

C) Capital Structure

Cenovus’s capital structure consists of shareholders’ equity plus 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, 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 Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 23

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

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 billion over the long-term at a West Texas Intermediate (“WTI”) price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices.

Net Debt to Adjusted EBITDA

	September 30,	December 31,
As at	2023	2022
Short-Term Borrowings	14	115
Current Portion of Long-Term Debt	—	—
Long-Term Portion of Long-Term Debt	7,224	8,691
Total Debt	7,238	8,806
Less: Cash and Cash Equivalents	(1,262)	(4,524)
Net Debt	5,976	4,282
Net Earnings (Loss)	4,150	6,450
Add (Deduct):
Finance Costs	682	820
Interest Income	(137)	(81)
Income Tax Expense (Recovery)	953	2,281
Depreciation, Depletion and Amortization	4,844	4,679
Exploration and Evaluation Asset Write-downs	1	64
(Income) Loss From Equity-Accounted Affiliates	(27)	(15)
Unrealized (Gain) Loss on Risk Management	50	(126)
Foreign Exchange (Gain) Loss, Net	(56)	343
Revaluation (Gain) Loss	33	(549)
Re-measurement of Contingent Payments	103	162
(Gain) Loss on Divestiture of Assets	(36)	(269)
Other (Income) Loss, Net	(107)	(532)
Adjusted EBITDA (1)	10,453	13,227
Net Debt to Adjusted EBITDA	0.6x	0.3x

(1)Calculated on a trailing twelve-month basis.

Net Debt to Adjusted Funds Flow

	September 30,	December 31,
As at	2023	2022
Net Debt	5,976	4,282
Cash From (Used in) Operating Activities	7,412	11,403
(Add) Deduct:
Settlement of Decommissioning Liabilities	(206)	(150)
Net Change in Non-Cash Working Capital	(1,469)	575
Adjusted Funds Flow (1)	9,087	10,978
Net Debt to Adjusted Funds Flow	0.7x	0.4x

(1)Calculated on a trailing twelve-month basis.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 24

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

Net Debt to Capitalization

	September 30,		December 31,
As at	2023		2022
Net Debt	5,976		4,282
Shareholders’ Equity	28,814		27,576
Capitalization	34,790		31,858
Net Debt to Capitalization	17	%	13	%

14. LEASE LIABILITIES

	Total
As at December 31, 2022	2,836
Acquisitions (Note 3) (1)	33
Additions	45
Interest Expense (Note 4)	121
Lease Payments	(337)
Modifications	34
Re-measurements	(6)
Divestitures (Note 3) (1)	(11)
Terminations	(8)
Exchange Rate Movements and Other	26
As at September 30, 2023	2,733
Less: Current Portion	315
Long-Term Portion	2,418

(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.

15. CONTINGENT PAYMENTS

In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments, up to $600 million, from SOSP to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average Western Canadian Select (“WCS”) price in a quarter exceeds $52.00 per barrel. The quarterly payment is 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 is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum payment over the remaining four quarters of the contract is $301 million.

The variable payment will be re-measured to fair value at each reporting date, with changes in fair value recorded to re-measurement of contingent payments in the Consolidated Statements of Earnings (Loss).

Payments made during the nine months ended September 30, 2023, totaled $207 million for the quarterly payment periods ending November 30, 2022, February 28, 2023, and May 31, 2023.

	Total
As at December 31, 2022	419
Liabilities Settled or Payable	(207)
Re-measurement	83
As at September 30, 2023	295

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 25

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

16. DECOMMISSIONING LIABILITIES

	Total
As at December 31, 2022	3,559
Liabilities Incurred	12
Liabilities Acquired (Note 3) (1)	5
Liabilities Settled	(156)
Liabilities Disposed (Note 3) (1)	(5)
Change in Estimated Future Cash Flows	32
Unwinding of Discount on Decommissioning Liabilities (Note 4)	165
Exchange Rate Movements	(9)
As at September 30, 2023	3,603

(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 September 30, 2023, the undiscounted amount of estimated future cash flows required to settle the obligation was discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2022 – 6.1 percent) and assumes an inflation rate of two percent (December 31, 2022 – 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 September 30, 2023, the Company had $209 million in restricted cash (December 31, 2022 – $209 million).

17. OTHER LIABILITIES

	September 30,	December 31,
As at	2023	2022
Renewable Volume Obligation, Net (1)	400	101
Pension and Other Post-Employment Benefit Plan	191	201
Provision for West White Rose Expansion Project	169	204
Provisions for Onerous and Unfavourable Contracts	76	95
Employee Long-Term Incentives	127	245
Drilling Provisions	25	31
Deferred Revenue	39	45
Other	156	120
	1,183	1,042

(1)The gross amounts of the renewable volume obligation and renewable identification numbers asset were $1.1 billion and $0.7 billion, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively).

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 26

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

18. 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

	September 30, 2023		December 31, 2022
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	1,909,190	16,320	2,001,211	17,016
Issued Upon Exercise of Warrants	2,314	23	9,399	93
Issued Under Stock Option Plans	3,443	54	11,069	170
Purchase of Common Shares Under NCIBs	(29,388)	(251)	(112,489)	(959)
Outstanding, End of Period	1,885,559	16,146	1,909,190	16,320

As at September 30, 2023, there were 45.2 million (December 31, 2022 – 43.1 million) common shares available for future issuance under the stock option plan.

C) Normal Course Issuer Bid

For the nine months ended September 30, 2023, the Company purchased and cancelled 29.4 million common shares through the existing NCIB. The shares were purchased at a volume weighted average price of $24.19 per common share for a total of $711 million. Paid in surplus was reduced by $460 million, representing the excess of the purchase price of the common shares over their average carrying value.

From October 1, 2023, to October 30, 2023, the Company purchased an additional 3.3 million common shares for $89 million. As at October 30, 2023, the Company can further purchase up to 92.5 million common shares under the existing NCIB. The current NCIB will expire on November 8, 2023.

On November 1, 2023, the Company received approval from the Board of Directors to apply to the TSX for an additional NCIB program. Subject to acceptance by the TSX, the Company will be able to purchase up to approximately 133 million common shares for a period of twelve months.

D) Issued and Outstanding – Preferred Shares

For the nine months ended September 30, 2023, there were no preferred shares issued. As at September 30, 2023, there were 36 million preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 – $519 million).

As at September 30, 2023	Dividend Reset Date	Dividend Rate		Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	%	10,740
Series 2 First Preferred Shares (1)	Quarterly	6.89	%	1,260
Series 3 First Preferred Shares	December 31, 2024	4.69	%	10,000
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 5.86 percent for the period from December 31, 2022, to March 30, 2023, 6.29 percent for the period from March 31, 2023, to June 29, 2023, and 6.29 percent from June 30, 2023, to September 29, 2023.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 27

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

E) Issued and Outstanding – Warrants

	September 30, 2023		December 31, 2022
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	55,720	184	65,119	215
Exercised	(2,314)	(7)	(9,399)	(31)
Purchased and Cancelled	(45,485)	(151)	—	—
Outstanding, End of Period	7,921	26	55,720	184

The exercise price of the Cenovus warrants is $6.54 per share.

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 of $6.54 per common share, 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.

Cenovus has the option to pay the warrant purchase price of $711 million through the remainder of 2023, with full payment required by January 5, 2024. For the three months ended September 30, 2023, total payments of $600 million were made.

19. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Pension and Other Post-Employment Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
As at December 31, 2021	28	27	629	684
Other Comprehensive Income (Loss), Before Tax	78	2	896	976
Income Tax (Expense) Recovery	(20)	—	—	(20)
As at September 30, 2022	86	29	1,525	1,640
As at December 31, 2022	99	29	1,342	1,470
Other Comprehensive Income (Loss), Before Tax	20	—	(43)	(23)
Reclassification on Divestiture (Note 3)	—	—	12	12
Income Tax (Expense) Recovery	(5)	—	—	(5)
As at September 30, 2023	114	29	1,311	1,454

20. 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.

On February 27, 2023, Cenovus granted PSUs and RSUs to certain employees under its new Performance Share Unit Plan for Local Employees in the Asia Pacific Region and Restricted Share Unit Plan for Local Employees in the Asia Pacific Region. The PSUs are time-vested whole-share units that entitle employees to receive a cash payment equal to the value of a Cenovus common share. The number of units 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. The RSUs are whole-share units and entitle employees to receive, upon vesting, a cash payment equal to the value of a Cenovus common share.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 28

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

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

	Units Outstanding	Units Exercisable
As at September 30, 2023	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	12,158	6,905
Cenovus Replacement Stock Options	1,095	1,072
Performance Share Units	10,193	—
Restricted Share Units	7,217	—
Deferred Share Units	1,662	1,662

The weighted average exercise price of NSRs and Cenovus replacement stock options outstanding as at September 30, 2023, were $13.62 and $6.52, respectively.

	Units Granted	Units Vested and Exercised/ Paid Out
For the nine months ended September 30, 2023	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	1,571	3,591
Cenovus Replacement Stock Options	—	2,031
Performance Share Units	2,533	972
Restricted Share Units	2,955	2,299
Deferred Share Units	162	33

	Weighted Average Exercise Price	Units Exercised
For the nine months ended September 30, 2023	($/unit)	(thousands)
Stock Options With Associated Net Settlement Rights Exercised for Net Cash Payment	12.94	3,392
Stock Options With Associated Net Settlement Rights Exercised and Net Settled for Common Shares (1)	17.22	199
Cenovus Replacement Stock Options Exercised and Net Settled for Cash	10.11	2,028
Cenovus Replacement Stock Options Exercised and Net Settled for Common Shares (2)	3.54	3

(1)NSRs were net settled for 49 thousand common shares.

(2)Cenovus replacement stock options were net settled for 2 thousand common shares.

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

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Stock Options With Associated Net Settlement Rights	2	3	9	12
Cenovus Replacement Stock Options	6	(5)	(1)	36
Performance Share Units	98	1	125	66
Restricted Share Units	35	4	56	65
Deferred Share Units	10	(4)	7	14
Stock-Based Compensation Expense (Recovery)	151	(1)	196	193

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 29

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

21. RELATED PARTY TRANSACTIONS

Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 11). As the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs.

The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or on a cost recovery basis with certain restrictions. For the three and nine months ended September 30, 2023, the Company charged HMLP $49 million and $112 million, respectively, for construction costs and management services (three and nine months ended September 30, 2022 – $56 million and $133 million, respectively).

The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the three and nine months ended September 30, 2023, the Company incurred costs of $67 million and $205 million, respectively, for the use of HMLP’s pipeline systems, as well as for transportation and storage services (three and nine months ended September 30, 2022 – $64 million and $197 million, respectively).

22. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, net investment in finance leases, risk management assets and liabilities, investments in the equity of companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and other liabilities. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of restricted cash, net investment in finance leases and long-term receivables 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 September 30, 2023, the carrying value of Cenovus’s long-term debt was $7.2 billion and the fair value was $6.2 billion (December 31, 2022, carrying value – $8.7 billion; fair value – $7.8 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 on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available.

The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:

	Total
As at December 31, 2022	55
Acquisition	11
As at September 30, 2023	66

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures, as well as renewable power, power and foreign exchange contracts. The Company may also enter into swaps, forwards, and options to manage commodity, foreign exchange and interest rate exposures. The Company’s risk management assets and liabilities are measured as Level 2 or Level 3 prices in the fair value hierarchy. Level 2 prices sourced from observable data or market corroboration refer to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Level 3 prices are sourced from partially unobservable data used in internal valuations.

Crude oil, natural gas, condensate, refined product 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, interest rate swaps and cross currency interest rate swaps is calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2).

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 30

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

The fair value of renewable power contracts are 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 that consists of individuals who are knowledgeable and have experience in fair value techniques.

Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets (for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings (Loss) within (gain) loss on risk management.

Summary of Risk Management Positions

	September 30, 2023			December 31, 2022
	Risk Management			Risk Management
As at	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	—	49	(49)	2	40	(38)
Power Swap Contracts	4	2	2	1	7	(6)
Renewable Power Contracts	21	—	21	90	—	90
Foreign Exchange Rate Contracts	—	1	(1)	—	—	—
	25	52	(27)	93	47	46

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

	September 30,	December 31,
As at	2023	2022
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(48)	(44)
Level 3 – Prices Sourced From Partially Unobservable Data	21	90
	(27)	46

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

	Total
As at December 31, 2022	46
Change in Fair Value of Contracts in Place, Beginning of Year	1
Change in Fair Value of Contracts Entered Into During the Period	(76)
Fair Value of Contracts Realized During the Period	1
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	1
As at September 30, 2023	(27)

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

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Realized (Gain) Loss	—	(10)	1	1,628
Unrealized (Gain) Loss	72	(18)	88	(88)
(Gain) Loss on Risk Management	72	(28)	89	1,540

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

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 31

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

D) Fair Value of Contingent Payments

The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value in the Consolidated Balance Sheets within contingent payments. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes 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 September 30, 2023, the fair value of the variable payment was estimated to be $295 million applying a credit-adjusted risk-free rate of 5.4 percent.

As at September 30, 2023, average WCS forward pricing for the remaining term of the variable payment is $89.81 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 36.6 percent and 5.9 percent, respectively. A sensitivity analysis for the following inputs to the option pricing model was performed, with fluctuations in all other variables held constant, and found to have a nominal impact on earnings before income tax:

•A $10.00 per barrel increase or decrease in WCS forward prices.

•A 10 percent increase or decrease in WTI option volatility.

•A five percent increase or decrease in Canadian to U.S. dollar foreign exchange rate option volatility.

23. 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 to manage exposure to future carbon compliance costs or to offset select carbon emissions.

The Company entered into risk management positions to help capture incremental margin expected to be received in future periods at the time products will be sold and to mitigate overall exposure to fluctuations in commodity prices related to inventories and physical sales. Mitigation of commodity price volatility may utilize financial positions to protect future cash flows. To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs, power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts.

As at September 30, 2023, the fair value of risk management positions was a net liability of $27 million and consisted of crude oil, natural gas, condensate, refined products, power, including renewable power, and foreign exchange rate instruments. As at September 30, 2023, there were foreign exchange contracts with a notional value of US$302 million (December 31, 2022 – US$168 million) and no interest rate contracts or cross currency interest rate swap contracts (December 31, 2022 – $nil).

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 32

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

Net Fair Value of Risk Management Positions

As at September 30, 2023	Notional Volumes (1) (2)	Terms (3)	Weighted Average Price (1) (2)	Fair Value Asset (Liability)
Futures Contracts Related to Blending (4)
WTI Fixed – Sell	6.2 MMbbls	October 2023 - June 2024	US$83.06/bbl	(52)
WTI Fixed – Buy	2.6 MMbbls	October 2023 - June 2024	US$86.23/bbl	13
Power Swap Contracts				2
Renewable Power Contracts				21
Other Financial Positions (5)				(10)
Foreign Exchange Rate Contracts				(1)
Total Fair Value				(27)

(1)    Million barrels (“MMbbls”). Barrel (“bbl”).

(2)    Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3)    Includes individual contracts with terms less than one year.

(4)    WTI futures contracts are used to help manage price exposure to condensate used for blending.

(5)    Includes risk management positions related to WCS, heavy oil and condensate differential contracts, 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. manufacturing and marketing activities.

A) Commodity Price and Foreign Exchange Rate Risk

Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at September 30, 2023	Sensitivity Range	Increase	Decrease
WCS and Condensate Differential Price	± US$2.50/bbl Applied to Differential Hedges Tied to Production	2	(2)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(23)	23
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(5)	5
Natural Gas Basis Price	± US$0.50/Mcf (1) Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/MWh (2) Applied to Power Hedges	109	(109)
U.S. to Canadian Dollar Exchange Rate	± 0.05 in the U.S. to Canadian Dollar Exchange Rate	26	(30)

(1)One thousand cubic feet (“Mcf”).

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

A US$10.00 per barrel increase or decrease in the crude oil commodity price would result in a nominal unrealized gain (loss) impact to earnings before income tax.

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 September 30, 2023, approximately 83 percent (December 31, 2022 – 85 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 98 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss on these accounts was 0.6 percent as at September 30, 2023 (December 31, 2022 – 0.4 percent).

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 33

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

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. Cenovus manages its liquidity risk through the active management of cash and debt, and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 13, 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 the bottom of the commodity price cycle to manage the Company’s overall debt position.

Undiscounted cash outflows relating to financial liabilities are:

As at September 30, 2023	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,435	—	—	—	6,435
Short-Term Borrowings	14	—	—	—	14
Lease Liabilities (2)	445	734	577	2,700	4,456
Long-Term Debt (2)	318	807	3,038	7,372	11,535
Contingent Payments	300	—	—	—	300
As at December 31, 2022	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,124	—	—	—	6,124
Short-Term Borrowings	115	—	—	—	115
Lease Liabilities (2)	426	746	596	2,889	4,657
Long-Term Debt (2)	401	983	2,014	11,196	14,594
Contingent Payments	271	167	—	—	438

(1)Includes current risk management liabilities.

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

24. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital

	September 30,	December 31,
As at	2023	2022
Total Current Assets	10,745	12,430
Total Current Liabilities	7,205	8,021
Working Capital	3,540	4,409

As at September 30, 2023, adjusted working capital was $3.8 billion (December 31, 2022 – $4.7 billion), excluding the current portion of the contingent payments of $295 million (December 31, 2022 – $263 million).

Changes in non-cash working capital is as follows:

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Accounts Receivable and Accrued Revenues	(1,288)	1,746	(1,097)	119
Income Tax Receivable	157	(111)	(12)	(88)
Inventories	(505)	1,138	(343)	(172)
Accounts Payable and Accrued Liabilities	851	(1,547)	69	(388)
Income Tax Payable	107	74	(1,056)	877
Total Change in Non-Cash Working Capital	(678)	1,300	(2,439)	348
Net Change in Non-Cash Working Capital – Operating Activities	(641)	1,193	(2,142)	(98)
Net Change in Non-Cash Working Capital – Investing Activities	(37)	107	(297)	446
Total Change in Non-Cash Working Capital	(678)	1,300	(2,439)	348

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 34

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

B) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable	Warrant Purchase Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2021	—	—	79	12,385	2,957
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(81)	—	—
(Repayment) of Long-Term Debt	—	—	—	(4,149)	—
Principal Repayment of Leases	—	—	—	—	(228)
Base Dividends Paid on Common Shares	(481)	—	—	—	—
Dividends Paid on Preferred Shares	(26)	—	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	—	(29)	—
Finance and Transaction Costs	—	—	—	(24)	—
Lease Additions	—	—	—	—	19
Lease Modifications	—	—	—	—	46
Lease Re-measurements	—	—	—	—	3
Lease Terminations	—	—	—	—	(2)
Base Dividends Declared on Common Shares	481	—	—	—	—
Dividends Declared on Preferred Shares	26	—	—	—	—
Exchange Rate Movements and Other	—	—	2	591	74
As at September 30, 2022	—	—	—	8,774	2,869
As at December 31, 2022	9	—	115	8,691	2,836
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(101)	—	—
(Repayment) of Long-Term Debt	—	—	—	(1,346)	—
Principal Repayment of Leases	—	—	—	—	(216)
Base Dividends Paid on Common Shares	(729)	—	—	—	—
Dividends Paid on Preferred Shares	(27)	—	—	—	—
Payment for Purchase of Warrants	—	(600)	—	—	—
Finance and Transaction Costs	—	(2)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	—	(84)	—
Finance and Transaction Costs	—	2	—	(15)	—
Lease Acquisitions	—	—	—	—	33
Lease Additions	—	—	—	—	45
Lease Modifications	—	—	—	—	34
Lease Re-measurements	—	—	—	—	(6)
Lease Divestitures	—	—	—	—	(11)
Lease Terminations	—	—	—	—	(8)
Base Dividends Declared on Common Shares	729	—	—	—	—
Dividends Declared on Preferred Shares	27	—	—	—	—
Warrants Purchased and Cancelled	—	711	—	—	—
Exchange Rate Movements and Other	—	—	—	(22)	26
As at September 30, 2023	9	111	14	7,224	2,733

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 35

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

25. 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 September 30, 2023	Remainder of Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	432	1,958	1,717	1,453	1,408	13,263	20,231
Product Purchases	393	779	—	—	—	—	1,172
Real Estate (3)	15	53	54	56	59	619	856
Obligation to Fund Equity-Accounted Affiliate (4)	25	105	96	96	91	145	558
Other Long-Term Commitments (5) (6)	284	185	163	151	142	948	1,873
Total Commitments	1,149	3,080	2,030	1,756	1,700	14,975	24,690

(1)Includes transportation commitments of $9.1 billion (December 31, 2022 – $9.1 billion) that are subject to regulatory approval or were approved, but are not yet in service. Terms are up to 20 years subsequent to the commencement of the contract. Estimated tolls reflect the original contract rate and are subject to change pending approval by the Canada Energy Regulator.

(2)As at September 30, 2023, the Company had commitments with HMLP that included $2.1 billion related to long-term transportation and storage commitments (December 31, 2022 – $2.2 billion).

(3)Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision was provided.

(4)Relates to funding obligations for HCML.

(5)Includes Cenovus’s proportionate share of the commitments related to WRB and joint arrangements in the Offshore segment.

(6)The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023.

There were outstanding letters of credit aggregating to $353 million (December 31, 2022 – $490 million) issued as security for financial and performance conditions under certain contracts.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its interim Consolidated Financial Statements.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

26. PRIOR PERIOD REVISIONS

Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was revised.

Classification Revisions

During the three months ended September 30, 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made:

•Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense.

•Report sales of feedstock between the Oil Sands, Conventional and U.S. Manufacturing segments on a net basis, which resulted in a reclassification between gross sales and purchased product.

Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 36

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position.

Change to Reporting Segments

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. In December 2022, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods were reclassified to reflect this change, with no impact to net earnings (loss), cash flows or financial position.

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

i) Three Months Ended March 31, 2023, and June 30, 2023

	Three Months Ended March 31, 2023 (1)			Three Months Ended June 30, 2023 (2)
Oil Sands Segment	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Gross Sales	5,911	(204)	5,707	6,556	(119)	6,437
Purchased Product	559	(204)	355	533	(119)	414
	5,352	—	5,352	6,023	—	6,023

Conventional Segment
Gross Sales	1,031	6	1,037	615	5	620
Purchased Product	510	(27)	483	352	(15)	337
Transportation and Blending	48	33	81	46	20	66
	473	—	473	217	—	217

U.S. Manufacturing Segment
Gross Sales	5,860	(231)	5,629	6,198	(134)	6,064
Purchased Product	5,129	(231)	4,898	5,498	(134)	5,364
	731	—	731	700	—	700

Corporate and Eliminations Segment
Gross Sales	(1,925)	429	(1,496)	(2,092)	248	(1,844)
Purchased Product	(1,499)	479	(1,020)	(1,757)	287	(1,470)
Transportation and Blending	(141)	(134)	(275)	(109)	(98)	(207)
Operating	(231)	84	(147)	(185)	59	(126)
	(54)	—	(54)	(41)	—	(41)

Consolidated
Purchased Product	5,792	17	5,809	5,709	19	5,728
Transportation and Blending	2,853	(101)	2,752	2,641	(78)	2,563
Operating	1,552	84	1,636	1,541	59	1,600
	10,197	—	10,197	9,891	—	9,891

(1)Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in the U.S. Manufacturing segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting adjustment to the Corporate and Eliminations segment.

(2)Includes revisions to gross sales and purchased product of $119 million in the Oil Sands segment, $15 million in the Conventional segment and $134 million in the U.S. Manufacturing segment for the reasons noted above.

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 37

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended September 30, 2023

ii) Three and Nine Months Ended September 30, 2022

	Three Months Ended September 30, 2022				Nine Months Ended September 30, 2022
Oil Sands Segment	Previously Reported	Revisions	Segment Aggregation	Revised Balance	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Gross Sales	8,778	(14)	—	8,764	28,044	(14)	—	28,030
Purchased Product	1,933	(14)	—	1,919	4,216	(14)	—	4,202
	6,845	—	—	6,845	23,828	—	—	23,828

Conventional Segment
Gross Sales	1,010	26	—	1,036	3,201	85	—	3,286
Transportation and Blending	38	26	—	64	106	85	—	191
	972	—	—	972	3,095	—	—	3,095

Canadian Manufacturing Segment
Gross Sales	1,478	—	690	2,168	4,043	—	1,977	6,020
Purchased Product	1,092	3	655	1,750	3,192	3	1,870	5,065
Transportation and Blending	3	(3)	—	—	3	(3)	—	—
Operating	134	—	38	172	438	—	96	534
Depreciation, Depletion and     Amortization	37	—	5	42	143	—	21	164
	212	—	(8)	204	267	—	(10)	257

U.S. Manufacturing Segment
Gross Sales	8,719	(14)	—	8,705	23,702	(14)	—	23,688
Purchased Product	7,944	(14)	—	7,930	20,365	(14)	—	20,351
	775	—	—	775	3,337	—	—	3,337

Retail Segment
Gross Sales	881	—	(881)	—	2,424	—	(2,424)	—
Purchased Product	846	—	(846)	—	2,317	—	(2,317)	—
Operating	38	—	(38)	—	96	—	(96)	—
Depreciation, Depletion and     Amortization	5	—	(5)	—	21	—	(21)	—
	(8)	—	8	—	(10)	—	10	—

Corporate and Eliminations Segment
Gross Sales	(2,619)	2	191	(2,426)	(6,162)	(57)	447	(5,772)
Purchased Product	(2,267)	65	191	(2,011)	(4,660)	173	447	(4,040)
Transportation and Blending	(119)	(128)	—	(247)	(528)	(383)	—	(911)
Operating	(256)	65	—	(191)	(918)	153	—	(765)
	23	—	—	23	(56)	—	—	(56)

Consolidated
Purchased Product	10,012	40	—	10,052	26,890	148	—	27,038
Transportation and Blending	2,684	(105)	—	2,579	8,707	(301)	—	8,406
Operating	1,439	65	—	1,504	4,207	153	—	4,360
	14,135	—	—	14,135	39,804	—	—	39,804

Cenovus Energy Inc. – Q3 2023 Interim Consolidated Financial Statements 38

EX-99.4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Jonathan M. McKenzie, President & Chief Executive Officer of Cenovus Energy Inc., certify the following:

1.Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Cenovus Energy Inc. (the “issuer”) for the interim period ended September 30, 2023.

2.No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3.Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4.Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1    Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework.

5.2    ICFR - material weakness relating to design: N/A

5.3    Limitation on scope of design: The issuer has disclosed in its interim MD&A

    (a)    the fact that the issuer's other certifying officer(s) and I have limited the scope of our design of DC&P     and ICFR to exclude controls, policies and procedures of a business that the issuer acquired not more     than 365 days before the last day of the period covered by the interim filings; and

    (b)     summary financial information about the business that the issuer acquired that has been     proportionately consolidated or consolidated in the issuer's financial statements.

6.Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2023 and ended on September 30, 2023 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 2, 2023

/s/ Jonathan M. McKenzie

Jonathan M. McKenzie

President & Chief Executive Officer

EX-99.5

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer of Cenovus Energy Inc., certify the following:

1.Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Cenovus Energy Inc. (the “issuer”) for the interim period ended September 30, 2023.

2.No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3.Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4.Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1    Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework.

5.2    ICFR - material weakness relating to design: N/A

5.3    Limitation on scope of design: The issuer has disclosed in its interim MD&A

    (a)    the fact that the issuer's other certifying officer(s) and I have limited the scope of our design of DC&P     and ICFR to exclude controls, policies and procedures of a business that the issuer acquired not more     than 365 days before the last day of the period covered by the interim filings; and

    (b)     summary financial information about the business that the issuer acquired that has been     proportionately consolidated or consolidated in the issuer's financial statements.

6.Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2023 and ended on September 30, 2023 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 2, 2023

/s/ Karamjit S. Sandhar

Karamjit S. Sandar

Executive Vice-President & Chief Financial Officer

XML

Cover	9 Months Ended
	Sep. 30, 2023
Cover [Abstract]
Document Type	6-K
Entity Registrant Name	CENOVUS ENERGY INC.
Entity Central Index Key	0001475260
Current Fiscal Year End Date	--12-31
Document Period End Date	Sep. 30, 2023
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Amendment Flag	false

XML

Consolidated Statements of Earnings (Loss) (unaudited) - CAD ($) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2023		Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022		Sep. 30, 2023		Sep. 30, 2022
Revenues
Gross Sales	$ 15,712,000				$ 18,697,000		$ 41,438,000		$ 56,827,000
Less: Royalties	1,135,000				1,226,000		2,368,000		3,993,000
Revenue	14,577,000				17,471,000		39,070,000		52,834,000
Expenses
Purchased Product	6,620,000	[1]	$ 5,728,000	$ 5,809,000	10,052,000	[1]	18,157,000	[1]	27,038,000	[1]
Transportation and Blending	2,164,000	[1]	2,563,000	2,752,000	2,579,000	[1]	7,479,000	[1]	8,406,000	[1]
Operating	1,553,000	[1]	$ 1,600,000	$ 1,636,000	1,504,000	[1]	4,789,000	[1]	4,360,000	[1]
(Gain) Loss on Risk Management	72,000				(28,000)		89,000		1,540,000
Depreciation, Depletion and Amortization	1,197,000				1,047,000		3,374,000		3,209,000
Exploration Expense	2,000				73,000		10,000		99,000
(Income) Loss From Equity-Accounted Affiliates	(11,000)				(9,000)		(23,000)		(11,000)
General and Administrative	292,000				128,000		617,000		545,000
Finance Costs	106,000				207,000		493,000		631,000
Interest Income	(33,000)				(21,000)		(100,000)		(44,000)
Integration and Transaction Costs	12,000				27,000		49,000		79,000
Foreign Exchange (Gain) Loss, Net	133,000				316,000		7,000		406,000
Revaluation (Gain) Loss	0				(549,000)		33,000		(549,000)
Re-measurement of Contingent Payments	67,000				(109,000)		83,000		142,000
(Gain) Loss on Divestiture of Assets	0				60,000		(11,000)		(244,000)
Other (Income) Loss, Net	(22,000)				(59,000)		(42,000)		(467,000)
Earnings (Loss) Before Income Tax	2,425,000				2,253,000		4,066,000		7,694,000
Income Tax Expense (Recovery)	561,000				644,000		700,000		2,028,000
Net Earnings (Loss)	$ 1,864,000				$ 1,609,000		$ 3,366,000		$ 5,666,000
Net Earnings (Loss) Per Common Share ($)
Net earnings (loss) per share — basic (CAD per share)	$ 0.98				$ 0.83		$ 1.76		$ 2.87
Net earnings (loss) per share — diluted (CAD per share)	$ 0.97				$ 0.81		$ 1.72		$ 2.79

[1] Comparative periods reflect certain revisions. See Note 26

XML

Consolidated Statements of Comprehensive Income (Loss) (unaudited) - CAD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of comprehensive income [abstract]
Net Earnings (Loss)		$ 1,864,000	$ 1,609,000	$ 3,366,000	$ 5,666,000
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post- Employment Benefits		19,000	1,000	15,000	58,000
Change in the fair value of equity instruments at FVOCI	[1]	1,000	2,000	0	2,000
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		253,000	724,000	(31,000)	896,000
Total Other Comprehensive Income (Loss), Net of Tax		273,000	727,000	(16,000)	956,000
Comprehensive Income (Loss)		$ 2,137,000	$ 2,336,000	$ 3,350,000	$ 6,622,000

[1] Fair value through other comprehensive income (loss) (“FVOCI”)

XML

Consolidated Balance Sheets (unaudited) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets
Cash and Cash Equivalents	$ 1,262	$ 4,524
Accounts Receivable and Accrued Revenues	4,534	3,473
Income Tax Receivable	133	121
Inventories	4,816	4,312
Total Current Assets	10,745	12,430
Restricted Cash	209	209
Exploration and Evaluation Assets, Net	796	685
Property, Plant and Equipment, Net	36,727	36,499
Right-of-Use Assets, Net	1,738	1,845
Income Tax Receivable	25	25
Investments in Equity-Accounted Affiliates	356	365
Other Assets	266	342
Deferred Income Taxes	642	546
Goodwill	2,923	2,923
Total Assets	54,427	55,869
Current Liabilities
Accounts Payable and Accrued Liabilities	6,435	6,124
Income Tax Payable	146	1,211
Short-Term Borrowings	14	115
Lease Liabilities	315	308
Contingent Payments	295	263
Total Current Liabilities	7,205	8,021
Long-Term Debt	7,224	8,691
Lease Liabilities	2,418	2,528
Contingent Payments	0	156
Decommissioning Liabilities	3,603	3,559
Other Liabilities	1,183	1,042
Deferred Income Taxes	3,967	4,283
Total Liabilities	25,600	28,280
Shareholders’ Equity	28,814	27,576
Non-Controlling Interest	13	13
Total Liabilities and Equity	$ 54,427	$ 55,869

XML

Consolidated Statements of Equity (unaudited) - CAD ($) $ in Thousands		Total	Common shares	Preference shares	Common Shares	Preferred Shares	Warrants	Paid in Surplus	Retained Earnings	Retained Earnings Common shares	Retained Earnings Preference shares	AOCI	[1]	Non-Controlling Interest
Beginning balance at Dec. 31, 2021		$ 23,596,000			$ 17,016,000	$ 519,000	$ 215,000	$ 4,284,000	$ 878,000			$ 684,000		$ 12,000
Net Earnings (Loss)		5,666,000							5,666,000
Other Comprehensive Income (Loss), Net of Tax		956,000										956,000
Comprehensive Income (Loss)		6,622,000							5,666,000			956,000
Common Shares Issued Under Stock Option Plans		133,000			165,000			(32,000)
Repurchase Of Equity	[2]	(2,143,000)			(826,000)			(1,317,000)
Warrants Exercised		51,000			76,000		(25,000)
Stock-Based Compensation Expense		10,000						10,000
Dividends			$ (481,000)	$ (26,000)						$ (481,000)	$ (26,000)
Ending balance at Sep. 30, 2022		27,762,000			16,431,000	519,000	190,000	2,945,000	6,037,000			1,640,000		12,000
Beginning balance at Dec. 31, 2021		23,596,000			17,016,000	519,000	215,000	4,284,000	878,000			684,000		12,000
Ending balance at Dec. 31, 2022		27,576,000			16,320,000	519,000	184,000	2,691,000	6,392,000			1,470,000		13,000
Beginning balance at Sep. 30, 2022		27,762,000			16,431,000	519,000	190,000	2,945,000	6,037,000			1,640,000		12,000
Ending balance at Sep. 30, 2023		28,814,000			16,146,000	519,000	26,000	2,229,000	8,440,000			1,454,000		13,000
Beginning balance at Dec. 31, 2022		27,576,000			16,320,000	519,000	184,000	2,691,000	6,392,000			1,470,000		13,000
Net Earnings (Loss)		3,366,000							3,366,000
Other Comprehensive Income (Loss), Net of Tax		(16,000)										(16,000)
Comprehensive Income (Loss)		3,350,000							3,366,000			(16,000)
Common Shares Issued Under Stock Option Plans		43,000			54,000			(11,000)
Repurchase Of Equity	[2]	(711,000)			(251,000)			(460,000)
Warrants Exercised		16,000			23,000		(7,000)
Warrants Purchased and Cancelled		(713,000)					(151,000)		(562,000)
Stock-Based Compensation Expense		9,000						9,000
Dividends			$ (729,000)	$ (27,000)						$ (729,000)	$ (27,000)
Ending balance at Sep. 30, 2023		$ 28,814,000			$ 16,146,000	$ 519,000	$ 26,000	$ 2,229,000	$ 8,440,000			$ 1,454,000		$ 13,000

[1] Accumulated other comprehensive income (loss) (“AOCI”).

[2] Normal course issuer bids (“NCIBs”).

XML

Consolidated Statements of Cash Flows (unaudited) - CAD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Operating Activities
Net Earnings (Loss)	$ 1,864,000	$ 1,609,000	$ 3,366,000	$ 5,666,000
Depreciation, Depletion and Amortization	1,197,000	1,047,000	3,374,000	3,209,000
Deferred Income Tax Expense (Recovery)	(2,000)	568,000	(416,000)	625,000
Unrealized (Gain) Loss on Risk Management	72,000	(18,000)	88,000	(88,000)
Unrealized Foreign Exchange (Gain) Loss	59,000	298,000	(99,000)	419,000
Realized Foreign Exchange (Gain) Loss on Non-Operating Items	98,000	120,000	98,000	146,000
Revaluation (Gain) Loss	0	(549,000)	33,000	(549,000)
Re-measurement of Contingent Payments, Net of Cash Paid	67,000	(286,000)	83,000	(489,000)
(Gain) Loss on Divestiture of Assets	0	60,000	(11,000)	(244,000)
Unwinding of Discount on Decommissioning Liabilities	55,000	43,000	165,000	132,000
(Income) Loss From Equity-Accounted Affiliates	(11,000)	(9,000)	(23,000)	(11,000)
Distributions Received From Equity-Accounted Affiliates	23,000	13,000	117,000	54,000
Other	25,000	55,000	(34,000)	(238,000)
Settlement of Decommissioning Liabilities	(68,000)	(55,000)	(157,000)	(101,000)
Net Change in Non-Cash Working Capital	(641,000)	1,193,000	(2,142,000)	(98,000)
Cash From (Used in) Operating Activities	2,738,000	4,089,000	4,442,000	8,433,000
Investing Activities
Cash Acquired Through Business Combination	(32,000)	(389,000)	(501,000)	(390,000)
Capital Investment	(1,025,000)	(866,000)	(3,128,000)	(2,434,000)
Proceeds From Divestitures	1,000	407,000	12,000	1,469,000
Payment on Divestiture of Assets	0	0	0	(50,000)
Net Change in Investments and Other	(8,000)	51,000	(101,000)	(185,000)
Net Change in Non-Cash Working Capital	(37,000)	107,000	(297,000)	446,000
Cash From (Used in) Investing Activities	(1,101,000)	(690,000)	(4,015,000)	(1,144,000)
Net Cash Provided (Used) Before Financing Activities	1,637,000	3,399,000	427,000	7,289,000
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings	14,000	(2,000)	(101,000)	(81,000)
(Repayment) of Long-Term Debt	(1,346,000)	(2,889,000)	(1,346,000)	(4,149,000)
Principal Repayment of Leases	(70,000)	(78,000)	(216,000)	(228,000)
Common Shares Issued Under Stock Option Plans	25,000	13,000	43,000	133,000
Purchase of Common Shares Under NCIBs	(361,000)	(659,000)	(711,000)	(2,143,000)
Payment for Purchase of Warrants	(600,000)	0	(600,000)	0
Proceeds From Exercise of Warrants	5,000	7,000	16,000	51,000
Other	(3,000)	0	(3,000)	(2,000)
Cash From (Used in) Financing Activities	(2,600,000)	(3,822,000)	(3,674,000)	(6,926,000)
Effect of Foreign Exchange on Cash and Cash Equivalents	58,000	224,000	(15,000)	258,000
Increase (Decrease) in Cash and Cash Equivalents	(905,000)	(199,000)	(3,262,000)	621,000
Cash and Cash Equivalents, Beginning of Period	2,167,000	3,693,000	4,524,000	2,873,000
Cash and Cash Equivalents, End of Period	1,262,000	3,494,000	1,262,000	3,494,000
Common shares
Financing Activities
Dividends paid	(264,000)	(205,000)	(729,000)	(481,000)
Preference shares
Financing Activities
Dividends paid	$ 0	$ (9,000)	$ (27,000)	$ (26,000)

XML

Description of Business and Segmented Disclosures

9 Months Ended

Sep. 30, 2023

Disclosure Of Reportable Segments [Abstract]

DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc., including its subsidiaries, (together “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, 3, 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 interim Consolidated Financial Statements is found in Note 2.

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin.

The Company operates through the following reportable segments:

Upstream Segments

•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 within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and 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 China and the east coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

•Canadian Manufacturing, 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. Manufacturing, 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, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus also markets some of its own and third-party volumes of refined petroleum 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 internal usage of natural gas and condensate production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on market prices.

In December 2022, Management elected to aggregate the commercial fuels business and the historical retail fuels business with the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. Prior period results were reclassified; see Note 26.

The following tabular financial information presents segmented information first by segment, then by product and geographic location.

A) Results of Operations – Segment and Operational Information

i) Results for the Three Months Ended September 30

	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2023	2022	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	7,571	8,764	810	1,036	402	450	8,783	10,250
Less: Royalties	1,082	1,136	27	68	26	22	1,135	1,226
	6,489	7,628	783	968	376	428	7,648	9,024
Expenses
Purchased Product (1)	462	1,919	438	464	—	—	900	2,383
Transportation and Blending (1)	2,324	2,758	73	64	—	4	2,397	2,826
Operating	688	689	150	141	76	85	914	915
Realized (Gain) Loss on Risk    Management	(6)	42	(4)	9	—	—	(10)	51
Operating Margin	3,021	2,220	126	290	300	339	3,447	2,849
Unrealized (Gain) Loss on Risk    Management	47	(2)	7	8	—	—	54	6
Depreciation, Depletion and    Amortization	785	652	104	103	130	132	1,019	887
Exploration Expense	—	7	—	—	2	66	2	73
(Income) Loss From Equity-    Accounted Affiliates	—	—	—	—	(11)	(9)	(11)	(9)
Segment Income (Loss)	2,189	1,563	15	179	179	150	2,383	1,892

(1)Comparative periods reflect certain revisions. See Note 26.

	Downstream
For the three months ended	Canadian Manufacturing		U.S. Manufacturing		Total
September 30,	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	1,805	2,168	7,853	8,705	9,658	10,873
Less: Royalties	—	—	—	—	—	—
	1,805	2,168	7,853	8,705	9,658	10,873
Expenses
Purchased Product (1)	1,480	1,750	6,467	7,930	7,947	9,680
Transportation and Blending (1)	—	—	—	—	—	—
Operating	155	172	623	608	778	780
Realized (Gain) Loss on Risk Management	—	—	11	(77)	11	(77)
Operating Margin	170	246	752	244	922	490
Unrealized (Gain) Loss on Risk Management	—	—	(2)	(8)	(2)	(8)
Depreciation, Depletion and Amortization	50	42	109	91	159	133
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	120	204	645	161	765	365

For the three months ended	Corporate and Eliminations		Consolidated
September 30,	2023	2022	2023	2022
Revenues
Gross Sales (1)	(2,729)	(2,426)	15,712	18,697
Less: Royalties	—	—	1,135	1,226
	(2,729)	(2,426)	14,577	17,471
Expenses
Purchased Product (1)	(2,227)	(2,011)	6,620	10,052
Transportation and Blending (1)	(233)	(247)	2,164	2,579
Operating (1)	(139)	(191)	1,553	1,504
Realized (Gain) Loss on Risk Management	(1)	16	—	(10)
Unrealized (Gain) Loss on Risk Management	20	(16)	72	(18)
Depreciation, Depletion and Amortization	19	27	1,197	1,047
Exploration Expense	—	—	2	73
(Income) Loss From Equity-Accounted Affiliates	—	—	(11)	(9)
Segment Income (Loss)	(168)	(4)	2,980	2,253
General and Administrative	292	128	292	128
Finance Costs	106	207	106	207
Interest Income	(33)	(21)	(33)	(21)
Integration and Transaction Costs	12	27	12	27
Foreign Exchange (Gain) Loss, Net	133	316	133	316
Revaluation (Gain) Loss	—	(549)	—	(549)
Re-measurement of Contingent Payments	67	(109)	67	(109)
(Gain) Loss on Divestiture of Assets	—	60	—	60
Other (Income) Loss, Net	(22)	(59)	(22)	(59)
	555	—	555	—
Earnings (Loss) Before Income Tax			2,425	2,253
Income Tax Expense (Recovery)			561	644
Net Earnings (Loss)			1,864	1,609

(1)Comparative periods reflect certain revisions. See Note 26.

ii) Results for the Nine Months Ended September 30

	Upstream
For the nine months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2023	2022	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	19,715	28,030	2,467	3,286	1,103	1,575	23,285	32,891
Less: Royalties	2,218	3,709	85	228	65	56	2,368	3,993
	17,497	24,321	2,382	3,058	1,038	1,519	20,917	28,898
Expenses
Purchased Product (1)	1,231	4,202	1,258	1,460	—	—	2,489	5,662
Transportation and Blending (1)	7,965	9,114	220	191	9	12	8,194	9,317
Operating	2,101	2,197	444	403	281	234	2,826	2,834
Realized (Gain) Loss on Risk    Management	(7)	1,468	—	17	—	—	(7)	1,485
Operating Margin	6,207	7,340	460	987	748	1,273	7,415	9,600
Unrealized (Gain) Loss on Risk    Management	44	(59)	(14)	7	—	—	30	(52)
Depreciation, Depletion and    Amortization	2,230	1,977	286	282	349	441	2,865	2,700
Exploration Expense	4	7	—	1	6	91	10	99
(Income) Loss From Equity-    Accounted Affiliates	6	8	—	—	(29)	(19)	(23)	(11)
Segment Income (Loss)	3,923	5,407	188	697	422	760	4,533	6,864

(1)Comparative periods reflect certain revisions. See Note 26.

	Downstream
For the nine months ended	Canadian Manufacturing		U.S. Manufacturing		Total
September 30,	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	4,676	6,020	19,546	23,688	24,222	29,708
Less: Royalties	—	—	—	—	—	—
	4,676	6,020	19,546	23,688	24,222	29,708
Expenses
Purchased Product (1)	3,656	5,065	16,729	20,351	20,385	25,416
Transportation and Blending (1)	—	—	—	—	—	—
Operating	471	534	1,904	1,757	2,375	2,291
Realized (Gain) Loss on Risk Management	—	—	6	120	6	120
Operating Margin	549	421	907	1,460	1,456	1,881
Unrealized (Gain) Loss on Risk Management	—	—	(13)	(22)	(13)	(22)
Depreciation, Depletion and Amortization	136	164	314	259	450	423
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	413	257	606	1,223	1,019	1,480

For the nine months ended	Corporate and Eliminations		Consolidated
September 30,	2023	2022	2023	2022
Revenues
Gross Sales (1)	(6,069)	(5,772)	41,438	56,827
Less: Royalties	—	—	2,368	3,993
	(6,069)	(5,772)	39,070	52,834
Expenses
Purchased Product (1)	(4,717)	(4,040)	18,157	27,038
Transportation and Blending (1)	(715)	(911)	7,479	8,406
Operating (1)	(412)	(765)	4,789	4,360
Realized (Gain) Loss on Risk Management	2	23	1	1,628
Unrealized (Gain) Loss on Risk Management	71	(14)	88	(88)
Depreciation, Depletion and Amortization	59	86	3,374	3,209
Exploration Expense	—	—	10	99
(Income) Loss From Equity-Accounted Affiliates	—	—	(23)	(11)
Segment Income (Loss)	(357)	(151)	5,195	8,193
General and Administrative	617	545	617	545
Finance Costs	493	631	493	631
Interest Income	(100)	(44)	(100)	(44)
Integration and Transaction Costs	49	79	49	79
Foreign Exchange (Gain) Loss, Net	7	406	7	406
Revaluation (Gain) Loss	33	(549)	33	(549)
Re-measurement of Contingent Payments	83	142	83	142
(Gain) Loss on Divestiture of Assets	(11)	(244)	(11)	(244)
Other (Income) Loss, Net	(42)	(467)	(42)	(467)
	1,129	499	1,129	499
Earnings (Loss) Before Income Tax			4,066	7,694
Income Tax Expense (Recovery)			700	2,028
Net Earnings (Loss)			3,366	5,666

(1)Comparative periods reflect certain revisions. See Note 26.

) Revenues by Product

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Upstream
Crude Oil (1) (2)	6,666	7,384	17,671	24,143
Natural Gas (2)	563	973	1,975	2,740
NGLs (1)	382	571	1,088	1,684
Other	37	96	183	331
Total Upstream	7,648	9,024	20,917	28,898
Downstream
Canadian Manufacturing
Synthetic Crude Oil	657	657	1,607	1,786
Diesel	460	567	1,286	1,544
Gasoline	162	298	410	837
Asphalt	200	248	431	482
Other Products and Services	326	398	942	1,371
U.S. Manufacturing
Gasoline	3,822	3,919	9,336	11,180
Distillates	2,871	3,384	7,169	8,535
Asphalt	326	196	610	402
Other Products (2)	834	1,206	2,431	3,571
Total Downstream	9,658	10,873	24,222	29,708
Corporate and Eliminations (2)	(2,729)	(2,426)	(6,069)	(5,772)
Consolidated	14,577	17,471	39,070	52,834

(1)Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.

(2)Comparative periods reflect certain revisions. See Note 26.

C) Geographical Information

	Revenues (1)
	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Canada (2)	6,666	7,999	18,828	26,471
United States (2)	7,611	9,155	19,425	25,340
China	300	317	817	1,023
Consolidated	14,577	17,471	39,070	52,834

(1)Revenues by country are classified based on where the operations are located.

(2)Comparative periods reflect certain revisions. See Note 26.

	Non-Current Assets (1)
	September 30,	December 31,
As at	2023	2022
Canada	35,257	35,194
United States	5,284	4,824
China	1,758	2,064
Indonesia	356	365
Consolidated	42,655	42,447

(1)Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill.

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
	September 30,	December 31,	September 30,	December 31,	September 30,	December 31,
As at	2023	2022	2023	2022	2023	2022
Oil Sands	785	674	24,271	24,657	687	638
Conventional	5	6	2,045	2,020	2	2
Offshore	6	5	2,679	2,549	103	152
Canadian Manufacturing	—	—	2,438	2,466	220	252
U.S. Manufacturing	—	—	4,981	4,482	286	329
Corporate and Eliminations	—	—	313	325	440	472
Consolidated	796	685	36,727	36,499	1,738	1,845

	Goodwill		Total Assets
	September 30,	December 31,	September 30,	December 31,
As at	2023	2022	2023	2022
Oil Sands	2,923	2,923	32,481	32,248
Conventional	—	—	2,278	2,410
Offshore	—	—	3,416	3,339
Canadian Manufacturing	—	—	3,320	3,172
U.S. Manufacturing	—	—	9,728	8,324
Corporate and Eliminations	—	—	3,204	6,376
Consolidated	2,923	2,923	54,427	55,869

E) Capital Expenditures (1)

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Capital Investment
Oil Sands	590	360	1,764	1,111
Conventional	100	67	323	188
Offshore
Asia Pacific	3	3	4	5
Atlantic	191	78	474	220
Total Upstream	884	508	2,565	1,524
Canadian Manufacturing	38	24	99	77
U.S. Manufacturing	88	300	435	774
Total Downstream	126	324	534	851
Corporate and Eliminations	15	34	29	59
	1,025	866	3,128	2,434
Acquisitions (Note 3)
Oil Sands	32	1,596	35	1,596
Conventional	1	5	5	6
U.S. Manufacturing (2)	—	—	337	—
	33	1,601	377	1,602
Total Capital Expenditures	1,058	2,467	3,505	4,036

(1)Includes expenditures on PP&E, E&E assets and capitalized interest.

(2)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 $320 million.

XML

Basis of Preparation and Statement of Compliance

9 Months Ended

Sep. 30, 2023

Basis Of Preparation And Statement Of Compliance [Abstract]

BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these interim Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These interim Consolidated Financial Statements were prepared in accordance with IFRS, as issued by the International Accounting Standards Board (“IASB”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting”, and were prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2022, except for income taxes. Income taxes on earnings or loss in the interim period are accrued using the income tax rate that would be applicable to the expected total annual earnings or loss.

Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements were condensed or disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2022, which were prepared in accordance with IFRS as issued by the IASB.

These interim Consolidated Financial Statements were approved by the Board of Directors effective November 1, 2023.

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Acquisitions

9 Months Ended

Sep. 30, 2023

Business Combination [Abstract]

Acquisitions

3. ACQUISITIONS

A) BP-Husky Refining LLC

i) Summary of the Acquisition

On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from BP Products North America Inc. (“bp”), a joint operation (the “Toledo Acquisition”). It provided 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$369 million (C$502 million) in cash, including 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

The preliminary purchase price allocation is based on Management’s best estimate of fair value. Upon finalizing the fair value of net assets acquired, adjustments to initial estimates, including goodwill, may be required.

The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition.

As at	February 28, 2023
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	69
Accounts Receivable and Accrued Revenues	3
Inventories	453
Property, Plant and Equipment	674
Right-of-Use Assets	33
Other Assets	10
Accounts Payable and Accrued Liabilities	(138)
Lease Liabilities	(33)
Decommissioning Liabilities	(5)
Other Liabilities	(70)
Total Identifiable Net Assets	996

The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which was collected.

iii) Goodwill

As at	February 28, 2023
Total Purchase Consideration	502
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo	494
Fair Value of Identifiable Net Assets	(996)
Goodwill	—

Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC

Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11, “Joint Arrangements”; therefore, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, “Consolidated Financial Statements”, and, accordingly Toledo was consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized as a revaluation (gain) loss in the Consolidated Statements of Earnings (Loss). When a disposition includes a foreign operation, the associated cumulative amount of foreign exchange differences are reclassified to earnings as part of the revaluation (gain) loss.

The acquisition-date fair value of the previously held interest was estimated to be $494 million and the net carrying value of Toledo assets was $539 million. On February 28, 2023, Cenovus recognized a non-cash revaluation loss of $33 million ($22 million, after tax) on the re-measurement of its existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign exchange differences.

iv) Integration and Transaction Costs

For the three and nine months ended September 30, 2023, integration costs of $10 million and $38 million respectively (three and nine months ended September 30, 2022 – $nil), and transaction costs of $2 million and $11 million, respectively, (three and nine months ended September 30, 2022 – $2 million), associated with the Toledo Acquisition were recognized in the Consolidated Statements of Earnings (Loss).

v) Revenue and Profit Contribution

The acquired business contributed revenues of $2.4 billion and net loss of $84 million for the period from February 28, 2023, to September 30, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The Toledo Refinery was fully operational in June. If the closing of the Toledo Acquisition had occurred on January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the nine months ended September 30, 2023, would be $39.1 billion and $3.3 billion, respectively. These amounts were calculated using results from the acquired business, adjusting them for:

•Additional Depreciation, Depletion and Amortization (“DD&A”) that would be charged assuming the fair value adjustments to PP&E had applied from January 1, 2023.

•Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023.

•The consequential tax effects.

This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had actually occurred on January 1, 2023.

B) Sunrise Oil Sands Partnership

On August 31, 2022, Cenovus closed a transaction with BP Canada Energy Group ULC (“bp Canada”) to purchase the remaining 50 percent interest in Sunrise Oil Sands Partnership (“SOSP”), previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core strength in the oil sands.

The final purchase price allocation was based on Management’s best estimate of the assets acquired and liabilities assumed. No additional adjustments were made to the purchase price allocation in the period. For more details, see Note 5 of the annual Consolidated Financial Statements for the year ended December 31, 2022.

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Finance Costs

9 Months Ended

Sep. 30, 2023

Finance Costs [Abstract]

Finance Costs

4. FINANCE COSTS

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Interest Expense – Short-Term Borrowings and Long-Term Debt	94	121	285	381
Net Premium (Discount) on Redemption of Long-Term Debt (1)	(84)	(4)	(84)	(29)
Interest Expense – Lease Liabilities (Note 14)	41	40	121	123
Unwinding of Discount on Decommissioning Liabilities (Note 16)	55	43	165	132
Other	5	9	18	27
	111	209	505	634
Capitalized Interest	(5)	(2)	(12)	(3)
	106	207	493	631

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Foreign Exchange (Gain) Loss, Net

9 Months Ended

Sep. 30, 2023

Foreign Exchange Gains Losses [Abstract]

Foreign Exchange (Gain) Loss, Net

5. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	28	324	(119)	444
Other	31	(26)	20	(25)
Unrealized Foreign Exchange (Gain) Loss	59	298	(99)	419
Realized Foreign Exchange (Gain) Loss	74	18	106	(13)
	133	316	7	406

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Income Taxes

9 Months Ended

Sep. 30, 2023

Disclosure Of Income Tax Expense Continuing Operations [Abstract]

Income Taxes

6. INCOME TAXES

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Current Tax
Canada	484	187	941	1,124
United States	4	(185)	4	96
Asia Pacific	68	64	152	173
Other International	7	10	19	10
Total Current Tax Expense (Recovery)	563	76	1,116	1,403
Deferred Tax Expense (Recovery)	(2)	568	(416)	625
	561	644	700	2,028

For the nine months ended September 30, 2023, Cenovus incurred a deferred tax recovery of $416 million of which $176 million related to a step-up in the tax basis on the Toledo Acquisition on February 28, 2023.

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Per Share Amounts

9 Months Ended

Sep. 30, 2023

Earnings per share [abstract]

Per Share Amounts

7. PER SHARE AMOUNTS

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Net Earnings (Loss)	1,864	1,609	3,366	5,666
Effect of Cumulative Dividends on Preferred Shares	(9)	(9)	(27)	(26)
Net Earnings (Loss) – Basic and Diluted	1,855	1,600	3,339	5,640
Basic – Weighted Average Number of Shares (thousands)	1,891,937	1,927,864	1,900,952	1,962,813
Dilutive Effect of Warrants	6,408	41,956	27,491	45,002
Dilutive Effect of Net Settlement Rights	6,752	7,188	7,643	10,657
Dilutive Effect of Cenovus Replacement Stock Options	—	1,637	630	—
Diluted – Weighted Average Number of Shares (thousands)	1,905,097	1,978,645	1,936,716	2,018,472
Net Earnings (Loss) Per Common Share – Basic ($)	0.98	0.83	1.76	2.87
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)	0.97	0.81	1.72	2.79

(1)For the three months ended September 30, 2023, net earnings of $6 million and common shares of 0.6 million related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the impact was anti-dilutive. For the nine months ended September 30, 2022, net earnings of $35 million and common shares of 1.6 million related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive.

(2)For the three and nine months ended September 30, 2023, net settlement rights (“NSRs”) of 1.5 million and 1.5 million, respectively, (three and nine months ended September 30, 2022 – 2.0 million and 2.0 million, respectively) were excluded from the calculation of diluted weighted average number of shares as the effect was anti-dilutive.

B) Common Share Dividends

	2023		2022
For the nine months ended September 30,	Per Share	Amount	Per Share	Amount
Base Dividends	0.385	729	0.245	481
Variable Dividends	—	—	—	—
Total Common Share Dividends Declared and Paid	0.385	729	0.245	481

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

On November 1, 2023, the Company’s Board of Directors declared a fourth quarter base dividend of $0.140 per common share, payable on December 29, 2023, to common shareholders of record as at December 15, 2023.

C) Preferred Share Dividends

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Series 1 First Preferred Shares	2	1	5	5
Series 2 First Preferred Shares	1	1	2	1
Series 3 First Preferred Shares	3	3	9	9
Series 5 First Preferred Shares	2	3	7	7
Series 7 First Preferred Shares	1	1	4	4
Total Preferred Share Dividends Declared	9	9	27	26

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

In the three and nine months ended September 30, 2023, the Company paid $nil and $27 million, respectively, in preferred share dividends (three and nine months ended September 30, 2022 – $9 million and $26 million, respectively).

On November 1, 2023, the Company’s Board of Directors declared fourth quarter dividends of $9 million payable on January 2, 2024, to preferred shareholders of record as at December 15, 2023.

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Exploration and Evaluation Assets, Net

9 Months Ended

Sep. 30, 2023

Disclosure Of Exploration And Evaluation Assets [Abstract]

Exploration and Evaluation Assets, Net

8. EXPLORATION AND EVALUATION ASSETS, NET

	Total
As at December 31, 2022	685
Acquisition	31
Additions	80
As at September 30, 2023	796

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Property, Plant and Equipment, Net

9 Months Ended

Sep. 30, 2023

Disclosure of detailed information about property, plant and equipment [abstract]

Property, Plant and Equipment, Net

9. PROPERTY, PLANT AND EQUIPMENT, NET

	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Manufacturing Assets	Other Assets (1)	Total
COST
As at December 31, 2022	43,528	254	12,132	1,825	57,739
Acquisitions (Note 3) (2)	9	—	674	—	683
Additions	2,485	19	508	36	3,048
Change in Decommissioning Liabilities	42	—	2	—	44
Divestitures (Note 3) (2)	(17)	—	(633)	(17)	(667)
Exchange Rate Movements and Other	(19)	5	(39)	(8)	(61)
As at September 30, 2023	46,028	278	12,644	1,836	60,786
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2022	14,302	106	5,547	1,285	21,240
Depreciation, Depletion and Amortization (3)	2,726	16	366	42	3,150
Divestitures (Note 3) (2)	(8)	—	(299)	(12)	(319)
Exchange Rate Movements and Other	13	4	(23)	(6)	(12)
As at September 30, 2023	17,033	126	5,591	1,309	24,059
CARRYING VALUE
As at December 31, 2022	29,226	148	6,585	540	36,499
As at September 30, 2023	28,995	152	7,053	527	36,727

(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.

(3)DD&A includes asset write-downs of $20 million in the Oil Sands segment and $8 million in the Canadian Manufacturing segment.

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Right of Use Assets, Net

9 Months Ended

Sep. 30, 2023

Disclosure of quantitative information about right-of-use assets [abstract]

Right of Use Assets, Net

10. RIGHT-OF-USE ASSETS, NET

	Real Estate	Transportation and Storage Assets (1)	Manufacturing Assets	Other Assets (2)	Total
COST
As at December 31, 2022	599	1,840	174	74	2,687
Acquisitions (Note 3) (3)	1	24	8	—	33
Additions	1	44	—	—	45
Modifications	(4)	37	1	—	34
Re-measurements	—	(11)	—	5	(6)
Divestitures (Note 3) (3)	—	—	(19)	—	(19)
Terminations	(3)	(1)	—	(2)	(6)
Exchange Rate Movements and Other	(4)	24	—	3	23
As at September 30, 2023	590	1,957	164	80	2,791
ACCUMULATED DEPRECIATION
As at December 31, 2022	127	645	58	12	842
Depreciation	27	170	17	10	224
Divestitures (Note 3) (3)	—	—	(12)	—	(12)
Terminations	(1)	(1)	—	(1)	(3)
Exchange Rate Movements and Other	(3)	8	(2)	(1)	2
As at September 30, 2023	150	822	61	20	1,053
CARRYING VALUE
As at December 31, 2022	472	1,195	116	62	1,845
As at September 30, 2023	440	1,135	103	60	1,738

(1)Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.

(2)Includes assets in the commercial fuels business, fleet vehicles 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.

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Joint Arrangements

9 Months Ended

Sep. 30, 2023

Subclassifications of assets, liabilities and equities [abstract]

JOINT ARRANGEMENTS

11. JOINT ARRANGEMENTS

A) Joint Operations

Cenovus has a number of joint operations in the Upstream segments. The Company also holds the following joint operation in the U.S. Manufacturing segment.

WRB Refining LP (“WRB”)

Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. 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.

B) Joint Ventures

Husky-CNOOC Madura Ltd.

The Company holds a 40 percent interest in the jointly controlled entity, HCML, which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia. The Company’s share of equity investment income (loss) related to the joint venture, distributions received and contributions paid are recorded in (income) loss from equity-accounted affiliates in the Offshore segment.

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations

	Nine Months Ended
For the periods ended September 30,	2023	2022
Revenue	439	256
Expenses	373	247
Net Earnings (Loss)	66	9

Balance Sheet

	September 30,	December 31,
As at	2023	2022
Current Assets (1)	285	247
Non-Current Assets	1,767	1,926
Current Liabilities	127	160
Non-Current Liabilities	1,114	1,293
Net Assets	811	720

(1)Includes cash and cash equivalents of $76 million (December 31, 2022 – $64 million).

For the nine months ended September 30, 2023, the Company’s share of income from the equity-accounted affiliate was $29 million (2022 – $19 million). As at September 30, 2023, the carrying amount of the Company’s share of net assets was $356 million (December 31, 2022 – $365 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 nine months ended September 30, 2023, the Company received $61 million of distributions from HCML (2022 – $32 million) and paid $31 million in contributions (2022 – $41 million).

Husky Midstream Limited Partnership

The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power Assets Holdings Limited holding a 49 percent interest and CK Infrastructure Holdings Limited holding a 16 percent interest in HMLP. The Company’s share of equity investment income related to the joint venture, only in excess of the cumulated unrecognized loss, distributions received and contributions paid, is recorded in (income) loss from equity-accounted affiliates in the Oil Sands segment.

For the nine months ended September 30, 2023, HMLP had net earnings of $118 million (2022 – $112 million). The Company’s share of (income) loss from the equity-accounted affiliate does not equal the 35 percent of the net earnings of HMLP due to the nature of the profit-sharing arrangement as set forth in the partnership agreement. The Company’s share of earnings will fluctuate depending on certain income thresholds of HMLP. For the nine months ended September 30, 2023, the Company did not record its share of pre-tax loss relating to HMLP of $20 million (2022 – pre-tax loss of $14 million). The carrying value was $nil at September 30, 2023 (December 31, 2022 – $nil).

As at September 30, 2023, the Company had $42 million in cumulative unrecognized losses and other comprehensive income (“OCI”), net of tax (December 31, 2022 – $28 million).

For the nine months ended September 30, 2023, the Company received $56 million of distributions from HMLP (2022 – $22 million) and paid $62 million in contributions (2022 – $30 million). The net amount of the distributions received and contributions paid is recorded in (income) loss from equity-accounted affiliates in the Oil Sands segment.

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Other Assets

9 Months Ended

Sep. 30, 2023

Other Noncurrent Assets [Abstract]

Other Assets

12. OTHER ASSETS

	September 30,	December 31,
As at	2023	2022
Long-Term Receivables and Prepaids	48	120
Precious Metals	79	86
Net Investment in Finance Leases	62	62
Private Equity Investments (Note 22)	66	55
Intangible Assets	11	19
	266	342

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Debt and Capital Structure

9 Months Ended

Sep. 30, 2023

Borrowings [abstract]

Debt and Capital Structure

13. DEBT AND CAPITAL STRUCTURE

A) Short-Term Borrowings

		September 30,	December 31,
As at	Notes	2023	2022
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	14	115
Total Debt Principal		14	115

i) Uncommitted Demand Facilities

As at September 30, 2023, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2022 – $1.9 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 September 30, 2023, there were outstanding letters of credit aggregating to $353 million (December 31, 2022 – $490 million) and no direct borrowings.

ii) WRB Uncommitted Demand Facilities

WRB has uncommitted demand facilities of 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 September 30, 2023, US$20 million was drawn on these facilities, of which Cenovus’s proportionate share was US$10 million (C$14 million). As at December 31, 2022, Cenovus’s proportionate share of the capacity was US$225 million and US$85 million (C$115 million) of this capacity was drawn.

B) Long-Term Debt

	September 30,	December 31,
As at	2023	2022
Committed Credit Facility (1)	—	—
U.S. Dollar Denominated Unsecured Notes	5,140	6,537
Canadian Dollar Unsecured Notes	2,000	2,000
Total Debt Principal	7,140	8,537
Debt Premiums (Discounts), Net, and Transaction Costs	84	154
Long-Term Debt	7,224	8,691

(1) The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

Committed Credit FacilityAs at September 30, 2023, the Company had in place a committed credit facility that consists of a $1.8 billion tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at September 30, 2023, no amount was drawn on the credit facility (December 31, 2022 – $nil). U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes

In September 2023, the Company purchased outstanding principal amounts of the following unsecured notes.

	US$ Principal
U.S. Dollar Unsecured Notes
4.40% due April 15, 2029	57
5.25% due June 15, 2037	250
6.80% due September 15, 2037	196
6.75% due November 15, 2039	283
4.45% due September 15, 2042	6
5.20% due September 15, 2043	2
5.40% due June 15, 2047	231
	1,025

The principal amounts of the Company’s outstanding unsecured notes are:

	September 30, 2023		December 31, 2022
	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Unsecured Notes
5.38% due July 15, 2025	133	181	133	181
4.25% due April 15, 2027	373	505	373	505
4.40% due April 15, 2029	183	247	240	324
2.65% due January 15, 2032	500	676	500	677
5.25% due June 15, 2037	333	450	583	790
6.80% due September 15, 2037	191	259	387	524
6.75% due November 15, 2039	652	881	935	1,267
4.45% due September 15, 2042	91	123	97	131
5.20% due September 15, 2043	27	36	29	39
5.40% due June 15, 2047	569	768	800	1,083
3.75% due February 15, 2052	750	1,014	750	1,016
	3,802	5,140	4,827	6,537
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		7,140		8,537

As at September 30, 2023, 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 well below this limit.

C) Capital Structure

Cenovus’s capital structure consists of shareholders’ equity plus 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, 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 billion over the long-term at a West Texas Intermediate (“WTI”) price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices.

Net Debt to Adjusted EBITDA

	September 30,	December 31,
As at	2023	2022
Short-Term Borrowings	14	115
Current Portion of Long-Term Debt	—	—
Long-Term Portion of Long-Term Debt	7,224	8,691
Total Debt	7,238	8,806
Less: Cash and Cash Equivalents	(1,262)	(4,524)
Net Debt	5,976	4,282
Net Earnings (Loss)	4,150	6,450
Add (Deduct):
Finance Costs	682	820
Interest Income	(137)	(81)
Income Tax Expense (Recovery)	953	2,281
Depreciation, Depletion and Amortization	4,844	4,679
Exploration and Evaluation Asset Write-downs	1	64
(Income) Loss From Equity-Accounted Affiliates	(27)	(15)
Unrealized (Gain) Loss on Risk Management	50	(126)
Foreign Exchange (Gain) Loss, Net	(56)	343
Revaluation (Gain) Loss	33	(549)
Re-measurement of Contingent Payments	103	162
(Gain) Loss on Divestiture of Assets	(36)	(269)
Other (Income) Loss, Net	(107)	(532)
Adjusted EBITDA (1)	10,453	13,227
Net Debt to Adjusted EBITDA	0.6x	0.3x

(1)Calculated on a trailing twelve-month basis.

Net Debt to Adjusted Funds Flow

	September 30,	December 31,
As at	2023	2022
Net Debt	5,976	4,282
Cash From (Used in) Operating Activities	7,412	11,403
(Add) Deduct:
Settlement of Decommissioning Liabilities	(206)	(150)
Net Change in Non-Cash Working Capital	(1,469)	575
Adjusted Funds Flow (1)	9,087	10,978
Net Debt to Adjusted Funds Flow	0.7x	0.4x

(1)Calculated on a trailing twelve-month basis.

Net Debt to Capitalization

	September 30,		December 31,
As at	2023		2022
Net Debt	5,976		4,282
Shareholders’ Equity	28,814		27,576
Capitalization	34,790		31,858
Net Debt to Capitalization	17	%	13	%

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Lease Liabilities

9 Months Ended

Sep. 30, 2023

Lease liabilities [abstract]

Lease Liabilities

14. LEASE LIABILITIES

	Total
As at December 31, 2022	2,836
Acquisitions (Note 3) (1)	33
Additions	45
Interest Expense (Note 4)	121
Lease Payments	(337)
Modifications	34
Re-measurements	(6)
Divestitures (Note 3) (1)	(11)
Terminations	(8)
Exchange Rate Movements and Other	26
As at September 30, 2023	2,733
Less: Current Portion	315
Long-Term Portion	2,418

(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.

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Contingent Payments

9 Months Ended

Sep. 30, 2023

Disclosure of contingent liabilities in business combination [abstract]

Contingent Payments

15. CONTINGENT PAYMENTS

In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments, up to $600 million, from SOSP to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average Western Canadian Select (“WCS”) price in a quarter exceeds $52.00 per barrel. The quarterly payment is 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 is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum payment over the remaining four quarters of the contract is $301 million.

The variable payment will be re-measured to fair value at each reporting date, with changes in fair value recorded to re-measurement of contingent payments in the Consolidated Statements of Earnings (Loss).

Payments made during the nine months ended September 30, 2023, totaled $207 million for the quarterly payment periods ending November 30, 2022, February 28, 2023, and May 31, 2023.

	Total
As at December 31, 2022	419
Liabilities Settled or Payable	(207)
Re-measurement	83
As at September 30, 2023	295

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Decommissioning Liabilities

9 Months Ended

Sep. 30, 2023

Provision for decommissioning, restoration and rehabilitation costs [abstract]

Decommissioning Liabilities

16. DECOMMISSIONING LIABILITIES

	Total
As at December 31, 2022	3,559
Liabilities Incurred	12
Liabilities Acquired (Note 3) (1)	5
Liabilities Settled	(156)
Liabilities Disposed (Note 3) (1)	(5)
Change in Estimated Future Cash Flows	32
Unwinding of Discount on Decommissioning Liabilities (Note 4)	165
Exchange Rate Movements	(9)
As at September 30, 2023	3,603

(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 September 30, 2023, the undiscounted amount of estimated future cash flows required to settle the obligation was discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2022 – 6.1 percent) and assumes an inflation rate of two percent (December 31, 2022 – 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 September 30, 2023, the Company had $209 million in restricted cash (December 31, 2022 – $209 million).

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Other Liabilities

9 Months Ended

Sep. 30, 2023

Miscellaneous non-current liabilities [abstract]

Other Liabilities

17. OTHER LIABILITIES

	September 30,	December 31,
As at	2023	2022
Renewable Volume Obligation, Net (1)	400	101
Pension and Other Post-Employment Benefit Plan	191	201
Provision for West White Rose Expansion Project	169	204
Provisions for Onerous and Unfavourable Contracts	76	95
Employee Long-Term Incentives	127	245
Drilling Provisions	25	31
Deferred Revenue	39	45
Other	156	120
	1,183	1,042

(1)The gross amounts of the renewable volume obligation and renewable identification numbers asset were $1.1 billion and $0.7 billion, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively).

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Share Capital and Warrants

9 Months Ended

Sep. 30, 2023

Disclosure of classes of share capital [abstract]

Share Capital and Warrants

18. SHARE CAPITAL AND WARRANTS

AuthorizedCenovus 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

	September 30, 2023		December 31, 2022
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	1,909,190	16,320	2,001,211	17,016
Issued Upon Exercise of Warrants	2,314	23	9,399	93
Issued Under Stock Option Plans	3,443	54	11,069	170
Purchase of Common Shares Under NCIBs	(29,388)	(251)	(112,489)	(959)
Outstanding, End of Period	1,885,559	16,146	1,909,190	16,320

As at September 30, 2023, there were 45.2 million (December 31, 2022 – 43.1 million) common shares available for future issuance under the stock option plan.

C) Normal Course Issuer Bid

For the nine months ended September 30, 2023, the Company purchased and cancelled 29.4 million common shares through the existing NCIB. The shares were purchased at a volume weighted average price of $24.19 per common share for a total of $711 million. Paid in surplus was reduced by $460 million, representing the excess of the purchase price of the common shares over their average carrying value.

From October 1, 2023, to October 30, 2023, the Company purchased an additional 3.3 million common shares for $89 million. As at October 30, 2023, the Company can further purchase up to 92.5 million common shares under the existing NCIB. The current NCIB will expire on November 8, 2023.

On November 1, 2023, the Company received approval from the Board of Directors to apply to the TSX for an additional NCIB program. Subject to acceptance by the TSX, the Company will be able to purchase up to approximately 133 million common shares for a period of twelve months.

) Issued and Outstanding – Preferred Shares

For the nine months ended September 30, 2023, there were no preferred shares issued. As at September 30, 2023, there were 36 million preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 – $519 million).

As at September 30, 2023	Dividend Reset Date	Dividend Rate		Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	%	10,740
Series 2 First Preferred Shares (1)	Quarterly	6.89	%	1,260
Series 3 First Preferred Shares	December 31, 2024	4.69	%	10,000
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 5.86 percent for the period from December 31, 2022, to March 30, 2023, 6.29 percent for the period from March 31, 2023, to June 29, 2023, and 6.29 percent from June 30, 2023, to September 29, 2023.

Issued and Outstanding – Warrants

	September 30, 2023		December 31, 2022
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	55,720	184	65,119	215
Exercised	(2,314)	(7)	(9,399)	(31)
Purchased and Cancelled	(45,485)	(151)	—	—
Outstanding, End of Period	7,921	26	55,720	184

The exercise price of the Cenovus warrants is $6.54 per share.

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 of $6.54 per common share, 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.

Cenovus has the option to pay the warrant purchase price of $711 million through the remainder of 2023, with full payment required by January 5, 2024. For the three months ended September 30, 2023, total payments of $600 million were made.

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Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2023

Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

19. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Pension and Other Post-Employment Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
As at December 31, 2021	28	27	629	684
Other Comprehensive Income (Loss), Before Tax	78	2	896	976
Income Tax (Expense) Recovery	(20)	—	—	(20)
As at September 30, 2022	86	29	1,525	1,640
As at December 31, 2022	99	29	1,342	1,470
Other Comprehensive Income (Loss), Before Tax	20	—	(43)	(23)
Reclassification on Divestiture (Note 3)	—	—	12	12
Income Tax (Expense) Recovery	(5)	—	—	(5)
As at September 30, 2023	114	29	1,311	1,454

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Stock-Based Compensation Plans

9 Months Ended

Sep. 30, 2023

Disclosure of terms and conditions of share-based payment arrangement [abstract]

STOCK-BASED COMPENSATION PLANS

20. 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.

On February 27, 2023, Cenovus granted PSUs and RSUs to certain employees under its new Performance Share Unit Plan for Local Employees in the Asia Pacific Region and Restricted Share Unit Plan for Local Employees in the Asia Pacific Region. The PSUs are time-vested whole-share units that entitle employees to receive a cash payment equal to the value of a Cenovus common share. The number of units 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. The RSUs are whole-share units and entitle employees to receive, upon vesting, a cash payment equal to the value of a Cenovus common share.

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

	Units Outstanding	Units Exercisable
As at September 30, 2023	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	12,158	6,905
Cenovus Replacement Stock Options	1,095	1,072
Performance Share Units	10,193	—
Restricted Share Units	7,217	—
Deferred Share Units	1,662	1,662

The weighted average exercise price of NSRs and Cenovus replacement stock options outstanding as at September 30, 2023, were $13.62 and $6.52, respectively.

	Units Granted	Units Vested and Exercised/ Paid Out
For the nine months ended September 30, 2023	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	1,571	3,591
Cenovus Replacement Stock Options	—	2,031
Performance Share Units	2,533	972
Restricted Share Units	2,955	2,299
Deferred Share Units	162	33

	Weighted Average Exercise Price	Units Exercised
For the nine months ended September 30, 2023	($/unit)	(thousands)
Stock Options With Associated Net Settlement Rights Exercised for Net Cash Payment	12.94	3,392
Stock Options With Associated Net Settlement Rights Exercised and Net Settled for Common Shares (1)	17.22	199
Cenovus Replacement Stock Options Exercised and Net Settled for Cash	10.11	2,028
Cenovus Replacement Stock Options Exercised and Net Settled for Common Shares (2)	3.54	3

(1)NSRs were net settled for 49 thousand common shares.

(2)Cenovus replacement stock options were net settled for 2 thousand common shares.

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

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Stock Options With Associated Net Settlement Rights	2	3	9	12
Cenovus Replacement Stock Options	6	(5)	(1)	36
Performance Share Units	98	1	125	66
Restricted Share Units	35	4	56	65
Deferred Share Units	10	(4)	7	14
Stock-Based Compensation Expense (Recovery)	151	(1)	196	193

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Related Party Transactions

9 Months Ended

Sep. 30, 2023

Disclosure of related party [Abstract]

RELATED PARTY TRANSACTIONS

21. RELATED PARTY TRANSACTIONS

Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 11). As the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs.

The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or on a cost recovery basis with certain restrictions. For the three and nine months ended September 30, 2023, the Company charged HMLP $49 million and $112 million, respectively, for construction costs and management services (three and nine months ended September 30, 2022 – $56 million and $133 million, respectively).

The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the three and nine months ended September 30, 2023, the Company incurred costs of $67 million and $205 million, respectively, for the use of HMLP’s pipeline systems, as well as for transportation and storage services (three and nine months ended September 30, 2022 – $64 million and $197 million, respectively).

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Financial Instruments

9 Months Ended

Sep. 30, 2023

Disclosure of detailed information about financial instruments [abstract]

FINANCIAL INSTRUMENTS

22. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, net investment in finance leases, risk management assets and liabilities, investments in the equity of companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and other liabilities. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of restricted cash, net investment in finance leases and long-term receivables 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 September 30, 2023, the carrying value of Cenovus’s long-term debt was $7.2 billion and the fair value was $6.2 billion (December 31, 2022, carrying value – $8.7 billion; fair value – $7.8 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 on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available.

The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:

	Total
As at December 31, 2022	55
Acquisition	11
As at September 30, 2023	66

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures, as well as renewable power, power and foreign exchange contracts. The Company may also enter into swaps, forwards, and options to manage commodity, foreign exchange and interest rate exposures. The Company’s risk management assets and liabilities are measured as Level 2 or Level 3 prices in the fair value hierarchy. Level 2 prices sourced from observable data or market corroboration refer to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Level 3 prices are sourced from partially unobservable data used in internal valuations.

Crude oil, natural gas, condensate, refined product 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, interest rate swaps and cross currency interest rate swaps is calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2).

The fair value of renewable power contracts are 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 that consists of individuals who are knowledgeable and have experience in fair value techniques.

Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets (for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings (Loss) within (gain) loss on risk management.

Summary of Risk Management Positions

	September 30, 2023			December 31, 2022
	Risk Management			Risk Management
As at	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	—	49	(49)	2	40	(38)
Power Swap Contracts	4	2	2	1	7	(6)
Renewable Power Contracts	21	—	21	90	—	90
Foreign Exchange Rate Contracts	—	1	(1)	—	—	—
	25	52	(27)	93	47	46

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

	September 30,	December 31,
As at	2023	2022
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(48)	(44)
Level 3 – Prices Sourced From Partially Unobservable Data	21	90
	(27)	46

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

	Total
As at December 31, 2022	46
Change in Fair Value of Contracts in Place, Beginning of Year	1
Change in Fair Value of Contracts Entered Into During the Period	(76)
Fair Value of Contracts Realized During the Period	1
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	1
As at September 30, 2023	(27)

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

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Realized (Gain) Loss	—	(10)	1	1,628
Unrealized (Gain) Loss	72	(18)	88	(88)
(Gain) Loss on Risk Management	72	(28)	89	1,540

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

Fair Value of Contingent Payments

The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value in the Consolidated Balance Sheets within contingent payments. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes 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 September 30, 2023, the fair value of the variable payment was estimated to be $295 million applying a credit-adjusted risk-free rate of 5.4 percent.

As at September 30, 2023, average WCS forward pricing for the remaining term of the variable payment is $89.81 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 36.6 percent and 5.9 percent, respectively. A sensitivity analysis for the following inputs to the option pricing model was performed, with fluctuations in all other variables held constant, and found to have a nominal impact on earnings before income tax:

•A $10.00 per barrel increase or decrease in WCS forward prices.

•A 10 percent increase or decrease in WTI option volatility.

•A five percent increase or decrease in Canadian to U.S. dollar foreign exchange rate option volatility.

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Risk Management

9 Months Ended

Sep. 30, 2023

Risk Management [Abstract]

Risk Management

23. 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 to manage exposure to future carbon compliance costs or to offset select carbon emissions.

The Company entered into risk management positions to help capture incremental margin expected to be received in future periods at the time products will be sold and to mitigate overall exposure to fluctuations in commodity prices related to inventories and physical sales. Mitigation of commodity price volatility may utilize financial positions to protect future cash flows. To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs, power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts.

As at September 30, 2023, the fair value of risk management positions was a net liability of $27 million and consisted of crude oil, natural gas, condensate, refined products, power, including renewable power, and foreign exchange rate instruments. As at September 30, 2023, there were foreign exchange contracts with a notional value of US$302 million (December 31, 2022 – US$168 million) and no interest rate contracts or cross currency interest rate swap contracts (December 31, 2022 – $nil).

Net Fair Value of Risk Management Positions

As at September 30, 2023	Notional Volumes (1) (2)	Terms (3)	Weighted Average Price (1) (2)	Fair Value Asset (Liability)
Futures Contracts Related to Blending (4)
WTI Fixed – Sell	6.2 MMbbls	October 2023 - June 2024	US$83.06/bbl	(52)
WTI Fixed – Buy	2.6 MMbbls	October 2023 - June 2024	US$86.23/bbl	13
Power Swap Contracts				2
Renewable Power Contracts				21
Other Financial Positions (5)				(10)
Foreign Exchange Rate Contracts				(1)
Total Fair Value				(27)

(1)    Million barrels (“MMbbls”). Barrel (“bbl”).

(2)    Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3)    Includes individual contracts with terms less than one year.

(4)    WTI futures contracts are used to help manage price exposure to condensate used for blending.

(5)    Includes risk management positions related to WCS, heavy oil and condensate differential contracts, 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. manufacturing and marketing activities.

A) Commodity Price and Foreign Exchange Rate Risk

Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at September 30, 2023	Sensitivity Range	Increase	Decrease
WCS and Condensate Differential Price	± US$2.50/bbl Applied to Differential Hedges Tied to Production	2	(2)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(23)	23
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(5)	5
Natural Gas Basis Price	± US$0.50/Mcf (1) Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/MWh (2) Applied to Power Hedges	109	(109)
U.S. to Canadian Dollar Exchange Rate	± 0.05 in the U.S. to Canadian Dollar Exchange Rate	26	(30)

(1)One thousand cubic feet (“Mcf”).

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

A US$10.00 per barrel increase or decrease in the crude oil commodity price would result in a nominal unrealized gain (loss) impact to earnings before income tax.

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 September 30, 2023, approximately 83 percent (December 31, 2022 – 85 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 98 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss on these accounts was 0.6 percent as at September 30, 2023 (December 31, 2022 – 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. Cenovus manages its liquidity risk through the active management of cash and debt, and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 13, 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 the bottom of the commodity price cycle to manage the Company’s overall debt position.

Undiscounted cash outflows relating to financial liabilities are:

As at September 30, 2023	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,435	—	—	—	6,435
Short-Term Borrowings	14	—	—	—	14
Lease Liabilities (2)	445	734	577	2,700	4,456
Long-Term Debt (2)	318	807	3,038	7,372	11,535
Contingent Payments	300	—	—	—	300
As at December 31, 2022	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,124	—	—	—	6,124
Short-Term Borrowings	115	—	—	—	115
Lease Liabilities (2)	426	746	596	2,889	4,657
Long-Term Debt (2)	401	983	2,014	11,196	14,594
Contingent Payments	271	167	—	—	438

(1)Includes current risk management liabilities.

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

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Supplementary Cash Flow Information

9 Months Ended

Sep. 30, 2023

Disclosure Of Supplementary Cash Flow Information [Abstract]

Supplementary Cash Flow Information

24. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital

	September 30,	December 31,
As at	2023	2022
Total Current Assets	10,745	12,430
Total Current Liabilities	7,205	8,021
Working Capital	3,540	4,409

As at September 30, 2023, adjusted working capital was $3.8 billion (December 31, 2022 – $4.7 billion), excluding the current portion of the contingent payments of $295 million (December 31, 2022 – $263 million).

Changes in non-cash working capital is as follows:

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Accounts Receivable and Accrued Revenues	(1,288)	1,746	(1,097)	119
Income Tax Receivable	157	(111)	(12)	(88)
Inventories	(505)	1,138	(343)	(172)
Accounts Payable and Accrued Liabilities	851	(1,547)	69	(388)
Income Tax Payable	107	74	(1,056)	877
Total Change in Non-Cash Working Capital	(678)	1,300	(2,439)	348
Net Change in Non-Cash Working Capital – Operating Activities	(641)	1,193	(2,142)	(98)
Net Change in Non-Cash Working Capital – Investing Activities	(37)	107	(297)	446
Total Change in Non-Cash Working Capital	(678)	1,300	(2,439)	348

B) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable	Warrant Purchase Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2021	—	—	79	12,385	2,957
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(81)	—	—
(Repayment) of Long-Term Debt	—	—	—	(4,149)	—
Principal Repayment of Leases	—	—	—	—	(228)
Base Dividends Paid on Common Shares	(481)	—	—	—	—
Dividends Paid on Preferred Shares	(26)	—	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	—	(29)	—
Finance and Transaction Costs	—	—	—	(24)	—
Lease Additions	—	—	—	—	19
Lease Modifications	—	—	—	—	46
Lease Re-measurements	—	—	—	—	3
Lease Terminations	—	—	—	—	(2)
Base Dividends Declared on Common Shares	481	—	—	—	—
Dividends Declared on Preferred Shares	26	—	—	—	—
Exchange Rate Movements and Other	—	—	2	591	74
As at September 30, 2022	—	—	—	8,774	2,869
As at December 31, 2022	9	—	115	8,691	2,836
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(101)	—	—
(Repayment) of Long-Term Debt	—	—	—	(1,346)	—
Principal Repayment of Leases	—	—	—	—	(216)
Base Dividends Paid on Common Shares	(729)	—	—	—	—
Dividends Paid on Preferred Shares	(27)	—	—	—	—
Payment for Purchase of Warrants	—	(600)	—	—	—
Finance and Transaction Costs	—	(2)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	—	(84)	—
Finance and Transaction Costs	—	2	—	(15)	—
Lease Acquisitions	—	—	—	—	33
Lease Additions	—	—	—	—	45
Lease Modifications	—	—	—	—	34
Lease Re-measurements	—	—	—	—	(6)
Lease Divestitures	—	—	—	—	(11)
Lease Terminations	—	—	—	—	(8)
Base Dividends Declared on Common Shares	729	—	—	—	—
Dividends Declared on Preferred Shares	27	—	—	—	—
Warrants Purchased and Cancelled	—	711	—	—	—
Exchange Rate Movements and Other	—	—	—	(22)	26
As at September 30, 2023	9	111	14	7,224	2,733

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2023

Commitments And Contingencies [Abstract]

Commitments and Contingencies

25. 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 September 30, 2023	Remainder of Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	432	1,958	1,717	1,453	1,408	13,263	20,231
Product Purchases	393	779	—	—	—	—	1,172
Real Estate (3)	15	53	54	56	59	619	856
Obligation to Fund Equity-Accounted Affiliate (4)	25	105	96	96	91	145	558
Other Long-Term Commitments (5) (6)	284	185	163	151	142	948	1,873
Total Commitments	1,149	3,080	2,030	1,756	1,700	14,975	24,690

(1)Includes transportation commitments of $9.1 billion (December 31, 2022 – $9.1 billion) that are subject to regulatory approval or were approved, but are not yet in service. Terms are up to 20 years subsequent to the commencement of the contract. Estimated tolls reflect the original contract rate and are subject to change pending approval by the Canada Energy Regulator.

(2)As at September 30, 2023, the Company had commitments with HMLP that included $2.1 billion related to long-term transportation and storage commitments (December 31, 2022 – $2.2 billion).

(3)Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision was provided.

(4)Relates to funding obligations for HCML.

(5)Includes Cenovus’s proportionate share of the commitments related to WRB and joint arrangements in the Offshore segment.

(6)The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023.

There were outstanding letters of credit aggregating to $353 million (December 31, 2022 – $490 million) issued as security for financial and performance conditions under certain contracts.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its interim Consolidated Financial Statements.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

XML

Prior Period Revisions

9 Months Ended

Sep. 30, 2023

Corporate information and statement of IFRS compliance [abstract]

Prior Period Revisions

26. PRIOR PERIOD REVISIONS

Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was revised.

Classification Revisions

During the three months ended September 30, 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made:

•Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense.

•Report sales of feedstock between the Oil Sands, Conventional and U.S. Manufacturing segments on a net basis, which resulted in a reclassification between gross sales and purchased product.

Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position.

It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position.

Change to Reporting Segments

In September 2022, the Company completed the divestiture of the majority of the retail fuels business. In December 2022, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods were reclassified to reflect this change, with no impact to net earnings (loss), cash flows or financial position.

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

i) Three Months Ended March 31, 2023, and June 30, 2023

	Three Months Ended March 31, 2023 (1)			Three Months Ended June 30, 2023 (2)
Oil Sands Segment	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Gross Sales	5,911	(204)	5,707	6,556	(119)	6,437
Purchased Product	559	(204)	355	533	(119)	414
	5,352	—	5,352	6,023	—	6,023

Conventional Segment
Gross Sales	1,031	6	1,037	615	5	620
Purchased Product	510	(27)	483	352	(15)	337
Transportation and Blending	48	33	81	46	20	66
	473	—	473	217	—	217

U.S. Manufacturing Segment
Gross Sales	5,860	(231)	5,629	6,198	(134)	6,064
Purchased Product	5,129	(231)	4,898	5,498	(134)	5,364
	731	—	731	700	—	700

Corporate and Eliminations Segment
Gross Sales	(1,925)	429	(1,496)	(2,092)	248	(1,844)
Purchased Product	(1,499)	479	(1,020)	(1,757)	287	(1,470)
Transportation and Blending	(141)	(134)	(275)	(109)	(98)	(207)
Operating	(231)	84	(147)	(185)	59	(126)
	(54)	—	(54)	(41)	—	(41)

Consolidated
Purchased Product	5,792	17	5,809	5,709	19	5,728
Transportation and Blending	2,853	(101)	2,752	2,641	(78)	2,563
Operating	1,552	84	1,636	1,541	59	1,600
	10,197	—	10,197	9,891	—	9,891

(1)Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in the U.S. Manufacturing segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting adjustment to the Corporate and Eliminations segment.

(2)Includes revisions to gross sales and purchased product of $119 million in the Oil Sands segment, $15 million in the Conventional segment and $134 million in the U.S. Manufacturing segment for the reasons noted above.

ii) Three and Nine Months Ended September 30, 2022

	Three Months Ended September 30, 2022				Nine Months Ended September 30, 2022
Oil Sands Segment	Previously Reported	Revisions	Segment Aggregation	Revised Balance	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Gross Sales	8,778	(14)	—	8,764	28,044	(14)	—	28,030
Purchased Product	1,933	(14)	—	1,919	4,216	(14)	—	4,202
	6,845	—	—	6,845	23,828	—	—	23,828

Conventional Segment
Gross Sales	1,010	26	—	1,036	3,201	85	—	3,286
Transportation and Blending	38	26	—	64	106	85	—	191
	972	—	—	972	3,095	—	—	3,095

Canadian Manufacturing Segment
Gross Sales	1,478	—	690	2,168	4,043	—	1,977	6,020
Purchased Product	1,092	3	655	1,750	3,192	3	1,870	5,065
Transportation and Blending	3	(3)	—	—	3	(3)	—	—
Operating	134	—	38	172	438	—	96	534
Depreciation, Depletion and     Amortization	37	—	5	42	143	—	21	164
	212	—	(8)	204	267	—	(10)	257

U.S. Manufacturing Segment
Gross Sales	8,719	(14)	—	8,705	23,702	(14)	—	23,688
Purchased Product	7,944	(14)	—	7,930	20,365	(14)	—	20,351
	775	—	—	775	3,337	—	—	3,337

Retail Segment
Gross Sales	881	—	(881)	—	2,424	—	(2,424)	—
Purchased Product	846	—	(846)	—	2,317	—	(2,317)	—
Operating	38	—	(38)	—	96	—	(96)	—
Depreciation, Depletion and     Amortization	5	—	(5)	—	21	—	(21)	—
	(8)	—	8	—	(10)	—	10	—

Corporate and Eliminations Segment
Gross Sales	(2,619)	2	191	(2,426)	(6,162)	(57)	447	(5,772)
Purchased Product	(2,267)	65	191	(2,011)	(4,660)	173	447	(4,040)
Transportation and Blending	(119)	(128)	—	(247)	(528)	(383)	—	(911)
Operating	(256)	65	—	(191)	(918)	153	—	(765)
	23	—	—	23	(56)	—	—	(56)

Consolidated
Purchased Product	10,012	40	—	10,052	26,890	148	—	27,038
Transportation and Blending	2,684	(105)	—	2,579	8,707	(301)	—	8,406
Operating	1,439	65	—	1,504	4,207	153	—	4,360
	14,135	—	—	14,135	39,804	—	—	39,804

XML

Description of Business and Segmented Disclosures (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure Of Reportable Segments [Abstract]

Schedule of Segment and Operational Information

	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2023	2022	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	7,571	8,764	810	1,036	402	450	8,783	10,250
Less: Royalties	1,082	1,136	27	68	26	22	1,135	1,226
	6,489	7,628	783	968	376	428	7,648	9,024
Expenses
Purchased Product (1)	462	1,919	438	464	—	—	900	2,383
Transportation and Blending (1)	2,324	2,758	73	64	—	4	2,397	2,826
Operating	688	689	150	141	76	85	914	915
Realized (Gain) Loss on Risk    Management	(6)	42	(4)	9	—	—	(10)	51
Operating Margin	3,021	2,220	126	290	300	339	3,447	2,849
Unrealized (Gain) Loss on Risk    Management	47	(2)	7	8	—	—	54	6
Depreciation, Depletion and    Amortization	785	652	104	103	130	132	1,019	887
Exploration Expense	—	7	—	—	2	66	2	73
(Income) Loss From Equity-    Accounted Affiliates	—	—	—	—	(11)	(9)	(11)	(9)
Segment Income (Loss)	2,189	1,563	15	179	179	150	2,383	1,892

(1)Comparative periods reflect certain revisions. See Note 26.

	Downstream
For the three months ended	Canadian Manufacturing		U.S. Manufacturing		Total
September 30,	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	1,805	2,168	7,853	8,705	9,658	10,873
Less: Royalties	—	—	—	—	—	—
	1,805	2,168	7,853	8,705	9,658	10,873
Expenses
Purchased Product (1)	1,480	1,750	6,467	7,930	7,947	9,680
Transportation and Blending (1)	—	—	—	—	—	—
Operating	155	172	623	608	778	780
Realized (Gain) Loss on Risk Management	—	—	11	(77)	11	(77)
Operating Margin	170	246	752	244	922	490
Unrealized (Gain) Loss on Risk Management	—	—	(2)	(8)	(2)	(8)
Depreciation, Depletion and Amortization	50	42	109	91	159	133
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	120	204	645	161	765	365

For the three months ended	Corporate and Eliminations		Consolidated
September 30,	2023	2022	2023	2022
Revenues
Gross Sales (1)	(2,729)	(2,426)	15,712	18,697
Less: Royalties	—	—	1,135	1,226
	(2,729)	(2,426)	14,577	17,471
Expenses
Purchased Product (1)	(2,227)	(2,011)	6,620	10,052
Transportation and Blending (1)	(233)	(247)	2,164	2,579
Operating (1)	(139)	(191)	1,553	1,504
Realized (Gain) Loss on Risk Management	(1)	16	—	(10)
Unrealized (Gain) Loss on Risk Management	20	(16)	72	(18)
Depreciation, Depletion and Amortization	19	27	1,197	1,047
Exploration Expense	—	—	2	73
(Income) Loss From Equity-Accounted Affiliates	—	—	(11)	(9)
Segment Income (Loss)	(168)	(4)	2,980	2,253
General and Administrative	292	128	292	128
Finance Costs	106	207	106	207
Interest Income	(33)	(21)	(33)	(21)
Integration and Transaction Costs	12	27	12	27
Foreign Exchange (Gain) Loss, Net	133	316	133	316
Revaluation (Gain) Loss	—	(549)	—	(549)
Re-measurement of Contingent Payments	67	(109)	67	(109)
(Gain) Loss on Divestiture of Assets	—	60	—	60
Other (Income) Loss, Net	(22)	(59)	(22)	(59)
	555	—	555	—
Earnings (Loss) Before Income Tax			2,425	2,253
Income Tax Expense (Recovery)			561	644
Net Earnings (Loss)			1,864	1,609

(1)Comparative periods reflect certain revisions. See Note 26.

ii) Results for the Nine Months Ended September 30

	Upstream
For the nine months ended	Oil Sands		Conventional		Offshore		Total
September 30,	2023	2022	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	19,715	28,030	2,467	3,286	1,103	1,575	23,285	32,891
Less: Royalties	2,218	3,709	85	228	65	56	2,368	3,993
	17,497	24,321	2,382	3,058	1,038	1,519	20,917	28,898
Expenses
Purchased Product (1)	1,231	4,202	1,258	1,460	—	—	2,489	5,662
Transportation and Blending (1)	7,965	9,114	220	191	9	12	8,194	9,317
Operating	2,101	2,197	444	403	281	234	2,826	2,834
Realized (Gain) Loss on Risk    Management	(7)	1,468	—	17	—	—	(7)	1,485
Operating Margin	6,207	7,340	460	987	748	1,273	7,415	9,600
Unrealized (Gain) Loss on Risk    Management	44	(59)	(14)	7	—	—	30	(52)
Depreciation, Depletion and    Amortization	2,230	1,977	286	282	349	441	2,865	2,700
Exploration Expense	4	7	—	1	6	91	10	99
(Income) Loss From Equity-    Accounted Affiliates	6	8	—	—	(29)	(19)	(23)	(11)
Segment Income (Loss)	3,923	5,407	188	697	422	760	4,533	6,864

(1)Comparative periods reflect certain revisions. See Note 26.

	Downstream
For the nine months ended	Canadian Manufacturing		U.S. Manufacturing		Total
September 30,	2023	2022	2023	2022	2023	2022
Revenues
Gross Sales (1)	4,676	6,020	19,546	23,688	24,222	29,708
Less: Royalties	—	—	—	—	—	—
	4,676	6,020	19,546	23,688	24,222	29,708
Expenses
Purchased Product (1)	3,656	5,065	16,729	20,351	20,385	25,416
Transportation and Blending (1)	—	—	—	—	—	—
Operating	471	534	1,904	1,757	2,375	2,291
Realized (Gain) Loss on Risk Management	—	—	6	120	6	120
Operating Margin	549	421	907	1,460	1,456	1,881
Unrealized (Gain) Loss on Risk Management	—	—	(13)	(22)	(13)	(22)
Depreciation, Depletion and Amortization	136	164	314	259	450	423
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	413	257	606	1,223	1,019	1,480

For the nine months ended	Corporate and Eliminations		Consolidated
September 30,	2023	2022	2023	2022
Revenues
Gross Sales (1)	(6,069)	(5,772)	41,438	56,827
Less: Royalties	—	—	2,368	3,993
	(6,069)	(5,772)	39,070	52,834
Expenses
Purchased Product (1)	(4,717)	(4,040)	18,157	27,038
Transportation and Blending (1)	(715)	(911)	7,479	8,406
Operating (1)	(412)	(765)	4,789	4,360
Realized (Gain) Loss on Risk Management	2	23	1	1,628
Unrealized (Gain) Loss on Risk Management	71	(14)	88	(88)
Depreciation, Depletion and Amortization	59	86	3,374	3,209
Exploration Expense	—	—	10	99
(Income) Loss From Equity-Accounted Affiliates	—	—	(23)	(11)
Segment Income (Loss)	(357)	(151)	5,195	8,193
General and Administrative	617	545	617	545
Finance Costs	493	631	493	631
Interest Income	(100)	(44)	(100)	(44)
Integration and Transaction Costs	49	79	49	79
Foreign Exchange (Gain) Loss, Net	7	406	7	406
Revaluation (Gain) Loss	33	(549)	33	(549)
Re-measurement of Contingent Payments	83	142	83	142
(Gain) Loss on Divestiture of Assets	(11)	(244)	(11)	(244)
Other (Income) Loss, Net	(42)	(467)	(42)	(467)
	1,129	499	1,129	499
Earnings (Loss) Before Income Tax			4,066	7,694
Income Tax Expense (Recovery)			700	2,028
Net Earnings (Loss)			3,366	5,666

(1)Comparative periods reflect certain revisions. See Note 26.

Schedule of Revenues by Product

) Revenues by Product

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Upstream
Crude Oil (1) (2)	6,666	7,384	17,671	24,143
Natural Gas (2)	563	973	1,975	2,740
NGLs (1)	382	571	1,088	1,684
Other	37	96	183	331
Total Upstream	7,648	9,024	20,917	28,898
Downstream
Canadian Manufacturing
Synthetic Crude Oil	657	657	1,607	1,786
Diesel	460	567	1,286	1,544
Gasoline	162	298	410	837
Asphalt	200	248	431	482
Other Products and Services	326	398	942	1,371
U.S. Manufacturing
Gasoline	3,822	3,919	9,336	11,180
Distillates	2,871	3,384	7,169	8,535
Asphalt	326	196	610	402
Other Products (2)	834	1,206	2,431	3,571
Total Downstream	9,658	10,873	24,222	29,708
Corporate and Eliminations (2)	(2,729)	(2,426)	(6,069)	(5,772)
Consolidated	14,577	17,471	39,070	52,834

(1)Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.

(2)Comparative periods reflect certain revisions. See Note 26.

Schedule of Geographical Information

C) Geographical Information

	Revenues (1)
	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Canada (2)	6,666	7,999	18,828	26,471
United States (2)	7,611	9,155	19,425	25,340
China	300	317	817	1,023
Consolidated	14,577	17,471	39,070	52,834

(1)Revenues by country are classified based on where the operations are located.

(2)Comparative periods reflect certain revisions. See Note 26.

	Non-Current Assets (1)
	September 30,	December 31,
As at	2023	2022
Canada	35,257	35,194
United States	5,284	4,824
China	1,758	2,064
Indonesia	356	365
Consolidated	42,655	42,447

(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.

Schedule of Assets by Segment

D) Assets by Segment

	E&E Assets		PP&E		ROU Assets
	September 30,	December 31,	September 30,	December 31,	September 30,	December 31,
As at	2023	2022	2023	2022	2023	2022
Oil Sands	785	674	24,271	24,657	687	638
Conventional	5	6	2,045	2,020	2	2
Offshore	6	5	2,679	2,549	103	152
Canadian Manufacturing	—	—	2,438	2,466	220	252
U.S. Manufacturing	—	—	4,981	4,482	286	329
Corporate and Eliminations	—	—	313	325	440	472
Consolidated	796	685	36,727	36,499	1,738	1,845

	Goodwill		Total Assets
	September 30,	December 31,	September 30,	December 31,
As at	2023	2022	2023	2022
Oil Sands	2,923	2,923	32,481	32,248
Conventional	—	—	2,278	2,410
Offshore	—	—	3,416	3,339
Canadian Manufacturing	—	—	3,320	3,172
U.S. Manufacturing	—	—	9,728	8,324
Corporate and Eliminations	—	—	3,204	6,376
Consolidated	2,923	2,923	54,427	55,869

Schedule of Capital Expenditures

E) Capital Expenditures (1)

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Capital Investment
Oil Sands	590	360	1,764	1,111
Conventional	100	67	323	188
Offshore
Asia Pacific	3	3	4	5
Atlantic	191	78	474	220
Total Upstream	884	508	2,565	1,524
Canadian Manufacturing	38	24	99	77
U.S. Manufacturing	88	300	435	774
Total Downstream	126	324	534	851
Corporate and Eliminations	15	34	29	59
	1,025	866	3,128	2,434
Acquisitions (Note 3)
Oil Sands	32	1,596	35	1,596
Conventional	1	5	5	6
U.S. Manufacturing (2)	—	—	337	—
	33	1,601	377	1,602
Total Capital Expenditures	1,058	2,467	3,505	4,036

(1)Includes expenditures on PP&E, E&E assets and capitalized interest.

(2)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 $320 million.

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2023

Business Combination [Abstract]

Disclosure of detailed information about business combination

The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition.

As at	February 28, 2023
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash	69
Accounts Receivable and Accrued Revenues	3
Inventories	453
Property, Plant and Equipment	674
Right-of-Use Assets	33
Other Assets	10
Accounts Payable and Accrued Liabilities	(138)
Lease Liabilities	(33)
Decommissioning Liabilities	(5)
Other Liabilities	(70)
Total Identifiable Net Assets	996

As at	February 28, 2023
Total Purchase Consideration	502
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo	494
Fair Value of Identifiable Net Assets	(996)
Goodwill	—

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Finance Costs (Tables)

9 Months Ended

Sep. 30, 2023

Finance Costs [Abstract]

Schedule of Finance Cost

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Interest Expense – Short-Term Borrowings and Long-Term Debt	94	121	285	381
Net Premium (Discount) on Redemption of Long-Term Debt (1)	(84)	(4)	(84)	(29)
Interest Expense – Lease Liabilities (Note 14)	41	40	121	123
Unwinding of Discount on Decommissioning Liabilities (Note 16)	55	43	165	132
Other	5	9	18	27
	111	209	505	634
Capitalized Interest	(5)	(2)	(12)	(3)
	106	207	493	631

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Foreign Exchange (Gain) Loss, Net (Tables)

9 Months Ended

Sep. 30, 2023

Foreign Exchange Gains Losses [Abstract]

Schedule of Foreign Exchange Gain Loss Net

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	28	324	(119)	444
Other	31	(26)	20	(25)
Unrealized Foreign Exchange (Gain) Loss	59	298	(99)	419
Realized Foreign Exchange (Gain) Loss	74	18	106	(13)
	133	316	7	406

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure Of Income Tax Expense Continuing Operations [Abstract]

Provision for Income Taxes

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Current Tax
Canada	484	187	941	1,124
United States	4	(185)	4	96
Asia Pacific	68	64	152	173
Other International	7	10	19	10
Total Current Tax Expense (Recovery)	563	76	1,116	1,403
Deferred Tax Expense (Recovery)	(2)	568	(416)	625
	561	644	700	2,028

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Per Share Amounts (Tables)

9 Months Ended

Sep. 30, 2023

Earnings per share [abstract]

Schedule Representing Per Share Amounts

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Net Earnings (Loss)	1,864	1,609	3,366	5,666
Effect of Cumulative Dividends on Preferred Shares	(9)	(9)	(27)	(26)
Net Earnings (Loss) – Basic and Diluted	1,855	1,600	3,339	5,640
Basic – Weighted Average Number of Shares (thousands)	1,891,937	1,927,864	1,900,952	1,962,813
Dilutive Effect of Warrants	6,408	41,956	27,491	45,002
Dilutive Effect of Net Settlement Rights	6,752	7,188	7,643	10,657
Dilutive Effect of Cenovus Replacement Stock Options	—	1,637	630	—
Diluted – Weighted Average Number of Shares (thousands)	1,905,097	1,978,645	1,936,716	2,018,472
Net Earnings (Loss) Per Common Share – Basic ($)	0.98	0.83	1.76	2.87
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)	0.97	0.81	1.72	2.79

(1)For the three months ended September 30, 2023, net earnings of $6 million and common shares of 0.6 million related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the impact was anti-dilutive. For the nine months ended September 30, 2022, net earnings of $35 million and common shares of 1.6 million related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive.

(2)For the three and nine months ended September 30, 2023, net settlement rights (“NSRs”) of 1.5 million and 1.5 million, respectively, (three and nine months ended September 30, 2022 – 2.0 million and 2.0 million, respectively) were excluded from the calculation of diluted weighted average number of shares as the effect was anti-dilutive.

Disclosure Of Dividends To Shareholders

	2023		2022
For the nine months ended September 30,	Per Share	Amount	Per Share	Amount
Base Dividends	0.385	729	0.245	481
Variable Dividends	—	—	—	—
Total Common Share Dividends Declared and Paid	0.385	729	0.245	481

C) Preferred Share Dividends

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Series 1 First Preferred Shares	2	1	5	5
Series 2 First Preferred Shares	1	1	2	1
Series 3 First Preferred Shares	3	3	9	9
Series 5 First Preferred Shares	2	3	7	7
Series 7 First Preferred Shares	1	1	4	4
Total Preferred Share Dividends Declared	9	9	27	26

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Exploration and Evaluation Assets, Net (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure Of Exploration And Evaluation Assets [Abstract]

Summary of Exploration and Valuation Assets, Net

	Total
As at December 31, 2022	685
Acquisition	31
Additions	80
As at September 30, 2023	796

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Property, Plant and Equipment, Net (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure of detailed information about property, plant and equipment [abstract]

Summary of Property, Plant and Equipment

	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Manufacturing Assets	Other Assets (1)	Total
COST
As at December 31, 2022	43,528	254	12,132	1,825	57,739
Acquisitions (Note 3) (2)	9	—	674	—	683
Additions	2,485	19	508	36	3,048
Change in Decommissioning Liabilities	42	—	2	—	44
Divestitures (Note 3) (2)	(17)	—	(633)	(17)	(667)
Exchange Rate Movements and Other	(19)	5	(39)	(8)	(61)
As at September 30, 2023	46,028	278	12,644	1,836	60,786
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2022	14,302	106	5,547	1,285	21,240
Depreciation, Depletion and Amortization (3)	2,726	16	366	42	3,150
Divestitures (Note 3) (2)	(8)	—	(299)	(12)	(319)
Exchange Rate Movements and Other	13	4	(23)	(6)	(12)
As at September 30, 2023	17,033	126	5,591	1,309	24,059
CARRYING VALUE
As at December 31, 2022	29,226	148	6,585	540	36,499
As at September 30, 2023	28,995	152	7,053	527	36,727

(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.

(3)DD&A includes asset write-downs of $20 million in the Oil Sands segment and $8 million in the Canadian Manufacturing segment.

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Right of Use Assets, Net (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure of quantitative information about right-of-use assets [abstract]

Summary of Right of Use Assets, Net

	Real Estate	Transportation and Storage Assets (1)	Manufacturing Assets	Other Assets (2)	Total
COST
As at December 31, 2022	599	1,840	174	74	2,687
Acquisitions (Note 3) (3)	1	24	8	—	33
Additions	1	44	—	—	45
Modifications	(4)	37	1	—	34
Re-measurements	—	(11)	—	5	(6)
Divestitures (Note 3) (3)	—	—	(19)	—	(19)
Terminations	(3)	(1)	—	(2)	(6)
Exchange Rate Movements and Other	(4)	24	—	3	23
As at September 30, 2023	590	1,957	164	80	2,791
ACCUMULATED DEPRECIATION
As at December 31, 2022	127	645	58	12	842
Depreciation	27	170	17	10	224
Divestitures (Note 3) (3)	—	—	(12)	—	(12)
Terminations	(1)	(1)	—	(1)	(3)
Exchange Rate Movements and Other	(3)	8	(2)	(1)	2
As at September 30, 2023	150	822	61	20	1,053
CARRYING VALUE
As at December 31, 2022	472	1,195	116	62	1,845
As at September 30, 2023	440	1,135	103	60	1,738

(1)Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.

(2)Includes assets in the commercial fuels business, fleet vehicles 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.

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Joint Arrangements (Tables)

9 Months Ended

Sep. 30, 2023

Subclassifications of assets, liabilities and equities [abstract]

Disclosure of joint ventures

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations

	Nine Months Ended
For the periods ended September 30,	2023	2022
Revenue	439	256
Expenses	373	247
Net Earnings (Loss)	66	9

Balance Sheet

	September 30,	December 31,
As at	2023	2022
Current Assets (1)	285	247
Non-Current Assets	1,767	1,926
Current Liabilities	127	160
Non-Current Liabilities	1,114	1,293
Net Assets	811	720

(1)Includes cash and cash equivalents of $76 million (December 31, 2022 – $64 million).

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Other Assets (Tables)

9 Months Ended

Sep. 30, 2023

Other Noncurrent Assets [Abstract]

Summary of Other Assets

	September 30,	December 31,
As at	2023	2022
Long-Term Receivables and Prepaids	48	120
Precious Metals	79	86
Net Investment in Finance Leases	62	62
Private Equity Investments (Note 22)	66	55
Intangible Assets	11	19
	266	342

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Debt and Capital Structure (Tables)

9 Months Ended

Sep. 30, 2023

Borrowings [abstract]

Schedule of Short-Term and Long-Term Debt

A) Short-Term Borrowings

		September 30,	December 31,
As at	Notes	2023	2022
Uncommitted Demand Facilities	i	—	—
WRB Uncommitted Demand Facilities	ii	14	115
Total Debt Principal		14	115

B) Long-Term Debt

	September 30,	December 31,
As at	2023	2022
Committed Credit Facility (1)	—	—
U.S. Dollar Denominated Unsecured Notes	5,140	6,537
Canadian Dollar Unsecured Notes	2,000	2,000
Total Debt Principal	7,140	8,537
Debt Premiums (Discounts), Net, and Transaction Costs	84	154
Long-Term Debt	7,224	8,691

Schedule Remaining Principal Amounts of U.S. Dollar Denominated Unsecured Notes

	US$ Principal
U.S. Dollar Unsecured Notes
4.40% due April 15, 2029	57
5.25% due June 15, 2037	250
6.80% due September 15, 2037	196
6.75% due November 15, 2039	283
4.45% due September 15, 2042	6
5.20% due September 15, 2043	2
5.40% due June 15, 2047	231
	1,025

The principal amounts of the Company’s outstanding unsecured notes are:

	September 30, 2023		December 31, 2022
	US$ Principal	C$ Principal and Equivalent	US$ Principal	C$ Principal and Equivalent
U.S. Dollar Unsecured Notes
5.38% due July 15, 2025	133	181	133	181
4.25% due April 15, 2027	373	505	373	505
4.40% due April 15, 2029	183	247	240	324
2.65% due January 15, 2032	500	676	500	677
5.25% due June 15, 2037	333	450	583	790
6.80% due September 15, 2037	191	259	387	524
6.75% due November 15, 2039	652	881	935	1,267
4.45% due September 15, 2042	91	123	97	131
5.20% due September 15, 2043	27	36	29	39
5.40% due June 15, 2047	569	768	800	1,083
3.75% due February 15, 2052	750	1,014	750	1,016
	3,802	5,140	4,827	6,537
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		7,140		8,537

Summary of Net Debt to Adjusted EBITDA

Net Debt to Adjusted EBITDA

	September 30,	December 31,
As at	2023	2022
Short-Term Borrowings	14	115
Current Portion of Long-Term Debt	—	—
Long-Term Portion of Long-Term Debt	7,224	8,691
Total Debt	7,238	8,806
Less: Cash and Cash Equivalents	(1,262)	(4,524)
Net Debt	5,976	4,282
Net Earnings (Loss)	4,150	6,450
Add (Deduct):
Finance Costs	682	820
Interest Income	(137)	(81)
Income Tax Expense (Recovery)	953	2,281
Depreciation, Depletion and Amortization	4,844	4,679
Exploration and Evaluation Asset Write-downs	1	64
(Income) Loss From Equity-Accounted Affiliates	(27)	(15)
Unrealized (Gain) Loss on Risk Management	50	(126)
Foreign Exchange (Gain) Loss, Net	(56)	343
Revaluation (Gain) Loss	33	(549)
Re-measurement of Contingent Payments	103	162
(Gain) Loss on Divestiture of Assets	(36)	(269)
Other (Income) Loss, Net	(107)	(532)
Adjusted EBITDA (1)	10,453	13,227
Net Debt to Adjusted EBITDA	0.6x	0.3x

(1)Calculated on a trailing twelve-month basis.

Disclosure Of Net To Adjusted Funds Flow Explanatory

Net Debt to Adjusted Funds Flow

	September 30,	December 31,
As at	2023	2022
Net Debt	5,976	4,282
Cash From (Used in) Operating Activities	7,412	11,403
(Add) Deduct:
Settlement of Decommissioning Liabilities	(206)	(150)
Net Change in Non-Cash Working Capital	(1,469)	575
Adjusted Funds Flow (1)	9,087	10,978
Net Debt to Adjusted Funds Flow	0.7x	0.4x

(1)Calculated on a trailing twelve-month basis.

Summary of Net Debt to Capitalization

Net Debt to Capitalization

	September 30,		December 31,
As at	2023		2022
Net Debt	5,976		4,282
Shareholders’ Equity	28,814		27,576
Capitalization	34,790		31,858
Net Debt to Capitalization	17	%	13	%

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Lease Liabilities (Tables)

9 Months Ended

Sep. 30, 2023

Lease liabilities [abstract]

Summary of Lease Liabilities

	Total
As at December 31, 2022	2,836
Acquisitions (Note 3) (1)	33
Additions	45
Interest Expense (Note 4)	121
Lease Payments	(337)
Modifications	34
Re-measurements	(6)
Divestitures (Note 3) (1)	(11)
Terminations	(8)
Exchange Rate Movements and Other	26
As at September 30, 2023	2,733
Less: Current Portion	315
Long-Term Portion	2,418

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Contingent Payments (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure of contingent liabilities in business combination [abstract]

Summary of Contingent Payments

	Total
As at December 31, 2022	419
Liabilities Settled or Payable	(207)
Re-measurement	83
As at September 30, 2023	295

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Decommissioning Liabilities (Tables)

9 Months Ended

Sep. 30, 2023

Provision for decommissioning, restoration and rehabilitation costs [abstract]

Summary of Decommissioning Provision

	Total
As at December 31, 2022	3,559
Liabilities Incurred	12
Liabilities Acquired (Note 3) (1)	5
Liabilities Settled	(156)
Liabilities Disposed (Note 3) (1)	(5)
Change in Estimated Future Cash Flows	32
Unwinding of Discount on Decommissioning Liabilities (Note 4)	165
Exchange Rate Movements	(9)
As at September 30, 2023	3,603

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Other Liabilities (Tables)

9 Months Ended

Sep. 30, 2023

Miscellaneous non-current liabilities [abstract]

Summary of Other Liabilities

	September 30,	December 31,
As at	2023	2022
Renewable Volume Obligation, Net (1)	400	101
Pension and Other Post-Employment Benefit Plan	191	201
Provision for West White Rose Expansion Project	169	204
Provisions for Onerous and Unfavourable Contracts	76	95
Employee Long-Term Incentives	127	245
Drilling Provisions	25	31
Deferred Revenue	39	45
Other	156	120
	1,183	1,042

(1)The gross amounts of the renewable volume obligation and renewable identification numbers asset were $1.1 billion and $0.7 billion, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively).

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Share Capital and Warrants (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure of classes of share capital [abstract]

Summary of Share Capital

B) Issued and Outstanding – Common Shares

	September 30, 2023		December 31, 2022
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	1,909,190	16,320	2,001,211	17,016
Issued Upon Exercise of Warrants	2,314	23	9,399	93
Issued Under Stock Option Plans	3,443	54	11,069	170
Purchase of Common Shares Under NCIBs	(29,388)	(251)	(112,489)	(959)
Outstanding, End of Period	1,885,559	16,146	1,909,190	16,320

) Issued and Outstanding – Preferred Shares

For the nine months ended September 30, 2023, there were no preferred shares issued. As at September 30, 2023, there were 36 million preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 – $519 million).

As at September 30, 2023	Dividend Reset Date	Dividend Rate		Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	%	10,740
Series 2 First Preferred Shares (1)	Quarterly	6.89	%	1,260
Series 3 First Preferred Shares	December 31, 2024	4.69	%	10,000
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 5.86 percent for the period from December 31, 2022, to March 30, 2023, 6.29 percent for the period from March 31, 2023, to June 29, 2023, and 6.29 percent from June 30, 2023, to September 29, 2023.

) Issued and Outstanding – Warrants

	September 30, 2023		December 31, 2022
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	55,720	184	65,119	215
Exercised	(2,314)	(7)	(9,399)	(31)
Purchased and Cancelled	(45,485)	(151)	—	—
Outstanding, End of Period	7,921	26	55,720	184

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Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract]

Summary of Accumulated Other Comprehensive Income (Loss)

	Pension and Other Post-Employment Benefits	Private Equity Instruments	Foreign Currency Translation Adjustment	Total
As at December 31, 2021	28	27	629	684
Other Comprehensive Income (Loss), Before Tax	78	2	896	976
Income Tax (Expense) Recovery	(20)	—	—	(20)
As at September 30, 2022	86	29	1,525	1,640
As at December 31, 2022	99	29	1,342	1,470
Other Comprehensive Income (Loss), Before Tax	20	—	(43)	(23)
Reclassification on Divestiture (Note 3)	—	—	12	12
Income Tax (Expense) Recovery	(5)	—	—	(5)
As at September 30, 2023	114	29	1,311	1,454

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Stock-Based Compensation Plans (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure of terms and conditions of share-based payment arrangement [abstract]

Summary of Options Outstanding and Exercisable

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

	Units Outstanding	Units Exercisable
As at September 30, 2023	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	12,158	6,905
Cenovus Replacement Stock Options	1,095	1,072
Performance Share Units	10,193	—
Restricted Share Units	7,217	—
Deferred Share Units	1,662	1,662

The weighted average exercise price of NSRs and Cenovus replacement stock options outstanding as at September 30, 2023, were $13.62 and $6.52, respectively.

	Units Granted	Units Vested and Exercised/ Paid Out
For the nine months ended September 30, 2023	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	1,571	3,591
Cenovus Replacement Stock Options	—	2,031
Performance Share Units	2,533	972
Restricted Share Units	2,955	2,299
Deferred Share Units	162	33

	Weighted Average Exercise Price	Units Exercised
For the nine months ended September 30, 2023	($/unit)	(thousands)
Stock Options With Associated Net Settlement Rights Exercised for Net Cash Payment	12.94	3,392
Stock Options With Associated Net Settlement Rights Exercised and Net Settled for Common Shares (1)	17.22	199
Cenovus Replacement Stock Options Exercised and Net Settled for Cash	10.11	2,028
Cenovus Replacement Stock Options Exercised and Net Settled for Common Shares (2)	3.54	3

(1)NSRs were net settled for 49 thousand common shares.

(2)Cenovus replacement stock options were net settled for 2 thousand common shares.

Summary of Stock-Based Compensation

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

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Stock Options With Associated Net Settlement Rights	2	3	9	12
Cenovus Replacement Stock Options	6	(5)	(1)	36
Performance Share Units	98	1	125	66
Restricted Share Units	35	4	56	65
Deferred Share Units	10	(4)	7	14
Stock-Based Compensation Expense (Recovery)	151	(1)	196	193

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Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure of detailed information about financial instruments [abstract]

Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets

The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:

	Total
As at December 31, 2022	55
Acquisition	11
As at September 30, 2023	66

Summary of Unrealized Risk Management Positions

Summary of Risk Management Positions

	September 30, 2023			December 31, 2022
	Risk Management			Risk Management
As at	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	—	49	(49)	2	40	(38)
Power Swap Contracts	4	2	2	1	7	(6)
Renewable Power Contracts	21	—	21	90	—	90
Foreign Exchange Rate Contracts	—	1	(1)	—	—	—
	25	52	(27)	93	47	46

Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value

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

	September 30,	December 31,
As at	2023	2022
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(48)	(44)
Level 3 – Prices Sourced From Partially Unobservable Data	21	90
	(27)	46

Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

	Total
As at December 31, 2022	46
Change in Fair Value of Contracts in Place, Beginning of Year	1
Change in Fair Value of Contracts Entered Into During the Period	(76)
Fair Value of Contracts Realized During the Period	1
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	1
As at September 30, 2023	(27)

Summary of Earnings Impact of (Gain) Loss from Risk Management Positions

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

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Realized (Gain) Loss	—	(10)	1	1,628
Unrealized (Gain) Loss	72	(18)	88	(88)
(Gain) Loss on Risk Management	72	(28)	89	1,540

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

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at September 30, 2023	Sensitivity Range	Increase	Decrease
WCS and Condensate Differential Price	± US$2.50/bbl Applied to Differential Hedges Tied to Production	2	(2)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(23)	23
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(5)	5
Natural Gas Basis Price	± US$0.50/Mcf (1) Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/MWh (2) Applied to Power Hedges	109	(109)
U.S. to Canadian Dollar Exchange Rate	± 0.05 in the U.S. to Canadian Dollar Exchange Rate	26	(30)

(1)One thousand cubic feet (“Mcf”).

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

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Risk Management (Tables)

9 Months Ended

Sep. 30, 2023

Risk Management [Abstract]

Net Fair Value of Risk Management Positions

Net Fair Value of Risk Management Positions

As at September 30, 2023	Notional Volumes (1) (2)	Terms (3)	Weighted Average Price (1) (2)	Fair Value Asset (Liability)
Futures Contracts Related to Blending (4)
WTI Fixed – Sell	6.2 MMbbls	October 2023 - June 2024	US$83.06/bbl	(52)
WTI Fixed – Buy	2.6 MMbbls	October 2023 - June 2024	US$86.23/bbl	13
Power Swap Contracts				2
Renewable Power Contracts				21
Other Financial Positions (5)				(10)
Foreign Exchange Rate Contracts				(1)
Total Fair Value				(27)

(1)    Million barrels (“MMbbls”). Barrel (“bbl”).

(2)    Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3)    Includes individual contracts with terms less than one year.

(4)    WTI futures contracts are used to help manage price exposure to condensate used for blending.

(5)    Includes risk management positions related to WCS, heavy oil and condensate differential contracts, 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. manufacturing and marketing activities.

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at September 30, 2023	Sensitivity Range	Increase	Decrease
WCS and Condensate Differential Price	± US$2.50/bbl Applied to Differential Hedges Tied to Production	2	(2)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(23)	23
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(5)	5
Natural Gas Basis Price	± US$0.50/Mcf (1) Applied to Natural Gas Basis Hedges	1	(1)
Power Commodity Price	± C$20.00/MWh (2) Applied to Power Hedges	109	(109)
U.S. to Canadian Dollar Exchange Rate	± 0.05 in the U.S. to Canadian Dollar Exchange Rate	26	(30)

(1)One thousand cubic feet (“Mcf”).

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

Undiscounted Cash Outflows Relating to Financial Liabilities

Undiscounted cash outflows relating to financial liabilities are:

As at September 30, 2023	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,435	—	—	—	6,435
Short-Term Borrowings	14	—	—	—	14
Lease Liabilities (2)	445	734	577	2,700	4,456
Long-Term Debt (2)	318	807	3,038	7,372	11,535
Contingent Payments	300	—	—	—	300
As at December 31, 2022	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,124	—	—	—	6,124
Short-Term Borrowings	115	—	—	—	115
Lease Liabilities (2)	426	746	596	2,889	4,657
Long-Term Debt (2)	401	983	2,014	11,196	14,594
Contingent Payments	271	167	—	—	438

(1)Includes current risk management liabilities.

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

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Supplementary Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2023

Disclosure Of Supplementary Cash Flow Information [Abstract]

Disclosure Of Changes In Non-Cash Working Capital Items

Working Capital

	September 30,	December 31,
As at	2023	2022
Total Current Assets	10,745	12,430
Total Current Liabilities	7,205	8,021
Working Capital	3,540	4,409

As at September 30, 2023, adjusted working capital was $3.8 billion (December 31, 2022 – $4.7 billion), excluding the current portion of the contingent payments of $295 million (December 31, 2022 – $263 million).

Changes in non-cash working capital is as follows:

	Three Months Ended		Nine Months Ended
For the periods ended September 30,	2023	2022	2023	2022
Accounts Receivable and Accrued Revenues	(1,288)	1,746	(1,097)	119
Income Tax Receivable	157	(111)	(12)	(88)
Inventories	(505)	1,138	(343)	(172)
Accounts Payable and Accrued Liabilities	851	(1,547)	69	(388)
Income Tax Payable	107	74	(1,056)	877
Total Change in Non-Cash Working Capital	(678)	1,300	(2,439)	348
Net Change in Non-Cash Working Capital – Operating Activities	(641)	1,193	(2,142)	(98)
Net Change in Non-Cash Working Capital – Investing Activities	(37)	107	(297)	446
Total Change in Non-Cash Working Capital	(678)	1,300	(2,439)	348

Summary of Reconciliation of Liabilities to Cash Flows from Financing Activities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable	Warrant Purchase Payable	Short-Term Borrowings	Long-Term Debt	Lease Liabilities
As at December 31, 2021	—	—	79	12,385	2,957
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(81)	—	—
(Repayment) of Long-Term Debt	—	—	—	(4,149)	—
Principal Repayment of Leases	—	—	—	—	(228)
Base Dividends Paid on Common Shares	(481)	—	—	—	—
Dividends Paid on Preferred Shares	(26)	—	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	—	(29)	—
Finance and Transaction Costs	—	—	—	(24)	—
Lease Additions	—	—	—	—	19
Lease Modifications	—	—	—	—	46
Lease Re-measurements	—	—	—	—	3
Lease Terminations	—	—	—	—	(2)
Base Dividends Declared on Common Shares	481	—	—	—	—
Dividends Declared on Preferred Shares	26	—	—	—	—
Exchange Rate Movements and Other	—	—	2	591	74
As at September 30, 2022	—	—	—	8,774	2,869
As at December 31, 2022	9	—	115	8,691	2,836
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(101)	—	—
(Repayment) of Long-Term Debt	—	—	—	(1,346)	—
Principal Repayment of Leases	—	—	—	—	(216)
Base Dividends Paid on Common Shares	(729)	—	—	—	—
Dividends Paid on Preferred Shares	(27)	—	—	—	—
Payment for Purchase of Warrants	—	(600)	—	—	—
Finance and Transaction Costs	—	(2)	—	—	—
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	—	—	—	(84)	—
Finance and Transaction Costs	—	2	—	(15)	—
Lease Acquisitions	—	—	—	—	33
Lease Additions	—	—	—	—	45
Lease Modifications	—	—	—	—	34
Lease Re-measurements	—	—	—	—	(6)
Lease Divestitures	—	—	—	—	(11)
Lease Terminations	—	—	—	—	(8)
Base Dividends Declared on Common Shares	729	—	—	—	—
Dividends Declared on Preferred Shares	27	—	—	—	—
Warrants Purchased and Cancelled	—	711	—	—	—
Exchange Rate Movements and Other	—	—	—	(22)	26
As at September 30, 2023	9	111	14	7,224	2,733

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2023

Commitments And Contingencies [Abstract]

Minimum Future Payments, Commitments And Contingent Liabilities

Future payments for the Company’s commitments are below:

As at September 30, 2023	Remainder of Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	432	1,958	1,717	1,453	1,408	13,263	20,231
Product Purchases	393	779	—	—	—	—	1,172
Real Estate (3)	15	53	54	56	59	619	856
Obligation to Fund Equity-Accounted Affiliate (4)	25	105	96	96	91	145	558
Other Long-Term Commitments (5) (6)	284	185	163	151	142	948	1,873
Total Commitments	1,149	3,080	2,030	1,756	1,700	14,975	24,690

(1)Includes transportation commitments of $9.1 billion (December 31, 2022 – $9.1 billion) that are subject to regulatory approval or were approved, but are not yet in service. Terms are up to 20 years subsequent to the commencement of the contract. Estimated tolls reflect the original contract rate and are subject to change pending approval by the Canada Energy Regulator.

(2)As at September 30, 2023, the Company had commitments with HMLP that included $2.1 billion related to long-term transportation and storage commitments (December 31, 2022 – $2.2 billion).

(3)Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision was provided.

(4)Relates to funding obligations for HCML.

(5)Includes Cenovus’s proportionate share of the commitments related to WRB and joint arrangements in the Offshore segment.

(6)The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023.

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Prior Period Revisions (Tables)

9 Months Ended

Sep. 30, 2023

Corporate information and statement of IFRS compliance [abstract]

Disclosure of Revisions to Prior Period

Three Months Ended March 31, 2023, and June 30, 2023

	Three Months Ended March 31, 2023 (1)			Three Months Ended June 30, 2023 (2)
Oil Sands Segment	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
Gross Sales	5,911	(204)	5,707	6,556	(119)	6,437
Purchased Product	559	(204)	355	533	(119)	414
	5,352	—	5,352	6,023	—	6,023

Conventional Segment
Gross Sales	1,031	6	1,037	615	5	620
Purchased Product	510	(27)	483	352	(15)	337
Transportation and Blending	48	33	81	46	20	66
	473	—	473	217	—	217

U.S. Manufacturing Segment
Gross Sales	5,860	(231)	5,629	6,198	(134)	6,064
Purchased Product	5,129	(231)	4,898	5,498	(134)	5,364
	731	—	731	700	—	700

Corporate and Eliminations Segment
Gross Sales	(1,925)	429	(1,496)	(2,092)	248	(1,844)
Purchased Product	(1,499)	479	(1,020)	(1,757)	287	(1,470)
Transportation and Blending	(141)	(134)	(275)	(109)	(98)	(207)
Operating	(231)	84	(147)	(185)	59	(126)
	(54)	—	(54)	(41)	—	(41)

Consolidated
Purchased Product	5,792	17	5,809	5,709	19	5,728
Transportation and Blending	2,853	(101)	2,752	2,641	(78)	2,563
Operating	1,552	84	1,636	1,541	59	1,600
	10,197	—	10,197	9,891	—	9,891

(1)Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in the U.S. Manufacturing segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting adjustment to the Corporate and Eliminations segment.

(2)Includes revisions to gross sales and purchased product of $119 million in the Oil Sands segment, $15 million in the Conventional segment and $134 million in the U.S. Manufacturing segment for the reasons noted above.

Three and Nine Months Ended September 30, 2022

	Three Months Ended September 30, 2022				Nine Months Ended September 30, 2022
Oil Sands Segment	Previously Reported	Revisions	Segment Aggregation	Revised Balance	Previously Reported	Revisions	Segment Aggregation	Revised Balance
Gross Sales	8,778	(14)	—	8,764	28,044	(14)	—	28,030
Purchased Product	1,933	(14)	—	1,919	4,216	(14)	—	4,202
	6,845	—	—	6,845	23,828	—	—	23,828

Conventional Segment
Gross Sales	1,010	26	—	1,036	3,201	85	—	3,286
Transportation and Blending	38	26	—	64	106	85	—	191
	972	—	—	972	3,095	—	—	3,095

Canadian Manufacturing Segment
Gross Sales	1,478	—	690	2,168	4,043	—	1,977	6,020
Purchased Product	1,092	3	655	1,750	3,192	3	1,870	5,065
Transportation and Blending	3	(3)	—	—	3	(3)	—	—
Operating	134	—	38	172	438	—	96	534
Depreciation, Depletion and     Amortization	37	—	5	42	143	—	21	164
	212	—	(8)	204	267	—	(10)	257

U.S. Manufacturing Segment
Gross Sales	8,719	(14)	—	8,705	23,702	(14)	—	23,688
Purchased Product	7,944	(14)	—	7,930	20,365	(14)	—	20,351
	775	—	—	775	3,337	—	—	3,337

Retail Segment
Gross Sales	881	—	(881)	—	2,424	—	(2,424)	—
Purchased Product	846	—	(846)	—	2,317	—	(2,317)	—
Operating	38	—	(38)	—	96	—	(96)	—
Depreciation, Depletion and     Amortization	5	—	(5)	—	21	—	(21)	—
	(8)	—	8	—	(10)	—	10	—

Corporate and Eliminations Segment
Gross Sales	(2,619)	2	191	(2,426)	(6,162)	(57)	447	(5,772)
Purchased Product	(2,267)	65	191	(2,011)	(4,660)	173	447	(4,040)
Transportation and Blending	(119)	(128)	—	(247)	(528)	(383)	—	(911)
Operating	(256)	65	—	(191)	(918)	153	—	(765)
	23	—	—	23	(56)	—	—	(56)

Consolidated
Purchased Product	10,012	40	—	10,052	26,890	148	—	27,038
Transportation and Blending	2,684	(105)	—	2,579	8,707	(301)	—	8,406
Operating	1,439	65	—	1,504	4,207	153	—	4,360
	14,135	—	—	14,135	39,804	—	—	39,804

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Description of Business and Segmented Disclosures - Narrative (Detail)	9 Months Ended
	Sep. 30, 2023 plant
Canadian Manufacturing | Downstream
Disclosure of operating segments [line items]
Number of ethanol plants	2

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Description of Business and Segmented Disclosures - Schedule of Segment and Operational Information (Detail) - CAD ($) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2023		Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022		Sep. 30, 2023		Sep. 30, 2022
Revenues
Gross Sales	$ 15,712,000				$ 18,697,000		$ 41,438,000		$ 56,827,000
Less: Royalties	1,135,000				1,226,000		2,368,000		3,993,000
Revenue	14,577,000				17,471,000		39,070,000		52,834,000
Expenses
Purchased Product	6,620,000	[1]	$ 5,728,000	$ 5,809,000	10,052,000	[1]	18,157,000	[1]	27,038,000	[1]
Transportation and Blending	2,164,000	[1]	2,563,000	2,752,000	2,579,000	[1]	7,479,000	[1]	8,406,000	[1]
Operating	1,553,000	[1]	1,600,000	1,636,000	1,504,000	[1]	4,789,000	[1]	4,360,000	[1]
(Gain) Loss on Risk Management	72,000				(28,000)		89,000		1,540,000
Depreciation, Depletion and Amortization	1,197,000				1,047,000		3,374,000		3,209,000
Exploration Expense	2,000				73,000		10,000		99,000
(Income) Loss From Equity-Accounted Affiliates	(11,000)				(9,000)		(23,000)		(11,000)
Segment Income (Loss)	2,980,000				2,253,000		5,195,000		8,193,000
General and Administrative	292,000				128,000		617,000		545,000
Finance Costs	106,000				207,000		493,000		631,000
Interest Income	(33,000)				(21,000)		(100,000)		(44,000)
Integration and Transaction Costs	12,000				27,000		49,000		79,000
Foreign Exchange (Gain) Loss, Net	133,000				316,000		7,000		406,000
Revaluation (Gain) Loss	0				(549,000)		33,000		(549,000)
Re-measurement of Contingent Payments	67,000				(109,000)		83,000		142,000
(Gain) Loss on Divestiture of Assets	0				60,000		(11,000)		(244,000)
Other (Income) Loss, Net	(22,000)				(59,000)		(42,000)		(467,000)
Total Non-operating (Income) Expense	555,000				0		1,129,000		499,000
Earnings (Loss) Before Income Tax	2,425,000				2,253,000		4,066,000		7,694,000
Income Tax Expense (Recovery)	561,000				644,000		700,000		2,028,000
Net Earnings (Loss)	1,864,000				1,609,000		3,366,000		5,666,000
Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	0				(10,000)		1,000		1,628,000
Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	72,000				(18,000)		88,000		(88,000)
Upstream
Revenues
Gross Sales	8,783,000				10,250,000		23,285,000		32,891,000
Less: Royalties	1,135,000				1,226,000		2,368,000		3,993,000
Revenue	7,648,000				9,024,000		20,917,000		28,898,000
Expenses
Purchased Product	900,000				2,383,000		2,489,000		5,662,000
Transportation and Blending	2,397,000				2,826,000		8,194,000		9,317,000
Operating	914,000				915,000		2,826,000		2,834,000
Operating Margin	3,447,000				2,849,000		7,415,000		9,600,000
Depreciation, Depletion and Amortization	1,019,000				887,000		2,865,000		2,700,000
Exploration Expense	2,000				73,000		10,000		99,000
(Income) Loss From Equity-Accounted Affiliates	(11,000)				(9,000)		(23,000)		(11,000)
Segment Income (Loss)	2,383,000				1,892,000		4,533,000		6,864,000
Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	(10,000)				51,000		(7,000)		1,485,000
Upstream | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	54,000				6,000		30,000		(52,000)
Downstream
Revenues
Gross Sales	9,658,000				10,873,000		24,222,000		29,708,000
Less: Royalties	0				0		0		0
Revenue	9,658,000				10,873,000		24,222,000		29,708,000
Expenses
Purchased Product	7,947,000				9,680,000		20,385,000		25,416,000
Transportation and Blending	0				0		0		0
Operating	778,000				780,000		2,375,000		2,291,000
Operating Margin	922,000				490,000		1,456,000		1,881,000
Depreciation, Depletion and Amortization	159,000				133,000		450,000		423,000
Exploration Expense	0				0		0		0
(Income) Loss From Equity-Accounted Affiliates	0				0		0		0
Segment Income (Loss)	765,000				365,000		1,019,000		1,480,000
Downstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	11,000				(77,000)		6,000		120,000
Downstream | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	(2,000)				(8,000)		(13,000)		(22,000)
Oil Sands
Revenues
Gross Sales			6,437,000	5,707,000	8,764,000				28,030,000
Expenses
Purchased Product			414,000	355,000	1,919,000				4,202,000
Oil Sands | Upstream
Revenues
Gross Sales	7,571,000				8,764,000		19,715,000		28,030,000
Less: Royalties	1,082,000				1,136,000		2,218,000		3,709,000
Revenue	6,489,000				7,628,000		17,497,000		24,321,000
Expenses
Purchased Product	462,000				1,919,000		1,231,000		4,202,000
Transportation and Blending	2,324,000				2,758,000		7,965,000		9,114,000
Operating	688,000				689,000		2,101,000		2,197,000
Operating Margin	3,021,000				2,220,000		6,207,000		7,340,000
Depreciation, Depletion and Amortization	785,000				652,000		2,230,000		1,977,000
Exploration Expense	0				7,000		4,000		7,000
(Income) Loss From Equity-Accounted Affiliates	0				0		6,000		8,000
Segment Income (Loss)	2,189,000				1,563,000		3,923,000		5,407,000
Oil Sands | Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	(6,000)				42,000		(7,000)		1,468,000
Oil Sands | Upstream | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	47,000				(2,000)		44,000		(59,000)
Conventional
Revenues
Gross Sales			620,000	1,037,000	1,036,000				3,286,000
Expenses
Purchased Product			337,000	483,000
Transportation and Blending			66,000	81,000	64,000				191,000
Conventional | Upstream
Revenues
Gross Sales	810,000				1,036,000		2,467,000		3,286,000
Less: Royalties	27,000				68,000		85,000		228,000
Revenue	783,000				968,000		2,382,000		3,058,000
Expenses
Purchased Product	438,000				464,000		1,258,000		1,460,000
Transportation and Blending	73,000				64,000		220,000		191,000
Operating	150,000				141,000		444,000		403,000
Operating Margin	126,000				290,000		460,000		987,000
Depreciation, Depletion and Amortization	104,000				103,000		286,000		282,000
Exploration Expense	0				0		0		1,000
(Income) Loss From Equity-Accounted Affiliates	0				0		0		0
Segment Income (Loss)	15,000				179,000		188,000		697,000
Conventional | Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	(4,000)				9,000		0		17,000
Conventional | Upstream | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	7,000				8,000		(14,000)		7,000
Offshore | Upstream
Revenues
Gross Sales	402,000				450,000		1,103,000		1,575,000
Less: Royalties	26,000				22,000		65,000		56,000
Revenue	376,000				428,000		1,038,000		1,519,000
Expenses
Purchased Product	0				0		0		0
Transportation and Blending	0				4,000		9,000		12,000
Operating	76,000				85,000		281,000		234,000
Operating Margin	300,000				339,000		748,000		1,273,000
Depreciation, Depletion and Amortization	130,000				132,000		349,000		441,000
Exploration Expense	2,000				66,000		6,000		91,000
(Income) Loss From Equity-Accounted Affiliates	(11,000)				(9,000)		(29,000)		(19,000)
Segment Income (Loss)	179,000				150,000		422,000		760,000
Offshore | Upstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	0				0		0		0
Offshore | Upstream | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	0				0		0		0
Canadian Manufacturing
Revenues
Gross Sales					2,168,000				6,020,000
Expenses
Purchased Product					1,750,000				5,065,000
Transportation and Blending					0				0
Operating					172,000				534,000
Depreciation, Depletion and Amortization					42,000				164,000
Canadian Manufacturing | Downstream
Revenues
Gross Sales	1,805,000				2,168,000		4,676,000		6,020,000
Less: Royalties	0				0		0		0
Revenue	1,805,000				2,168,000		4,676,000		6,020,000
Expenses
Purchased Product	1,480,000				1,750,000		3,656,000		5,065,000
Transportation and Blending	0				0		0		0
Operating	155,000				172,000		471,000		534,000
Operating Margin	170,000				246,000		549,000		421,000
Depreciation, Depletion and Amortization	50,000				42,000		136,000		164,000
Exploration Expense	0				0		0		0
(Income) Loss From Equity-Accounted Affiliates	0				0		0		0
Segment Income (Loss)	120,000				204,000		413,000		257,000
Canadian Manufacturing | Downstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	0				0		0		0
Canadian Manufacturing | Downstream | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	0				0		0		0
U.S. Manufacturing
Revenues
Gross Sales			6,064,000	5,629,000	8,705,000				23,688,000
Expenses
Purchased Product			5,364,000	4,898,000	7,930,000				20,351,000
U.S. Manufacturing | Downstream
Revenues
Gross Sales	7,853,000				8,705,000		19,546,000		23,688,000
Less: Royalties	0				0		0		0
Revenue	7,853,000				8,705,000		19,546,000		23,688,000
Expenses
Purchased Product	6,467,000				7,930,000		16,729,000		20,351,000
Transportation and Blending	0				0		0		0
Operating	623,000				608,000		1,904,000		1,757,000
Operating Margin	752,000				244,000		907,000		1,460,000
Depreciation, Depletion and Amortization	109,000				91,000		314,000		259,000
Exploration Expense	0				0		0		0
(Income) Loss From Equity-Accounted Affiliates	0				0		0		0
Segment Income (Loss)	645,000				161,000		606,000		1,223,000
U.S. Manufacturing | Downstream | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	11,000				(77,000)		6,000		120,000
U.S. Manufacturing | Downstream | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	(2,000)				(8,000)		(13,000)		(22,000)
Corporate and Eliminations
Revenues
Gross Sales	(2,729,000)		(1,844,000)	(1,496,000)	(2,426,000)		(6,069,000)		(5,772,000)
Less: Royalties	0				0		0		0
Revenue	(2,729,000)				(2,426,000)		(6,069,000)		(5,772,000)
Expenses
Purchased Product	(2,227,000)		(1,470,000)	(1,020,000)	(2,011,000)		(4,717,000)		(4,040,000)
Transportation and Blending	(233,000)		(207,000)	(275,000)	(247,000)		(715,000)		(911,000)
Operating	(139,000)		$ (126,000)	$ (147,000)	(191,000)		(412,000)		(765,000)
Depreciation, Depletion and Amortization	19,000				27,000		59,000		86,000
Exploration Expense	0				0		0		0
(Income) Loss From Equity-Accounted Affiliates	0				0		0		0
Segment Income (Loss)	(168,000)				(4,000)		(357,000)		(151,000)
General and Administrative	292,000				128,000		617,000		545,000
Finance Costs	106,000				207,000		493,000		631,000
Interest Income	(33,000)				(21,000)		(100,000)		(44,000)
Integration and Transaction Costs	12,000				27,000		49,000		79,000
Foreign Exchange (Gain) Loss, Net	133,000				316,000		7,000		406,000
Revaluation (Gain) Loss	0				(549,000)		33,000		(549,000)
Re-measurement of Contingent Payments	67,000				(109,000)		83,000		142,000
(Gain) Loss on Divestiture of Assets	0				60,000		(11,000)		(244,000)
Other (Income) Loss, Net	(22,000)				(59,000)		(42,000)		(467,000)
Total Non-operating (Income) Expense	555,000				0		1,129,000		499,000
Corporate and Eliminations | Realized (Gain) Loss
Expenses
(Gain) Loss on Risk Management	(1,000)				16,000		2,000		23,000
Corporate and Eliminations | Unrealized (Gain) Loss on Risk Management
Expenses
(Gain) Loss on Risk Management	$ 20,000				$ (16,000)		$ 71,000		$ (14,000)

[1] Comparative periods reflect certain revisions. See Note 26

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Description of Business and Segmented Disclosures - Schedule of Revenues by Product (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Upstream
Revenue	$ 14,577	$ 17,471	$ 39,070	$ 52,834
U.S. Manufacturing
Consolidated	14,577	17,471	39,070	52,834
Corporate and Eliminations
Upstream
Revenue	(2,729)	(2,426)	(6,069)	(5,772)
U.S. Manufacturing
Corporate and Eliminations (2)	(2,729)	(2,426)	(6,069)	(5,772)
Consolidated	(2,729)	(2,426)	(6,069)	(5,772)
Upstream
Upstream
Crude Oil	6,666	7,384	17,671	24,143
Natural Gas (2)	563	973	1,975	2,740
NGLs	382	571	1,088	1,684
Other	37	96	183	331
Revenue	7,648	9,024	20,917	28,898
Canadian Manufacturing
Synthetic Crude Oil	6,666	7,384	17,671	24,143
U.S. Manufacturing
Consolidated	7,648	9,024	20,917	28,898
Downstream
Upstream
Revenue	9,658	10,873	24,222	29,708
U.S. Manufacturing
Consolidated	9,658	10,873	24,222	29,708
Downstream | Canadian Manufacturing
Upstream
Crude Oil	657	657	1,607	1,786
Canadian Manufacturing
Synthetic Crude Oil	657	657	1,607	1,786
Diesel	460	567	1,286	1,544
Gasoline	162	298	410	837
Asphalt	200	248	431	482
Other Products and Services	326	398	942	1,371
U.S. Manufacturing
Gasoline	162	298	410	837
Distillates	460	567	1,286	1,544
Asphalt	200	248	431	482
Other Products (2)	326	398	942	1,371
Downstream | U.S. Manufacturing
Canadian Manufacturing
Diesel	2,871	3,384	7,169	8,535
Gasoline	3,822	3,919	9,336	11,180
Asphalt	326	196	610	402
Other Products and Services	834	1,206	2,431	3,571
U.S. Manufacturing
Gasoline	3,822	3,919	9,336	11,180
Distillates	2,871	3,384	7,169	8,535
Asphalt	326	196	610	402
Other Products (2)	$ 834	$ 1,206	$ 2,431	$ 3,571

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Description of Business and Segmented Disclosures - Schedule of Geographical Information (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Disclosure of geographical areas [line items]
Revenue	$ 14,577	$ 17,471	$ 39,070	$ 52,834
Non-Current Assets	42,655		42,655		$ 42,447
Current assets	10,745		10,745		12,430
Canada
Disclosure of geographical areas [line items]
Revenue	6,666	7,999	18,828	26,471
Non-Current Assets	35,257		35,257		35,194
United States
Disclosure of geographical areas [line items]
Revenue	7,611	9,155	19,425	25,340
Non-Current Assets	5,284		5,284		4,824
China
Disclosure of geographical areas [line items]
Revenue	300	$ 317	817	$ 1,023
Non-Current Assets	1,758		1,758		2,064
Indonesia
Disclosure of geographical areas [line items]
Non-Current Assets	$ 356		$ 356		$ 365

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Description of Business and Segmented Disclosures - Schedule of Assets by Segment (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Disclosure Of Reportable Segments [Line Items]
Intangible exploration and evaluation assets	$ 796	$ 685
Property, plant and equipment	36,727	36,499
Right-of-use assets	1,738	1,845
Goodwill	2,923	2,923
Assets	54,427	55,869
Current assets	10,745	12,430
Oil Sands
Disclosure Of Reportable Segments [Line Items]
Intangible exploration and evaluation assets	785	674
Property, plant and equipment	24,271	24,657
Right-of-use assets	687	638
Goodwill	2,923	2,923
Assets	32,481	32,248
Conventional
Disclosure Of Reportable Segments [Line Items]
Intangible exploration and evaluation assets	5	6
Property, plant and equipment	2,045	2,020
Right-of-use assets	2	2
Goodwill	0	0
Assets	2,278	2,410
Offshore
Disclosure Of Reportable Segments [Line Items]
Intangible exploration and evaluation assets	6	5
Property, plant and equipment	2,679	2,549
Right-of-use assets	103	152
Goodwill	0	0
Assets	3,416	3,339
Canadian Manufacturing
Disclosure Of Reportable Segments [Line Items]
Intangible exploration and evaluation assets	0	0
Property, plant and equipment	2,438	2,466
Right-of-use assets	220	252
Goodwill	0	0
Assets	3,320	3,172
U.S. Manufacturing
Disclosure Of Reportable Segments [Line Items]
Intangible exploration and evaluation assets	0	0
Property, plant and equipment	4,981	4,482
Right-of-use assets	286	329
Goodwill	0	0
Assets	9,728	8,324
Corporate and Eliminations
Disclosure Of Reportable Segments [Line Items]
Intangible exploration and evaluation assets	0	0
Property, plant and equipment	313	325
Right-of-use assets	440	472
Goodwill	0	0
Assets	$ 3,204	$ 6,376

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Description of Business and Segmented Disclosures - Schedule of Capital Expenditures (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disclosure Of Reportable Segments [Line Items]
Capital Investment	$ 1,025	$ 866	$ 3,128	$ 2,434
Acquisitions	33	1,601	377	1,602
Total Capital Expenditures	1,058	2,467	3,505	4,036
BP Products North America, Toledo
Disclosure Of Reportable Segments [Line Items]
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo	320		320
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo	320		320
Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	884	508	2,565	1,524
Downstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	126	324	534	851
Oil Sands
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 3)	32	1,596	35	1,596
Oil Sands | Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	590	360	1,764	1,111
Conventional
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 3)	1	5	5	6
Conventional | Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	100	67	323	188
Offshore | Asia Pacific | Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	3	3	4	5
Offshore | Atlantic Region | Upstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	191	78	474	220
Canadian Manufacturing | Downstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	38	24	99	77
U.S. Manufacturing
Disclosure Of Reportable Segments [Line Items]
Acquisitions (Note 3)	0	0	337	0
U.S. Manufacturing | Downstream
Disclosure Of Reportable Segments [Line Items]
Capital Investment	88	300	435	774
Corporate and Eliminations
Disclosure Of Reportable Segments [Line Items]
Capital Investment	$ 15	$ 34	$ 29	$ 59

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Acquisitions - Narrative (Details) $ in Millions, $ in Millions				3 Months Ended		7 Months Ended	9 Months Ended
	Feb. 28, 2023 CAD ($)	Aug. 31, 2022	Feb. 28, 2022 CAD ($)	Sep. 30, 2023 CAD ($)	Sep. 30, 2022 CAD ($)	Sep. 30, 2023 CAD ($)	Sep. 30, 2023 CAD ($)	Sep. 30, 2022 CAD ($)	Feb. 28, 2023 USD ($)
BP-Husky Refining LLC
Disclosure of detailed information about business combination [line items]
Agreement to purchase remaining ownership	50.00%
Total Purchase Consideration	$ 502								$ 369
Accounts Receivable and Accrued Revenues	3
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo	494
Carrying value of investment in joint ventures recognised​ as of​ acquisition​ date	539
Non-cash revaluation loss, before tax	33
Non-cash revaluation loss, after tax			$ 22
Non-cash revaluation loss, cumulative foreign exchange	$ 12
Integration costs				$ 10	$ 0		$ 38	$ 0
Transaction Costs				$ 2	$ 2		11	$ 2
Revenue of acquiree since acquisition date						$ 2,400
Profit (loss) of acquiree since acquisition date						$ (84)
Revenue of combined entity as if combination occurred at beginning of period							39,100
Profit (loss) of combined entity as if combination occurred at beginning of period							$ 3,300
Sunrise Oil Sands Partnership
Disclosure of detailed information about business combination [line items]
Agreement to purchase remaining ownership		50.00%

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Acquisitions - BP-Husky, Summary of Consideration (Details) - BP-Husky Refining LLC $ in Millions	Feb. 28, 2023 CAD ($)
Disclosure of detailed information about business combination [line items]
Cash	$ 69
Accounts Receivable and Accrued Revenues	3
Inventories	453
Property, Plant and Equipment	674
Right-of-Use Assets	33
Other Assets	10
Accounts Payable and Accrued Liabilities	(138)
Lease Liabilities	(33)
Decommissioning Liabilities	(5)
Other Liabilities	(70)
Total Identifiable Net Assets	$ 996

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Acquisitions - BP-Husky, Summary of Goodwill (Details) $ in Millions, $ in Millions	Sep. 30, 2023 CAD ($)	Feb. 28, 2023 CAD ($)	Feb. 28, 2023 USD ($)	Dec. 31, 2022 CAD ($)
Disclosure of detailed information about business combination [line items]
Goodwill	$ 2,923			$ 2,923
BP-Husky Refining LLC
Disclosure of detailed information about business combination [line items]
Total Purchase Consideration		$ 502	$ 369
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo		494
Fair Value of Identifiable Net Assets		(996)
Goodwill		$ 0

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Finance Costs - Schedule of Finance Costs (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Finance Costs [Abstract]
Interest Expense – Short-Term Borrowings and Long-Term Debt	$ 94	$ 121	$ 285	$ 381
Net Premium (Discount) on Redemption of Long-Term Debt	(84)	(4)	(84)	(29)
Interest Expense - Lease Liabilities	41	40	121	123
Unwinding of Discount on Decommissioning Liabilities	55	43	165	132
Other	5	9	18	27
Total finance costs	111	209	505	634
Capitalized Interest	(5)	(2)	(12)	(3)
Finance Costs	$ 106	$ 207	$ 493	$ 631

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Foreign Exchange (Gain) Loss, Net - Schedule of Foreign Exchange Gain Loss Net (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items]
Unrealized Foreign Exchange (Gain) Loss	$ 59	$ 298	$ (99)	$ 419
Realized Foreign Exchange (Gain) Loss	74	18	106	(13)
Total	133	316	7	406
U.S. Dollar Debt Issued From Canada
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items]
Unrealized Foreign Exchange (Gain) Loss	28	324	(119)	444
Other
Disclosure Of Effect Of Changes In Foreign Exchange Rates Gain Loss [Line Items]
Unrealized Foreign Exchange (Gain) Loss	$ 31	$ (26)	$ 20	$ (25)

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Income Taxes - Provision for Income Taxes (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	$ 563	$ 76	$ 1,116	$ 1,403
Deferred Tax Expense (Recovery)	(2)	568	(416)	625
Tax Expense (Recovery) From Continuing Operations	561	644	700	2,028
BP-Husky Refining LLC
Major Components Of Tax Expense Income [Line Items]
Deferred Tax Expense (Recovery)			(176)
Canada
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	484	187	941	1,124
United States
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	4	(185)	4	96
Asia Pacific
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	68	64	152	173
Other International
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	$ 7	$ 10	$ 19	$ 10

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Per Share Amounts - Schedule Representing Per Share Amounts (Detail) - CAD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Earnings per share [line items]
Net Earnings (Loss)	$ 1,864,000	$ 1,609,000	$ 3,366,000	$ 5,666,000
Effect of Cumulative Dividends on Preferred Shares	(9,000)	(9,000)	(27,000)	(26,000)
Net Earnings (Loss) – Basic and Diluted	$ 1,855,000	$ 1,600,000	$ 3,339,000	$ 5,640,000
Basic – weighted average number of shares (in shares)	1,891,937	1,927,864	1,900,952	1,962,813
Dilutive effect of warrants (in shares)	6,408	41,956	27,491	45,002
Dilutive effect of net settlement rights (in shares)	6,752	7,188	7,643	10,657
Diluted – weighted average number of shares (in shares)	1,905,097	1,978,645	1,936,716	2,018,472
Net earnings (loss) per share — basic (CAD per share)	$ 0.98	$ 0.83	$ 1.76	$ 2.87
Net earnings (loss) per share — diluted (CAD per share)	$ 0.97	$ 0.81	$ 1.72	$ 2.79
Cenovus Replacement Stock Options
Earnings per share [line items]
Dilutive effect of options (in shares)	0	1,637	630	0

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Per Share Amounts - Additional Information (Detail) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
	Nov. 01, 2023	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disclosure of non-adjusting events after reporting period [line items]
Total dividends paid on preferred shares		$ 9	$ 9	$ 27	$ 26
Stock Options With Associated Net Settlement Rights
Disclosure of non-adjusting events after reporting period [line items]
Instruments excluded from calculation, shares (in shares)		1.5	2.0	1.5	2.0
Common shares
Disclosure of non-adjusting events after reporting period [line items]
Instruments excluded from calculation		$ 6			$ 35
Instruments excluded from calculation, shares (in shares)		0.6			1.6
Variable dividends declared ( in CAD per share)				$ 0	$ 0
Preference shares
Disclosure of non-adjusting events after reporting period [line items]
Total dividends paid on preferred shares		$ 0	$ 9	$ 27	$ 26
Potential ordinary share transactions | Common shares
Disclosure of non-adjusting events after reporting period [line items]
Dividends declared (in CAD per share)	$ 0.140
Potential ordinary share transactions | Preference shares
Disclosure of non-adjusting events after reporting period [line items]
Dividends declared	$ 9

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Per Share Amounts - Common Share Dividends (Details) - Common shares - CAD ($) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Earnings per share [line items]
Dividends paid (in CAD per share)	$ 0.385	$ 0.245
Dividends paid on common shares	$ 729	$ 481
Variable dividends declared ( in CAD per share)	$ 0	$ 0
Variable dividends paid on common shares	$ 0	$ 0
Total common share dividends paid (in CAD per share)	$ 0.385	$ 0.245
Total dividends paid on common shares	$ 729	$ 481

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Per Share Amounts - Preferred Share Dividends (Details) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Earnings per share [line items]
Total Preferred Share Dividends Declared	$ 9	$ 9	$ 27	$ 26
Series 1 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	2	1	5	5
Series 2 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	1	1	2	1
Series 3 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	3	3	9	9
Series 5 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	2	3	7	7
Series 7 First Preferred Shares
Earnings per share [line items]
Total Preferred Share Dividends Declared	$ 1	$ 1	$ 4	$ 4

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Exploration and Evaluation Assets, Net - Summary of Exploration and Valuation Assets, Net (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($)
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	$ 685
Ending Balance	796
E&E Assets
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	685
Acquisitions	31
Additions	80
Ending Balance	$ 796

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Property, Plant and Equipment, Net - Summary of Property, Plant and Equipment (Detail) - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Feb. 28, 2023
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	$ 36,499
Ending balance	36,727
Property, Plant and Equipment, Net	36,727
Oil Sands
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	24,657
Ending balance	24,271
Property, Plant and Equipment, Net	24,271
Write-downs (reversals of write-downs) of property, plant and equipment	20
Canadian Manufacturing
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	2,466
Ending balance	2,438
Property, Plant and Equipment, Net	2,438
Write-downs (reversals of write-downs) of property, plant and equipment	8
BP-Husky Refining LLC
Disclosure of detailed information about property, plant and equipment [line items]
Property, Plant and Equipment, Net		$ 334
COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	57,739
Acquisitions	683
Additions	3,048
Change in Decommissioning Liabilities	44
Divestitures	667
Exchange Rate Movements and Other	(61)
Ending balance	60,786
Property, Plant and Equipment, Net	60,786
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	(21,240)
Divestitures	(319)
Exchange Rate Movements and Other	(12)
Depreciation, depletion and amortization	3,150
Ending balance	(24,059)
Property, Plant and Equipment, Net	(24,059)
Crude Oil and Natural Gas Properties
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	29,226
Ending balance	28,995
Property, Plant and Equipment, Net	28,995
Crude Oil and Natural Gas Properties | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	43,528
Acquisitions	9
Additions	2,485
Change in Decommissioning Liabilities	42
Divestitures	17
Exchange Rate Movements and Other	(19)
Ending balance	46,028
Property, Plant and Equipment, Net	46,028
Crude Oil and Natural Gas Properties | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	(14,302)
Divestitures	(8)
Exchange Rate Movements and Other	13
Depreciation, depletion and amortization	2,726
Ending balance	(17,033)
Property, Plant and Equipment, Net	(17,033)
Processing, Transportation and Storage Assets
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	148
Ending balance	152
Property, Plant and Equipment, Net	152
Processing, Transportation and Storage Assets | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	254
Acquisitions	0
Additions	19
Change in Decommissioning Liabilities	0
Divestitures	0
Exchange Rate Movements and Other	5
Ending balance	278
Property, Plant and Equipment, Net	278
Processing, Transportation and Storage Assets | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	(106)
Divestitures	0
Exchange Rate Movements and Other	4
Depreciation, depletion and amortization	16
Ending balance	(126)
Property, Plant and Equipment, Net	(126)
Manufacturing Assets
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	6,585
Ending balance	7,053
Property, Plant and Equipment, Net	7,053
Manufacturing Assets | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	12,132
Acquisitions	674
Additions	508
Change in Decommissioning Liabilities	2
Divestitures	633
Exchange Rate Movements and Other	(39)
Ending balance	12,644
Property, Plant and Equipment, Net	12,644
Manufacturing Assets | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	(5,547)
Divestitures	(299)
Exchange Rate Movements and Other	(23)
Depreciation, depletion and amortization	366
Ending balance	(5,591)
Property, Plant and Equipment, Net	(5,591)
Retail and Other Assets
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	540
Ending balance	527
Property, Plant and Equipment, Net	527
Retail and Other Assets | COST
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	1,825
Acquisitions	0
Additions	36
Change in Decommissioning Liabilities	0
Divestitures	17
Exchange Rate Movements and Other	(8)
Ending balance	1,836
Property, Plant and Equipment, Net	1,836
Retail and Other Assets | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Disclosure of detailed information about property, plant and equipment [line items]
Beginning balance	(1,285)
Divestitures	(12)
Exchange Rate Movements and Other	(6)
Depreciation, depletion and amortization	42
Ending balance	(1,309)
Property, Plant and Equipment, Net	$ (1,309)

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Right of Use Assets, Net - Summary of Right of Use Assets, Net (Detail) - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Feb. 28, 2023
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	$ 1,845
Balance at end of period	1,738
Right-of-Use Assets, Net	1,738
BP-Husky Refining LLC
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-Use Assets, Net		$ 7
COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	2,687
Acquisitions	33
Additions	45
Modifications	34
Re-measurements	(6)
Divestitures	(19)
Terminations	(6)
Exchange Rate Movements and Other	23
Balance at end of period	2,791
Right-of-Use Assets, Net	2,791
ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	842
Divestitures	(12)
Terminations	(3)
Depreciation	224
Exchange Rate Movements and Other	2
Balance at end of period	1,053
Real Estate
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	472
Balance at end of period	440
Right-of-Use Assets, Net	440
Real Estate | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	599
Acquisitions	1
Additions	1
Modifications	(4)
Re-measurements	0
Divestitures	0
Terminations	(3)
Exchange Rate Movements and Other	(4)
Balance at end of period	590
Right-of-Use Assets, Net	590
Real Estate | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	127
Divestitures	0
Terminations	(1)
Depreciation	27
Exchange Rate Movements and Other	(3)
Balance at end of period	150
Transportation And Storage Assets
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	1,195
Balance at end of period	1,135
Right-of-Use Assets, Net	1,135
Transportation And Storage Assets | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	1,840
Acquisitions	24
Additions	44
Modifications	37
Re-measurements	(11)
Divestitures	0
Terminations	(1)
Exchange Rate Movements and Other	24
Balance at end of period	1,957
Right-of-Use Assets, Net	1,957
Transportation And Storage Assets | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	645
Divestitures	0
Terminations	(1)
Depreciation	170
Exchange Rate Movements and Other	8
Balance at end of period	822
Manufacturing Assets
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	116
Balance at end of period	103
Right-of-Use Assets, Net	103
Manufacturing Assets | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	174
Acquisitions	8
Additions	0
Modifications	1
Re-measurements	0
Divestitures	(19)
Terminations	0
Exchange Rate Movements and Other	0
Balance at end of period	164
Right-of-Use Assets, Net	164
Manufacturing Assets | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	58
Divestitures	(12)
Terminations	0
Depreciation	17
Exchange Rate Movements and Other	(2)
Balance at end of period	61
Other Assets
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	62
Balance at end of period	60
Right-of-Use Assets, Net	60
Other Assets | COST
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	74
Acquisitions	0
Additions	0
Modifications	0
Re-measurements	5
Divestitures	0
Terminations	(2)
Exchange Rate Movements and Other	3
Balance at end of period	80
Right-of-Use Assets, Net	80
Other Assets | ACCUMULATED DEPRECIATION
Disclosure of quantitative information about right-of-use assets [line items]
Balance at beginning of period	12
Divestitures	0
Terminations	(1)
Depreciation	10
Exchange Rate Movements and Other	(1)
Balance at end of period	$ 20

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Joint Arrangements - Joint Operations (Details) - WRB Refining LP	9 Months Ended
	Sep. 30, 2023
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Phillips 66
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%

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Joint Arrangements - Husky - CNOOC Madura Ltd (Details) - CAD ($) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2023		Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022		Sep. 30, 2023		Sep. 30, 2022		Dec. 31, 2022	Jun. 30, 2022	Dec. 31, 2021
Results of Operations
Revenue	$ 14,577,000				$ 17,471,000		$ 39,070,000		$ 52,834,000
Operating	1,553,000	[1]	$ 1,600,000	$ 1,636,000	1,504,000	[1]	4,789,000	[1]	4,360,000	[1]
Net Earnings (Loss)	1,864,000				1,609,000		3,366,000		5,666,000
Balance Sheets
Current assets	10,745,000						10,745,000				$ 12,430,000
Current Liabilities	7,205,000						7,205,000				8,021,000
Cash and Cash Equivalents	1,262,000		$ 2,167,000		3,494,000		1,262,000		3,494,000		4,524,000	$ 3,693,000	$ 2,873,000
Shareholders’ Equity	28,814,000				$ 27,762,000		$ 28,814,000		27,762,000		27,576,000		$ 23,596,000
Husky-CNOOC Madura Ltd.
Disclosure of joint ventures [line items]
Share of equity investment							40.00%
Results of Operations
Revenue							$ 439,000		256,000
Operating							373,000		247,000
Net Earnings (Loss)							66,000		9,000
Balance Sheets
Current assets	285,000						285,000				247,000
Non-Current Assets	1,767,000						1,767,000				1,926,000
Current Liabilities	127,000						127,000				160,000
Non-Current Liabilities	1,114,000						1,114,000				1,293,000
Net Assets	811,000						811,000				720,000
Cash and Cash Equivalents	76,000						76,000				64,000
Shareholders’ Equity	29,000						29,000				19,000
Investments in Equity-Accounted Affiliates	$ 356,000						356,000				$ 365,000
Distributions received							61,000		32,000
Joint venture, contributions							$ 31,000		$ 41,000

[1] Comparative periods reflect certain revisions. See Note 26

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Joint Arrangements - Husky Midstream Limited Partnership (Details) - CAD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Disclosure of joint ventures [line items]
Net Earnings (Loss)	$ 1,864,000	$ 1,609,000	$ 3,366,000	$ 5,666,000
Husky Midstream Limited Partnership
Disclosure of joint ventures [line items]
Share of equity investment			35.00%
Net Earnings (Loss)			$ 118,000	112,000
Unrecognised share of pre-tax net losses of joint ventures			20,000	14,000
Investments in Equity-Accounted Affiliates	$ 0		0		$ 0
Unrecognised share of losses of joint ventures			42,000		$ 28,000
Dividends received			56,000	22,000
Joint venture, contributions			$ 62,000	$ 30,000
Husky Midstream Limited Partnership | Power Assets Holding Ltd.
Disclosure of joint ventures [line items]
Share of equity investment			49.00%
Husky Midstream Limited Partnership | Cheung Kong Infrastructure Holdings Ltd.
Disclosure of joint ventures [line items]
Share of equity investment			16.00%

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Other Assets - Schedule of Other Assets (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Other Noncurrent Assets [Abstract]
Long-Term Receivables and Prepaids	$ 48	$ 120
Precious Metals	79	86
Net Investment in Finance Leases	62	62
Private Equity Investments (Note 22)	66	55
Intangible Assets	11	19
Other assets	$ 266	$ 342

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Debt and Capital Structure - Schedule of Short-Term Borrowings (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Disclosure of detailed information about borrowings [line items]
Short-Term Borrowings	$ 14	$ 115
Uncommitted Demand Facility
Disclosure of detailed information about borrowings [line items]
Short-Term Borrowings	0	0
WRB Refining LP
Disclosure of detailed information about borrowings [line items]
Short-Term Borrowings	$ 14	$ 115

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Debt and Capital Structure - Additional Information (Detail) $ in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($) $ / bbl	Sep. 30, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	$ 353		$ 490
Current borrowings	$ 14		115
Maximum debt to capitalization ratio	65.00%	65.00%
Target net debt	$ 4,000
Average crude oil price | $ / bbl	45.00
Committed Credit Facilities, Maturing November 10, 2025
Disclosure of detailed information about borrowings [line items]
Credit facilities, maximum borrowing capacity	$ 1,800
Committed Credit Facilities, Maturing November 10, 2026
Disclosure of detailed information about borrowings [line items]
Credit facilities, maximum borrowing capacity	3,700
Committed credit facilities
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing facilities, outstanding	0		0
Uncommitted Demand Facility
Disclosure of detailed information about borrowings [line items]
Current borrowings	0		0
WRB Refining LP
Disclosure of detailed information about borrowings [line items]
Current borrowings	$ 14		115
Proportion of ownership interest in joint operation	50.00%
Undrawn borrowing facilities, outstanding		$ 20
WRB Refining LP | Cenovus Energy Inc
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing facilities, outstanding	$ 14	10	115	$ 85
Maximum
Disclosure of detailed information about borrowings [line items]
Credit facilities, maximum borrowing capacity	1,700		$ 1,900
Maximum | Maximum
Disclosure of detailed information about borrowings [line items]
Amount of undrawn facilities for general purposes	$ 1,400
Maximum | WRB Refining LP
Disclosure of detailed information about borrowings [line items]
Credit facilities, maximum borrowing capacity		$ 450
Maximum | WRB Refining LP | Cenovus Energy Inc
Disclosure of detailed information about borrowings [line items]
Credit facilities, maximum borrowing capacity				$ 225

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Debt and Capital Structure - Schedule of Long-Term Debt (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Disclosure of detailed information about borrowings [line items]
Net Debt Premiums (Discounts) and Transaction Costs	$ 84	$ 154
Long-Term Debt	7,224	8,691
Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	7,140	8,537
Long-Term Debt | Revolving Term Debt
Disclosure of detailed information about borrowings [line items]
Revolving Term Debt	0	0
Long-Term Debt | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	5,140	6,537
Long-Term Debt | Canadian Dollar Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)	$ 2,000	$ 2,000

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Debt and Capital Structure - Schedule Of Unsecured Notes (Details) - U.S. Dollar Denominated Unsecured Notes $ in Millions	Sep. 30, 2023 CAD ($)
Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 1,025
4.40% due April 15, 2029
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 57
4.40% due April 15, 2029 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.40%
5.25% due June 15, 2037
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 250
5.25% due June 15, 2037 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.25%
6.80% due September 15, 2037
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 196
6.80% due September 15, 2037 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	6.80%
6.75% due November 15, 2039
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 283
6.75% due November 15, 2039 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	6.75%
4.45% due September 15, 2042
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 6
4.45% due September 15, 2042 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.45%
5.20% due September 15, 2043
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 2
5.20% due September 15, 2043 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.20%
5.40% due June 15, 2047
Disclosure of detailed information about borrowings [line items]
Repayment of principal	$ 231
5.40% due June 15, 2047 | Long-Term Debt
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.40%

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Debt and Capital Structure - Schedule Remaining Principal Amounts of Unsecured Notes (Details) - Long-Term Debt $ in Millions, $ in Millions	Sep. 30, 2023 USD ($)	Sep. 30, 2023 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)
Disclosure of detailed information about borrowings [line items]
Total debt principal		$ 7,140		$ 8,537
Canadian Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total debt principal		2,000		2,000
Unsecured Notes | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Total debt principal	$ 3,802	$ 5,140	$ 4,827	6,537
5.38% due July 15, 2025 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.38%	5.38%
Total debt principal	$ 133	$ 181	133	181
4.25% due April 15, 2027 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.25%	4.25%
Total debt principal	$ 373	$ 505	373	505
4.40% due April 15, 2029 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.40%	4.40%
Total debt principal	$ 183	$ 247	240	324
2.65% due January 15, 2032 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	2.65%	2.65%
Total debt principal	$ 500	$ 676	500	677
5.25% due June 15, 2037 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.25%	5.25%
Total debt principal	$ 333	$ 450	583	790
6.80% due September 15, 2037 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	6.80%	6.80%
Total debt principal	$ 191	$ 259	387	524
6.75% due November 15, 2039 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	6.75%	6.75%
Total debt principal	$ 652	$ 881	935	1,267
4.45% due September 15, 2042 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	4.45%	4.45%
Total debt principal	$ 91	$ 123	97	131
5.20% due September 15, 2043 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.20%	5.20%
Total debt principal	$ 27	$ 36	29	39
5.40% due June 15, 2047 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	5.40%	5.40%
Total debt principal	$ 569	$ 768	800	1,083
3.75% due February 15, 2052 | U.S. Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.75%	3.75%
Total debt principal	$ 750	$ 1,014	$ 750	1,016
3.60% due March 10, 2027 | Canadian Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.60%	3.60%
Total debt principal		$ 750		750
3.50% due February 7, 2028 | Canadian Dollar Denominated Unsecured Notes
Disclosure of detailed information about borrowings [line items]
Long-term debt, interest rate	3.50%	3.50%
Total debt principal		$ 1,250		$ 1,250

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Debt and Capital Structure - Summary of Net Debt to Adjusted EBITDA (Detail) - CAD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Dec. 31, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2021
Disclosure of objectives, policies and processes for managing capital [line items]
Short-Term Borrowings	$ 14,000		$ 14,000		$ 14,000	$ 115,000
Long-Term Debt	7,224,000		7,224,000		7,224,000	8,691,000
Total Debt	7,224,000		7,224,000		7,224,000	8,691,000
Less: Cash and Cash Equivalents	(1,262,000)	$ (3,494,000)	(1,262,000)	$ (3,494,000)	(1,262,000)	(4,524,000)	$ (2,167,000)	$ (3,693,000)	$ (2,873,000)
Net Debt	5,976,000		5,976,000		$ 5,976,000	$ 4,282,000
Net Earnings (Loss)	1,864,000	1,609,000	3,366,000	5,666,000
Add (Deduct):
Interest Income	(33,000)	(21,000)	(100,000)	(44,000)
Foreign Exchange (Gain) Loss, Net	133,000	316,000	7,000	406,000
Revaluation (Gain) Loss	0	(549,000)	33,000	(549,000)
Re-measurement of Contingent Payments	67,000	(109,000)	83,000	142,000
(Gain) Loss on Divestiture of Assets	0	60,000	(11,000)	(244,000)
Other (Income) Loss, Net	(22,000)	$ (59,000)	(42,000)	$ (467,000)
Net Debt to Adjusted EBITDA					60.00%	30.00%
Rolling Twelve Month Basis
Disclosure of objectives, policies and processes for managing capital [line items]
Short-Term Borrowings	14,000		14,000		$ 14,000	$ 115,000
Current Portion of Long-Term Debt	0		0		0	0
Long-Term Debt	7,224,000		7,224,000		7,224,000	8,691,000
Total Debt	7,238,000		7,238,000		7,238,000	8,806,000
Less: Cash and Cash Equivalents	(1,262,000)		(1,262,000)		(1,262,000)	(4,524,000)
Net Debt	$ 5,976,000		$ 5,976,000		5,976,000	4,282,000
Net Earnings (Loss)					4,150,000	6,450,000
Add (Deduct):
Finance Costs					682,000	820,000
Interest Income					(137,000)	(81,000)
Income Tax Expense (Recovery)					953,000	2,281,000
Depreciation, Depletion and Amortization					4,844,000	4,679,000
Exploration and Evaluation Asset Write-downs					1,000	64,000
(Income) Loss From Equity-Accounted Affiliates					(27,000)	(15,000)
Unrealized (Gain) Loss on Risk Management					50,000	(126,000)
Foreign Exchange (Gain) Loss, Net					(56,000)	343,000
Revaluation (Gain) Loss					33,000	(549,000)
Re-measurement of Contingent Payments					103,000	162,000
(Gain) Loss on Divestiture of Assets					(36,000)	(269,000)
Other (Income) Loss, Net					(107,000)	(532,000)
Adjusted EBITDA					$ 10,453,000	$ 13,227,000

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Debt and Capital Structure - Schedule of Net Debt to Adjusted Funds Flow (Details) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Dec. 31, 2022
Borrowings [abstract]
Net Debt	$ 5,976		$ 5,976		$ 5,976	$ 4,282
Cash From (Used in) Operating Activities	2,738	$ 4,089	4,442	$ 8,433	7,412	11,403
Settlement of Decommissioning Liabilities	(68)	(55)	(157)	(101)	(206)	(150)
Net Change in Non-Cash Working Capital	$ (641)	$ 1,193	$ (2,142)	$ (98)	(1,469)	575
Adjusted funds flow					$ 9,087	$ 10,978
Net Debt to Adjusted Funds Flow					70.00%	40.00%

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Debt and Capital Structure - Summary of Net Debt to Capitalization (Detail) - CAD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2023	Dec. 31, 2022	Sep. 30, 2022	Dec. 31, 2021
Borrowings [abstract]
Net Debt	$ 5,976	$ 4,282
Shareholders’ Equity	28,814	27,576	$ 27,762	$ 23,596
Capitalization	$ 34,790	$ 31,858
Net Debt to Capitalization	17.00%	13.00%

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Lease Liabilities - Summary of Lease Liabilities (Details) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Feb. 28, 2023	Dec. 31, 2022
Disclosure of quantitative information about right-of-use assets [line items]
Beginning balance, lease liabilities			$ 2,836
Acquisition			33
Additions			45
Interest Expense (Note 4)	$ 41	$ 40	121	$ 123
Lease Payments			(337)
Modifications			34
Re-measurements			(6)
Divestitures			11
Terminations			(8)
Exchange Rate Movements and Other			26
Ending Balance, lease liabilities	2,733		2,733
Less: Current Portion	315		315			$ 308
Long-Term Portion	2,418		2,418			2,528
Lease liabilities	$ 2,733		$ 2,733			$ 2,836
BP-Husky Refining LLC
Disclosure of quantitative information about right-of-use assets [line items]
Lease liabilities					$ 11

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Contingent Payments - Summary of Contingent Payments (Detail) - Sunrise Oil Sands Partnership $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($)
Disclosure of contingent liabilities in business combination [line items]
Contingent payments. beginning of period	$ 419
Liabilities Settled or Payable	(207)
Re-measurement	83
Contingent payments, end of period	$ 295

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Contingent Payments - Additional Information (Detail) - Sunrise Oil Sands Partnership $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($)	Aug. 31, 2022 CAD ($) $ / bbl
Disclosure of contingent liabilities in business combination [line items]
Contingent consideration maximum payment	$ 301.0	$ 600.0
Contingent consideration, price per barrel (in dollars per barrel) | $ / bbl		52.00
Contingent consideration, quarterly payment		$ 2.8
Liabilities Settled or Payable	207.0
Major business combination
Disclosure of contingent liabilities in business combination [line items]
Liabilities Settled or Payable	$ 207.0
Maximum
Disclosure of contingent liabilities in business combination [line items]
Contingent consideration, price per barrel (in dollars per barrel) | $ / bbl		53.00

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Decommissioning Liabilities - Summary of Decommissioning Provision (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($)
Provision for decommissioning, restoration and rehabilitation costs [abstract]
Beginning balance	$ 3,559
Liabilities Incurred	12
Liabilities acquired	5
Liabilities Settled	(156)
Liabilities disposed	(5)
Change in Estimated Future Cash Flows	32
Unwinding of Discount on Decommissioning Liabilities (Note 4)	165
Exchange Rate Movements	(9)
Ending balance	$ 3,603

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Decommissioning Liabilities - Additional Information (Detail) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Feb. 28, 2023 CAD ($)
Disclosure of other provisions [line items]
Credit-adjusted risk-free rate	6.10%	6.10%
Inflation rate	0.02	0.02
Restricted Cash	$ 209	$ 209
BP-Husky Refining LLC
Disclosure of other provisions [line items]
Carrying value of pre-existing decommissioning liabilities			$ 2

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Other Liabilities - Summary of Other Liabilities (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Miscellaneous non-current liabilities [abstract]
Renewable volume obligation, net	$ 400	$ 101
Pension and Other Post-Employment Benefit Plan	191	201
Provision for West White Rose Expansion Project	169	204
Provisions for Onerous and Unfavourable Contracts	76	95
Employee Long-Term Incentives	127	245
Drilling Provisions	25	31
Deferred Revenue	39	45
Other	156	120
Other liabilities	1,183	1,042
RVO included in other liabilities, gross	1,100	1,100
RINs included in other liabilities, gross	$ 700	$ 1,000

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Share Capital and Warrants - Additional Information (Detail) - CAD ($) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended				9 Months Ended		12 Months Ended
	Jun. 14, 2023	Oct. 30, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022	Nov. 01, 2023	Dec. 31, 2021
Disclosure of classes of share capital [Line Items]
Maximum percentage of preferred stock upon issuance or outstanding of common stock							20.00%
NCIB, shares redeemed, amount			$ 361.0			$ 659.0	$ 711.0	$ 2,143.0
Payment for Purchase of Warrants			$ 600.0			$ 0.0	$ 600.0	$ 0.0
Common shares
Disclosure of classes of share capital [Line Items]
Purchase of Common Shares Under NCIB (in shares)							29,388,000		112,489,000
Shares outstanding (in shares)			1,885,559,000				1,885,559,000		1,909,190,000		2,001,211,000
Issued capital			$ 16,146.0				$ 16,146.0		$ 16,320.0		$ 17,016.0
Common shares | Renewed NCIB
Disclosure of classes of share capital [Line Items]
Purchase of Common Shares Under NCIB (in shares)							29,400,000
NCIB, shares repurchased, price per share (in CAD per share)							$ 24.19
NCIB, shares redeemed, amount							$ 711.0
NCIB, reduction to contributed surplus							$ 460.0
Common shares | Potential ordinary share transactions | Renewed NCIB
Disclosure of classes of share capital [Line Items]
NCIB, shares authorized for repurchase (in shares)		92,500,000								133,000,000
Purchase of Common Shares Under NCIB (in shares)		3,300,000
NCIB, shares redeemed, amount		$ 89.0
Stock Option Plan
Disclosure of classes of share capital [Line Items]
Shares available for future issuance (in shares)			45,200,000				45,200,000		43,100,000
Preference shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)			36,000,000				36,000,000
Issued capital			$ 519.0				$ 519.0
Expected dividend			6.29%	6.29%	5.86%
Common Share Warrants
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)			7,921,000				7,921,000		55,720,000		65,119,000
Issued capital			$ 26.0				$ 26.0		$ 184.0		$ 215.0
Exercise price of warrants issued (in CAD per share)	$ 6.54						$ 6.54
Purchased and cancelled (in shares)	45,500,000						45,485,000		0
Purchased and Cancelled	$ 711.0						$ 151.0		$ 0.0
Warrants purchase price (in CAD per share)	$ 22.18
Decrease through repurchase and cancellation of warrants, equity	$ 560.0
Decrease through repurchase and cancellation of warrants, transaction costs, equity	$ 2.0
Payment for Purchase of Warrants			$ 600.0

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Share Capital and Warrants - Issued and Outstanding - Common Shares (Detail) - Common shares - CAD ($) shares in Thousands, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
Number of Common Shares
Outstanding, Beginning of Year (in shares)	1,909,190	2,001,211
Issued Upon Exercise of Warrants (in shares)	2,314	9,399
Issued Under Stock Option Plans (in shares)	3,443	11,069
Purchases of common shares under NCIB (in shares)	(29,388)	(112,489)
Outstanding, End of Period (in shares)	1,885,559	1,909,190
Amount
Outstanding, Beginning of Year	$ 16,320	$ 17,016
Issued Upon Exercise of Warrants	23	93
Issued Under Stock Option Plans	54	170
Purchase of Common Shares Under NCIBs	(251)	(959)
Outstanding, End of Period	$ 16,146	$ 16,320

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Share Capital and Warrants - Issued and Outstanding - Preferred Shares (Details) - Preference shares - shares	3 Months Ended			9 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2023
Disclosure of classes of share capital [Line Items]
Shares issued (in shares)	0			0
Shares outstanding (in shares)	36,000,000			36,000,000
Expected dividend	6.29%	6.29%	5.86%
Series 1 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)	10,740,000			10,740,000
Expected dividend				2.58%
Series 2 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)	1,260,000			1,260,000
Expected dividend				6.89%
Series 3 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)	10,000,000			10,000,000
Expected dividend				4.69%
Series 5 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)	8,000,000			8,000,000
Expected dividend				4.59%
Series 7 First Preferred Shares
Disclosure of classes of share capital [Line Items]
Shares outstanding (in shares)	6,000,000			6,000,000
Expected dividend				3.94%

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Share Capital and Warrants - Issued and Outstanding - Warrants (Details) - Common Share Warrants - CAD ($) shares in Thousands, $ in Millions		9 Months Ended	12 Months Ended
	Jun. 14, 2023	Sep. 30, 2023	Dec. 31, 2022
Number of Warrants
Outstanding, Beginning of Year (in shares)		55,720	65,119
Issued Upon Exercise of Warrants (in shares)		(2,314)	(9,399)
Purchased and cancelled (in shares)	(45,500)	(45,485)	0
Outstanding, End of Period (in shares)		7,921	55,720
Amount
Outstanding, Beginning of Year		$ 184	$ 215
Issued Upon Exercise of Warrants		(7)	(31)
Purchased and Cancelled	$ (711)	(151)	0
Outstanding, End of Period		$ 26	$ 184

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Accumulated Other Comprehensive Income (Loss) - Schedule of Accumulated Other Comprehensive Income (Loss) (Detail) - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	$ 1,470	$ 684
Other Comprehensive Income (Loss), Before Tax	(23)	976
Income Tax (Expense) Recovery	(5)	(20)
Reclassification on Divestiture (Note 3)	12
Ending balance	1,454	1,640
Pension and Other Post-Employment Benefits
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	99	28
Other Comprehensive Income (Loss), Before Tax	20	78
Income Tax (Expense) Recovery	(5)	(20)
Reclassification on Divestiture (Note 3)	0
Ending balance	114	86
Private Equity Instruments
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	29	27
Other Comprehensive Income (Loss), Before Tax	0	2
Income Tax (Expense) Recovery	0	0
Reclassification on Divestiture (Note 3)	0
Ending balance	29	29
Foreign Currency Translation Adjustment
Disclosure of accumulated other comprehensive income loss [line items]
Beginning balance	1,342	629
Other Comprehensive Income (Loss), Before Tax	(43)	896
Income Tax (Expense) Recovery	0	0
Reclassification on Divestiture (Note 3)	12
Ending balance	$ 1,311	$ 1,525

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Stock-Based Compensation Plans - Narrative (Detail) - $ / shares	9 Months Ended
	Sep. 30, 2023	Feb. 28, 2023
Minimum
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Performance share unit plan, vesting multiplier, percent		0.00%
Maximum
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Performance share unit plan, vesting multiplier, percent		200.00%
Stock Options With Associated Net Settlement Rights
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Weighted average exercise price (in CAD per share)	$ 13.62
Common shares issued in exercise of other equity instruments (in shares)	49,000
Cenovus Replacement Stock Options
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Weighted average exercise price (in CAD per share)	$ 6.52
Common shares issued in exercise of other equity instruments (in shares)	2,000

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Stock-Based Compensation Plans - Summary of Information Related to Cenovus's Stock-Based Compensation Plans (Detail) shares in Thousands	9 Months Ended
	Sep. 30, 2023 shares $ / shares
Stock Options With Associated Net Settlement Rights
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share options, outstanding (in shares)	12,158
Number of share options, exercisable (in shares)	6,905
Number of share options, granted (in shares)	1,571
Number of shares issued for stock options exercised (in shares)	3,591
Number of share units, vested and exercised/paid out (in shares)	3,392
Weighted average exercise price of other equity instruments exercised or vested in share-based payment arrangement (in CAD per share) | $ / shares	$ 12.94
Weighted average exercise price of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in CAD per share) | $ / shares	$ 17.22
Number of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in shares)	199
Cenovus Replacement Stock Options
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share options, outstanding (in shares)	1,095
Number of share options, exercisable (in shares)	1,072
Number of share options, granted (in shares)	0
Number of shares issued for stock options exercised (in shares)	2,031
Number of share units, vested and exercised/paid out (in shares)	2,028
Weighted average exercise price of other equity instruments exercised or vested in share-based payment arrangement (in CAD per share) | $ / shares	$ 10.11
Weighted average exercise price of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in CAD per share) | $ / shares	$ 3.54
Number of other equity instruments exercised or vested in share-based payment arrangement, settled for common shares (in shares)	3
Performance Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share units, outstanding (in shares)	10,193
Number of share units, exercisable (in shares)	0
Number of share units, granted (in shares)	2,533
Number of share units, vested and exercised/paid out (in shares)	972
Restricted Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share units, outstanding (in shares)	7,217
Number of share units, exercisable (in shares)	0
Number of share units, granted (in shares)	2,955
Number of share units, vested and exercised/paid out (in shares)	2,299
Deferred Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of share units, outstanding (in shares)	1,662
Number of share units, exercisable (in shares)	1,662
Number of share units, granted (in shares)	162
Number of share units, vested and exercised/paid out (in shares)	33

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Stock-Based Compensation Plans - Summary of Stock-Based Compensation (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	$ 151	$ (1)	$ 196	$ 193
Stock Options With Associated Net Settlement Rights
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	2	3	9	12
Cenovus Replacement Stock Options
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	6	(5)	(1)	36
Performance Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	98	1	125	66
Restricted Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	35	4	56	65
Deferred Share Units
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	$ 10	$ (4)	$ 7	$ 14

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Related Party Transactions (Details) - Husky Midstream Limited Partnership - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disclosure of transactions between related parties [line items]
Share of equity investment			35.00%
Joint ventures where entity is venturer
Disclosure of transactions between related parties [line items]
Revenue from rendering of services, related party transactions	$ 49	$ 56	$ 112	$ 133
Purchases of goods, related party transactions	$ 67	$ 64	$ 205	$ 197

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Financial Instruments - Narrative (Detail) $ in Millions	Sep. 30, 2023 CAD ($) $ / bbl	Dec. 31, 2022 CAD ($)
Disclosure of detailed information about financial instruments [Line Items]
Borrowings	$ 7,224	$ 8,691
Discounted credit adjusted risk free rate	5.40%
Sunrise Oil Sands Partnership
Disclosure of detailed information about financial instruments [Line Items]
Estimated fair value of contingent payment	$ 295	419
Western Canadian Select Forward Pricing
Disclosure of detailed information about financial instruments [Line Items]
Average forward price for Western Canadian Select Crude Oil for the remaining term (in CAD per barrel) | $ / bbl	89.81
West Texas Intermediate Option Volatility
Disclosure of detailed information about financial instruments [Line Items]
Average implied volatility contingent payment percentage	36.60%
Foreign Exchange Average Volatility Rate Contingent
Disclosure of detailed information about financial instruments [Line Items]
Average implied volatility contingent payment percentage	5.90%
Level 2 of fair value hierarchy
Disclosure of detailed information about financial instruments [Line Items]
Debt, fair value	$ 6,200	$ 7,800

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Financial Instruments - Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets (Detail) - Level 3 of fair value hierarchy $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($)
Disclosure of fair value measurement of assets [Line Items]
Fair value, beginning of year	$ 55
Acquisition	11
Fair value, end of year	$ 66

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Financial Instruments - Summary of Unrealized Risk Management Positions (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management net asset (liability)	$ (27)	$ 46
Power Swap Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management net asset (liability)	2
Level 2 of fair value hierarchy
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management asset	25	93
Risk management liability	52	47
Risk management net asset (liability)	(27)	46
Level 2 of fair value hierarchy | Commodity price risk | Crude Oil, Natural Gas, Condensate and Refined Products
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management asset	0	2
Risk management liability	49	40
Risk management net asset (liability)	(49)	(38)
Level 2 of fair value hierarchy | Commodity price risk | Power Swap Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management asset	4	1
Risk management liability	2	7
Risk management net asset (liability)	2	(6)
Level 2 of fair value hierarchy | Commodity price risk | Renewable Power Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management asset	21	90
Risk management liability	0	0
Risk management net asset (liability)	21	90
Level 2 of fair value hierarchy | Currency risk | Foreign Exchange Rate Contracts
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk management asset	0	0
Risk management liability	1	0
Risk management net asset (liability)	$ (1)	$ 0

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Financial Instruments - Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair value of derivative financial instruments net	$ (27)	$ 46
Level 2 of fair value hierarchy
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair value of derivative financial instruments	(48)	(44)
Fair value of derivative financial instruments net	(27)	46
Level 3 of fair value hierarchy
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair value of derivative financial instruments	$ 21	$ 90

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Financial Instruments - Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($)
Disclosure of detailed information about financial instruments [abstract]
As at December 31, 2022	$ 46
Change in Fair Value of Contracts in Place, Beginning of Year	1
Change in Fair Value of Contracts Entered Into During the Period	(76)
Fair Value of Contracts Realized During the Period	1
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	1
As at September 30, 2023	$ (27)

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Financial Instruments - Summary of Earnings Impact of (Gain) Loss from Risk Management Positions (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disclosure of detailed information about financial instruments [line items]
(Gain) Loss on Risk Management	$ 72	$ (28)	$ 89	$ 1,540
Realized (Gain) Loss
Disclosure of detailed information about financial instruments [line items]
(Gain) Loss on Risk Management	0	(10)	1	1,628
Unrealized (Gain) Loss on Risk Management
Disclosure of detailed information about financial instruments [line items]
(Gain) Loss on Risk Management	$ 72	$ (18)	$ 88	$ (88)

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Financial Instruments - Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2023 CAD ($) $ / bbl
Western Canadian Select Forward Pricing
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Sensitivity price range | $ / bbl	10.00
West Texas Intermediate Option Volatility
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Sensitivity range	10.00%
Foreign Exchange Volatility Rate
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Increase in volatility	$ 0
Decrease in volatility	$ 0
Sensitivity range	5.00%

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Risk Management - Additional Information (Detail) $ in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2023 USD ($)	Sep. 30, 2023 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Fair value of derivative financial instruments net		$ (27)		$ 46
Percentage of accounts receivable outstanding, less than 60 days	98.00%	98.00%
Target net debt to adjusted EBITDA ratio	1.0
Fair Value Derivative Financial Instruments
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Average contract financial term	1 year
Foreign Exchange Contracts
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Fair value of derivative financial instruments net		$ (1)
Notional value	$ 302		$ 168
Interest Rate, Foreign Exchange or Cross Currency Interest Rate Swap
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Notional value	$ 0		$ 0
Trade Receivables | Credit risk
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Average expected credit loss rate	0.60%	0.60%	0.40%	0.40%
Trade Receivables | Credit risk | Investment grade counterparties
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Number of days outstanding for accruals, joint operations, trade receivables and net investment in finance leases	60 days	60 days
Trade Receivables | Credit risk | Investment grade counterparties | Minimum
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Percent of accounts receivable held with investment grade counterparties	83.00%	83.00%	85.00%	85.00%

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Risk Management - Net Fair Value of Risk Management Positions (Detail) MMBbls in Millions, $ in Millions	Sep. 30, 2023 CAD ($) $ / bbl MMBbls	Dec. 31, 2022 CAD ($)
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	$ (27)	$ 46
Power Swap Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	2
Renewable Power Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	21
Foreign Exchange Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	$ (1)
WTI Fixed - Sell | Crude Oil and Condensate Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | MMBbls	6.2
Weighted Average Price | $ / bbl	83.06
Fair Value Asset (Liability)	$ (52)
WTI Fixed - Buy | Crude Oil and Condensate Contracts
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | MMBbls	2.6
Weighted Average Price | $ / bbl	86.23
Fair Value Asset (Liability)	$ 13
Other financial positions
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	$ (10)

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Risk Management - Impact of Fluctuating Commodity Prices and Interest Rates on Company'S Open Risk Management Positions (Detail) $ in Millions	Sep. 30, 2023 CAD ($) $ / bbl $ / MMcf $ / $ $ / MWh
Commodity price risk | WCS and Condensate Differential
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / bbl	2.50
Increase	$ 2
Decrease	$ (2)
Commodity price risk | WCS Hardisty
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / bbl	5.00
Increase	$ (23)
Decrease	$ 23
Commodity price risk | Refined Products
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / bbl	10.00
Increase	$ (5)
Decrease	$ 5
Commodity price risk | Natural Gas Contracts
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / MMcf	0.50
Increase	$ 1
Decrease	$ (1)
Commodity price risk | Power Commodity
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / MWh	20.00
Increase	$ 109
Decrease	$ (109)
Commodity price risk | Crude Oil Contracts
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / bbl	10.00
Increase	$ 0
Decrease	$ 0
Currency risk | U.S. to Canadian Dollar Exchange Rate
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Sensitivity Range | $ / $	0.05
Increase	$ 26
Decrease	$ (30)

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Risk Management - Undiscounted Cash Outflows Relating to Financial Liabilities (Detail) - CAD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Accounts payable and accrued liabilities
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	$ 6,435	$ 6,124
Accounts payable and accrued liabilities | Remainder of Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	6,435	6,124
Accounts payable and accrued liabilities | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Accounts payable and accrued liabilities | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Accounts payable and accrued liabilities | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Short-Term Borrowings
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	14	115
Short-Term Borrowings | Remainder of Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	14	115
Short-Term Borrowings | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Short-Term Borrowings | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Short-Term Borrowings | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Lease Liabilities
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	4,456	4,657
Lease Liabilities | Remainder of Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	445	426
Lease Liabilities | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	734	746
Lease Liabilities | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	577	596
Lease Liabilities | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	2,700	2,889
Long-Term Debt
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	11,535	14,594
Long-Term Debt | Remainder of Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	318	401
Long-Term Debt | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	807	983
Long-Term Debt | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	3,038	2,014
Long-Term Debt | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	7,372	11,196
Contingent Payment
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	300	438
Contingent Payment | Remainder of Year
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	300	271
Contingent Payment | Years 2 and 3
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	167
Contingent Payment | Years 4 and 5
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	0	0
Contingent Payment | Thereafter
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Financial instruments	$ 0	$ 0

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Supplementary Cash Flow Information - Non-Cash Working Capital (Details) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Disclosure Of Supplementary Cash Flow Information [Line Items]
Current assets	$ 10,745		$ 10,745		$ 12,430
Current Liabilities	7,205		7,205		8,021
Working Capital	3,540		3,540		4,409
Adjusted working capital	3,800		3,800		4,700
Contingent Payments	295		295		$ 263
Accounts Receivable and Accrued Revenues	(1,288)	$ 1,746	(1,097)	$ 119
Income Tax Receivable	157	(111)	(12)	(88)
Inventories	(505)	1,138	(343)	(172)
Accounts Payable and Accrued Liabilities	851	(1,547)	69	(388)
Income Tax Payable	107	74	(1,056)	877
Total Change in Non-Cash Working Capital	(678)	1,300	(2,439)	348
Net Change in Non-Cash Working Capital – Operating Activities	(641)	1,193	(2,142)	(98)
Net Change in Non-Cash Working Capital – Investing Activities	$ (37)	$ 107	$ (297)	$ 446

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Supplementary Cash Flow Information - Summary of Reconciliation of Liabilities to Cash Flows from Financing Activities (Detail) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance, short-term borrowings			$ 115
Beginning balance, lease liabilities			2,836
Changes From Financing Cash Flows:
(Repayment) of Long-Term Debt	$ (1,346)	$ (2,889)	(1,346)	$ (4,149)
Principal Repayment of Leases	(70)	(78)	(216)	(228)
Payment for Purchase of Warrants	(600)	0	(600)	0
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt	(84)	(4)	(84)	(29)
Lease Additions			45
Lease Modifications			34
Lease Re-measurements			8
Ending balance, short term borrowings	14		14		$ 115
Ending Balance, lease liabilities	2,733		2,733		2,836
Dividends Payable
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance. dividend payables			9	0	0
Non-Cash Changes:
Beginning balance. dividend payables	9	0	9	0	9
Dividends Payable | Common shares
Changes From Financing Cash Flows:
Dividends Paid			(729)	(481)
Non-Cash Changes:
Dividends declared			729	481
Dividends Payable | Preference shares
Changes From Financing Cash Flows:
Dividends Paid			(27)	(26)
Non-Cash Changes:
Dividends declared			27	26
Warrant Purchase Payable
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance, warrant payable			0	0	0
Changes From Financing Cash Flows:
Payment for Purchase of Warrants			(600)
Finance and Transaction Costs			(2)
Non-Cash Changes:
Finance Costs			2
Purchased and Cancelled			711
Ending balance, warrant payable	111	0	111	0	0
Short-Term Borrowings
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance, short-term borrowings			115	79	79
Changes From Financing Cash Flows:
Net Issuance Repayment Of Short Term Borrowings			(101)	(81)
Non-Cash Changes:
Lease Acquisitions			0
Exchange Rate Movements and Other			0	2
Ending balance, short term borrowings	14	0	14	0	115
Long-Term Debt
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance, long-term debt			8,691	12,385	12,385
Changes From Financing Cash Flows:
(Repayment) of Long-Term Debt			(1,346)	(4,149)
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt			(84)	(29)
Finance Costs			(15)	(24)
Lease Acquisitions			0
Exchange Rate Movements and Other			(22)	591
Ending balance, long-term debt	7,224	8,774	7,224	8,774	8,691
Lease Liabilities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Beginning balance, lease liabilities			2,836	2,957	2,957
Changes From Financing Cash Flows:
Principal Repayment of Leases			(216)	(228)
Non-Cash Changes:
Lease Acquisitions			33
Lease Additions			45	19
Lease Modifications			34	46
Lease Re-measurements			(6)	3
Lease Divestitures			(11)
Lease Re-measurements			(8)	(2)
Exchange Rate Movements and Other			26	74
Ending Balance, lease liabilities	$ 2,733	$ 2,869	$ 2,733	$ 2,869	$ 2,836

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Commitments and Contingencies - Future Payments for Commitments (Details) - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	$ 20,231
Product Purchases	1,172
Real estate	856
Obligation to fund equity-accounted affiliate	558
Other long term commitments	1,873
Total Commitments	24,690
Commitments approved and not yet in service
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	$ 9,100	$ 9,100
Minimum
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation commitments subject to regulatory approval or approved but not yet in service term	20 years
Remainder of Year
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	$ 432
Product Purchases	393
Real estate	15
Obligation to fund equity-accounted affiliate	25
Other long term commitments	284
Total Commitments	1,149
2 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	1,958
Product Purchases	779
Real estate	53
Obligation to fund equity-accounted affiliate	105
Other long term commitments	185
Total Commitments	3,080
3 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	1,717
Product Purchases	0
Real estate	54
Obligation to fund equity-accounted affiliate	96
Other long term commitments	163
Total Commitments	2,030
4 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	1,453
Product Purchases	0
Real estate	56
Obligation to fund equity-accounted affiliate	96
Other long term commitments	151
Total Commitments	1,756
5 Years
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	1,408
Product Purchases	0
Real estate	59
Obligation to fund equity-accounted affiliate	91
Other long term commitments	142
Total Commitments	1,700
Thereafter
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Transportation and storage	13,263
Product Purchases	0
Real estate	619
Obligation to fund equity-accounted affiliate	145
Other long term commitments	948
Total Commitments	$ 14,975

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Commitments and Contingencies - Narrative (Details) - CAD ($) $ in Millions	Sep. 30, 2023	Feb. 28, 2023	Dec. 31, 2022
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Total commitments	$ 24,690
Outstanding letters of credit	353		$ 490
HMLP
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Total commitments	$ 2,100		$ 2,200
BP-Husky Refining LLC
Disclosure Of Commitments And Contingent Liabilities [Line Items]
Total commitments		$ 538

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Prior Period Revisions (Details) - CAD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2023		Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022		Sep. 30, 2023		Sep. 30, 2022
Disclosure of changes in accounting estimates [line items]
Gross Sales	$ 15,712				$ 18,697		$ 41,438		$ 56,827
Purchased Product	6,620	[1]	$ 5,728	$ 5,809	10,052	[1]	18,157	[1]	27,038	[1]
Transportation and Blending	2,164	[1]	2,563	2,752	2,579	[1]	7,479	[1]	8,406	[1]
Operating	1,553	[1]	1,600	1,636	1,504	[1]	4,789	[1]	4,360	[1]
Depreciation, Depletion and Amortization	1,197				1,047		3,374		3,209
Purchased Product, Transportation And Blending, Operating			9,891	10,197	14,135				39,804
Oil Sands
Disclosure of changes in accounting estimates [line items]
Gross Sales			6,437	5,707	8,764				28,030
Purchased Product			414	355	1,919				4,202
Gross sales and purchased product			6,023	5,352	6,845				23,828
Gross sales less purchased product			6,023	5,352	6,845				23,828
Conventional
Disclosure of changes in accounting estimates [line items]
Gross Sales			620	1,037	1,036				3,286
Purchased Product			337	483
Transportation and Blending			66	81	64				191
Gross sales less purchased product and transportation and blending			217	473
Gross Sales Less Transportation And Blending					972				3,095
U.S. Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales			6,064	5,629	8,705				23,688
Purchased Product			5,364	4,898	7,930				20,351
Gross sales and purchased product			700	731	775				3,337
Gross sales less purchased product			700	731	775				3,337
Corporate and Eliminations
Disclosure of changes in accounting estimates [line items]
Gross Sales	(2,729)		(1,844)	(1,496)	(2,426)		(6,069)		(5,772)
Purchased Product	(2,227)		(1,470)	(1,020)	(2,011)		(4,717)		(4,040)
Transportation and Blending	(233)		(207)	(275)	(247)		(715)		(911)
Operating	(139)		(126)	(147)	(191)		(412)		(765)
Depreciation, Depletion and Amortization	$ 19				27		$ 59		86
Gross sales less purchased product, transportation and blending and operating			(41)	(54)	23				(56)
Canadian Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales					2,168				6,020
Purchased Product					1,750				5,065
Transportation and Blending					0				0
Operating					172				534
Depreciation, Depletion and Amortization					42				164
Gross sales less purchased product, transportation, blending and operating, and depreciation, depletion and amortization					204				257
Retail
Disclosure of changes in accounting estimates [line items]
Gross Sales					0				0
Purchased Product					0				0
Operating					0				0
Depreciation, Depletion and Amortization					0				0
Gross Sales Less Purchased Product, Operating, And Depreciation, Depletion And Amortization					0				0
Previously Reported
Disclosure of changes in accounting estimates [line items]
Purchased Product			5,709	5,792	10,012				26,890
Transportation and Blending			2,641	2,853	2,684				8,707
Operating			1,541	1,552	1,439				4,207
Purchased Product, Transportation And Blending, Operating			9,891	10,197	14,135				39,804
Previously Reported | Oil Sands
Disclosure of changes in accounting estimates [line items]
Gross Sales			6,556	5,911	8,778				28,044
Purchased Product			533	559	1,933				4,216
Gross sales and purchased product			6,023	5,352	6,845				23,828
Gross sales less purchased product			6,023	5,352	6,845				23,828
Previously Reported | Conventional
Disclosure of changes in accounting estimates [line items]
Gross Sales			615	1,031	1,010				3,201
Purchased Product			352	510
Transportation and Blending			46	48	38				106
Gross sales less purchased product and transportation and blending			217	473
Gross Sales Less Transportation And Blending					972				3,095
Previously Reported | U.S. Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales			6,198	5,860	8,719				23,702
Purchased Product			5,498	5,129	7,944				20,365
Gross sales and purchased product			700	731	775				3,337
Gross sales less purchased product			700	731	775				3,337
Previously Reported | Corporate and Eliminations
Disclosure of changes in accounting estimates [line items]
Gross Sales			(2,092)	(1,925)	(2,619)				(6,162)
Purchased Product			(1,757)	(1,499)	(2,267)				(4,660)
Transportation and Blending			(109)	(141)	(119)				(528)
Operating			(185)	(231)	(256)				(918)
Gross sales less purchased product, transportation and blending and operating			(41)	(54)	23				(56)
Previously Reported | Canadian Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales					1,478				4,043
Purchased Product					1,092				3,192
Transportation and Blending					3				3
Operating					134				438
Depreciation, Depletion and Amortization					37				143
Gross sales less purchased product, transportation, blending and operating, and depreciation, depletion and amortization					212				267
Previously Reported | Retail
Disclosure of changes in accounting estimates [line items]
Gross Sales					881				2,424
Purchased Product					846				2,317
Operating					38				96
Depreciation, Depletion and Amortization					5				21
Gross Sales Less Purchased Product, Operating, And Depreciation, Depletion And Amortization					(8)				(10)
Revisions
Disclosure of changes in accounting estimates [line items]
Purchased Product			19	17	40				148
Transportation and Blending			(78)	(101)	(105)				(301)
Operating			59	84	65				153
Purchased Product, Transportation And Blending, Operating			0	0	0				0
Revisions | Oil Sands
Disclosure of changes in accounting estimates [line items]
Gross Sales			(119)	(204)	(14)				(14)
Purchased Product			(119)	(204)	(14)				(14)
Gross sales and purchased product			0	0	0				0
Gross sales less purchased product			0	0	0				0
Revisions | Conventional
Disclosure of changes in accounting estimates [line items]
Gross Sales			5	6	26				85
Purchased Product			(15)	(27)
Transportation and Blending			20	33	26				85
Gross sales less purchased product and transportation and blending			0	0
Gross Sales Less Transportation And Blending					0				0
Revisions | U.S. Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales			(134)	(231)	(14)				(14)
Purchased Product			(134)	(231)	(14)				(14)
Gross sales and purchased product			0	0	0				0
Gross sales less purchased product			0	0	0				0
Revisions | Corporate and Eliminations
Disclosure of changes in accounting estimates [line items]
Gross Sales			248	429	2				(57)
Purchased Product			287	479	65				173
Transportation and Blending			(98)	(134)	(128)				(383)
Operating			59	84	65				153
Gross sales less purchased product, transportation and blending and operating			$ 0	$ 0	0				0
Revisions | Canadian Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales					0				0
Purchased Product					3				3
Transportation and Blending					(3)				(3)
Operating					0				0
Depreciation, Depletion and Amortization					0				0
Gross sales less purchased product, transportation, blending and operating, and depreciation, depletion and amortization					0				0
Revisions | Retail
Disclosure of changes in accounting estimates [line items]
Gross Sales					0				0
Purchased Product					0				0
Operating					0				0
Depreciation, Depletion and Amortization					0				0
Gross Sales Less Purchased Product, Operating, And Depreciation, Depletion And Amortization					0				0
Segment Aggregation
Disclosure of changes in accounting estimates [line items]
Purchased Product					0				0
Transportation and Blending					0				0
Operating					0				0
Purchased Product, Transportation And Blending, Operating					0				0
Segment Aggregation | Oil Sands
Disclosure of changes in accounting estimates [line items]
Gross Sales					0				0
Purchased Product					0				0
Gross sales and purchased product					0				0
Gross sales less purchased product					0				0
Segment Aggregation | Conventional
Disclosure of changes in accounting estimates [line items]
Gross Sales					0				0
Transportation and Blending					0				0
Gross Sales Less Transportation And Blending					0				0
Segment Aggregation | U.S. Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales					0				0
Purchased Product					0				0
Gross sales and purchased product					0				0
Gross sales less purchased product					0				0
Segment Aggregation | Corporate and Eliminations
Disclosure of changes in accounting estimates [line items]
Gross Sales					191				447
Purchased Product					191				447
Transportation and Blending					0				0
Operating					0				0
Gross sales less purchased product, transportation and blending and operating					0				0
Segment Aggregation | Canadian Manufacturing
Disclosure of changes in accounting estimates [line items]
Gross Sales					690				1,977
Purchased Product					655				1,870
Transportation and Blending					0				0
Operating					38				96
Depreciation, Depletion and Amortization					5				21
Gross sales less purchased product, transportation, blending and operating, and depreciation, depletion and amortization					(8)				(10)
Segment Aggregation | Retail
Disclosure of changes in accounting estimates [line items]
Gross Sales					(881)				(2,424)
Purchased Product					(846)				(2,317)
Operating					(38)				(96)
Depreciation, Depletion and Amortization					(5)				(21)
Gross Sales Less Purchased Product, Operating, And Depreciation, Depletion And Amortization					$ 8				$ 10

[1] Comparative periods reflect certain revisions. See Note 26