Form 6-K - Report of foreign issuer [Rules 13a-16 and 15d-16]

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 August 2024

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): ☐

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: August 1, 2024

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 August 1, 2024

99.2						Management’s Discussion and Analysis dated July 31, 2024 for the period ended June 30, 2024

99.3						Interim Consolidated Financial Statement (unaudited) for the period ended June 30, 2024

99.4						Form 52-109F2 Full Certificate, dated August 1, 2024, of Jonathan M. McKenzie, President & Chief Executive Officer

99.5						Form 52-109F2 Full Certificate, dated August 1, 2024, of Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer


						Exhibit 99.1

News release

Cenovus announces second quarter 2024 results

Calgary, Alberta (August 1, 2024) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) delivered strong operational performance across its portfolio in the second quarter of 2024, with solid production from its upstream assets and improved crude throughput at the company’s U.S. refineries, which operated at an overall utilization rate of 93%. Net debt was $4.26 billion at June 30, 2024, and in July the company achieved its net debt target of $4.0 billion. As a result, beginning in the third quarter, Cenovus will begin returning 100% of excess free funds flow (EFFF) to shareholders, as per the company’s shareholder returns framework.

“With the achievement of this significant financial milestone, we are now in a position to substantially increase our shareholder returns,” said Jon McKenzie, Cenovus President & Chief Executive Officer. “We will continue our focus on safely delivering profitable and predictable operations, while progressing our growth projects to further improve the resiliency of the company.”

Recent highlights

•Achieved net debt target of $4.0 billion in July, immediately shifting to returning 100% excess free funds flow to shareholders.

•As a result of strong first half performance, increased the midpoint of Upstream production guidance to 797,500 barrels of oil equivalent per day (BOE/d)1 and the midpoint of Downstream throughput guidance to 655,000 barrels per day (bbls/d). Capital investment range is unchanged.

•The Narrows Lake tie-back pipeline to Christina Lake is expected to achieve mechanical completion by the end of the year, and remains on schedule to deliver first oil mid-2025.

•At Sunrise, the company began steaming two well pads which will be brought on production in the third and fourth quarters of this year.

•Achieved significant milestones on the West White Rose project as the concrete gravity structure reached its final height and topsides were structurally completed.

•Safely completed the largest turnaround in the Lloydminster Upgrader’s history, with the facility now returned to full operations.


Financial, production & throughput summary
For the period ended June 30	2024 Q2	2024 Q1	2023 Q2
Financial ($ millions, except per share amounts)
Cash from (used in) operating activities	2,807	1,925	1,990
Adjusted funds flow2	2,361	2,242	1,899
Per share (diluted)2	1.26	1.19	0.98
Capital investment	1,155	1,036	1,002
Free funds flow2	1,206	1,206	897
Excess free funds flow2	735	832	505
Net earnings (loss)	1,000	1,176	866
Per share (diluted)	0.53	0.62	0.44
Long-term debt, including current portion	7,275	7,227	8,534
Net debt	4,258	4,827	6,367
Production and throughput (before royalties, net to Cenovus)
Oil and NGLs (bbls/d)1	656,300	658,200	608,400
Conventional natural gas (MMcf/d)	867.2	855.8	729.4

1 See 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


Total upstream production (BOE/d)1	800,800	800,900	729,900
Total downstream throughput (bbls/d)	622,700	655,200	537,800

Second-quarter results

Operating results1

Cenovus’s total revenues were approximately $14.9 billion in the second quarter of 2024, up from $13.4 billion in the first quarter, driven primarily by improved benchmark oil prices, including a narrower light-heavy crude oil differential, combined with strong operating results. Upstream revenues were about $7.9 billion, an increase from $7.1 billion in the first quarter, while downstream revenues were approximately $9.1 billion, up from $8.6 billion in the first quarter. Total operating margin3 was about $2.9 billion, compared with $3.2 billion in the previous quarter. Upstream operating margin4 was approximately $3.1 billion, up from $2.6 billion in the first quarter. The company had a downstream operating margin4 shortfall of $153 million in the second quarter, compared with an operating margin of $560 million in the previous quarter as the Lloydminster Upgrader underwent a major planned turnaround. The turnaround was impacted by weather-related delays which resulted in additional costs due to lost productivity. The turnaround is now complete and the Upgrader has ramped up to full rates. Downstream operating margin was further impacted by narrower light-heavy crude oil differentials in addition to planned and unplanned outages. In the second quarter, operating margin in U.S. Refining benefited from approximately $80 million of first in, first out (FIFO) gains.

Total upstream production was 800,800 BOE/d in the second quarter, in line with the first quarter. Foster Creek volumes were 195,000 bbls/d compared with 196,000 bbls/d in the first quarter and Christina Lake production was 237,100 bbls/d, in line with the first quarter. Christina Lake will commence planned turnaround activity in September, which is expected to reduce third-quarter production volumes by approximately 45,000 bbls/d. Sunrise production was 46,100 bbls/d in the second quarter, a slight decline from the previous quarter, reflecting a planned outage. Lloydminster thermal production was 113,500 bbls/d, which reflects a successful redevelopment program and base well optimization. Lloydminster conventional heavy oil production was 18,100 bbls/d, in line with the first quarter. In the second quarter, Cenovus loaded its first vessels at the Westridge Marine Terminal following the successful startup of the Trans Mountain pipeline expansion.

Production in the Conventional segment was 123,100 BOE/d in the second quarter, an increase from 120,700 BOE/d in the prior quarter. Conventional operating costs declined approximately 14% from the first quarter of 2024, to $11.25/BOE4, reflecting lower repair and maintenance expenses, the divestment of higher-cost assets and the company’s commitment to cost discipline.

In the Offshore segment, production was 66,200 BOE/d compared with 64,900 BOE/d in the first quarter. In Asia Pacific, sales volumes were 57,800 BOE/d, reflecting strong natural gas demand in the region. In the Atlantic, production was 8,400 bbls/d, up from 7,200 bbls/d in the prior quarter as the non-operated Terra Nova field continues to ramp up to full rates. Sales volumes in the Atlantic region in the second quarter were 14,800 bbls/d, compared with 3,900 bbls/d in the first quarter. Planned maintenance work on the SeaRose floating production, storage and offloading (FPSO) vessel is nearing completion and the company anticipates the return of the vessel to the White Rose field late in the third quarter of this year.

Refining throughput in the second quarter was 622,700 bbls/d, a decrease from 655,200 bbls/d in the first quarter, due to planned maintenance activities in Canadian Refining as well as both planned and minor unplanned outages in U.S. Refining. Crude throughput in the Canadian Refining segment was 53,800 bbls/d in the second quarter, compared with 104,100 bbls/d in the first quarter, with the decrease due to the

1 See Advisory for production by product type.

3 Non-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.

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turnaround at the Lloydminster Upgrader. The turnaround was safely and successfully completed, and the Upgrader has now ramped up to normal rates. Weather-related delays impacting the turnaround resulted in cost increases due to lost productivity and extended the scheduled timeline.

In U.S. Refining, crude throughput was 568,900 bbls/d in the second quarter, compared with 551,100 bbls/d in the first quarter. Throughput in the quarter increased primarily due to improved operating performance and availability across the company's operated and non-operated refining assets and lower levels of planned maintenance when compared with the prior quarter. In addition, the company has optimized planned turnaround activity at the Lima Refinery in the second half of the year, leveraging the integration of the company’s expanded refinery network. This, combined with the deferral of some planned turnaround activities into 2025, is now reflected in the planned maintenance summary below and in the company’s updated guidance range for crude throughput.

1 See Advisory for production by product type.

3 Non-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 | 3

Financial results

Second-quarter cash from operating activities, which includes changes in non-cash working capital, was about $2.8 billion, compared with $1.9 billion in the first quarter of 2024. Adjusted funds flow was approximately $2.4 billion, compared with $2.2 billion in the prior period and free funds flow was $1.2 billion, in line with the previous quarter. Second-quarter financial results were positively impacted by higher benchmark crude oil prices and a narrowing of the light-heavy crude oil differential, partially offset by higher feedstock costs in the company’s Downstream business and increased condensate prices. Net earnings in the second quarter were $1.0 billion, a slight decline from $1.2 billion in the previous quarter, primarily as a result of higher purchased product, and transportation and blending costs.

Long-term debt, including the current portion, was $7.3 billion at June 30, 2024, in line with the previous quarter. Net debt was approximately $4.26 billion at June 30, 2024, a decrease from $4.8 billion at March 31, 2024, primarily due to free funds flow of $1.2 billion and a release of non-cash working capital. These factors were partially offset by shareholder returns of $1.0 billion. In July, the company achieved its net debt target of $4.0 billion, and will now return 100% of EFFF to shareholders in accordance with its financial framework.

Growth projects and capital investments

In the Oil Sands segment, the company continues to progress the tie-back of Narrows Lake, building a 17-kilometre pipeline connecting the reservoir to the Christina Lake processing facility, which will add between 20,000 bbls/d and 30,000 bbls/d of production starting in late 2025. The project is now 88% constructed, with the first two pads drilled, and hydro testing of the first segment of the line was completed in the second quarter of 2024. At Sunrise, the company began steaming two well pads which will be brought on production in the third and fourth quarters of this year, and one additional well pad will come online in early 2025. Additionally, the optimization project at Foster Creek remains on schedule for startup by the middle of 2026, with most modules and major pieces of equipment in place and pipe installation underway. At the Conventional Heavy Oil assets, the rig fleet has ramped up to four rigs. The company expects to see increased drilling activity in the second half of the year and a higher exit production rate for the asset.

Capital in the Conventional business was directed towards drilling, completion, tie-in and infrastructure projects. The West White Rose project reached a significant milestone with the completion of major construction on two key components of the platform, with the concrete gravity structure reaching its final height and the topsides structurally completed. The West White Rose project is now approximately 80% complete and progressing on-schedule, with first production expected from the field in 2026. In the Downstream, capital was primarily directed to sustaining activities and reliability initiatives at the company’s operated and non-operated assets.

2024 guidance update

Cenovus has revised its 2024 corporate guidance to reflect the company’s updated outlook for the remainder of the year. It is available on Cenovus.com under Investors.

Changes to the company’s 2024 guidance include:

•Total upstream production of 785,000 BOE/d to 810,000 BOE/d, an increase of 7,500 BOE/d at the midpoint as a result of strong year-to-date performance and asset reliability.

•Total downstream throughput of 640,000 bbls/d to 670,000 bbls/d, an increase of 5,000 bbls/d at the midpoint as a result of strong year-to-date performance and optimization of the

1 See Advisory for production by product type.

3 Non-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 | 4

company’s turnaround activities in the second half of the year, including turnaround activity that was deferred to 2025.

•Oil Sands operating costs of $10.50/bbl to $12.50/bbl representing a decrease of 12% at the midpoint, and Asia Pacific operating costs of $9.50/BOE to $10.50/BOE, representing a decrease of $2.00/BOE at the midpoint.

•Updated Canadian Refining operating costs per barrel range to $20.25/bbl to $22.25/bbl to reflect cost increases associated with the Lloydminster Upgrader turnaround which were incurred in the first half of the year.

•G&A expenses of $625 million to $675 million, a reduction of $25 million at the midpoint

The company has also updated its commodity price assumptions, guidance range for cash taxes, and operating cost guidance for the Atlantic and U.S. Downstream segments. The company continues to execute its capital program and there has been no change to Cenovus’s expected capital investment range of $4.5 billion to $5.0 billion.

Dividend declarations and share purchases

The Board of Directors has declared a quarterly base dividend of $0.180 per common share, payable on September 27, 2024 to shareholders of record as of September 13, 2024.

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 October 1, 2024 to shareholders of record as of September 13, 2024 as follows:


Preferred shares dividend summary
Share series	Rate (%)	Amount ($/share)
Series 1	2.577	0.16106
Series 2	6.602	0.41488
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.

In the second quarter, the company returned approximately $1.0 billion to common shareholders. This was composed of $440 million through its normal course issuer bid, $334 million through base dividends and $251 million of variable dividends paid.

2024 planned maintenance

The following table provides details on planned maintenance activities at Cenovus assets through 2024 and anticipated production or throughput impacts.


2024 planned maintenance
Potential quarterly production/throughput impact (Mbbls/d or MBOE/d)
	Q3	Q4	Annualized impact
Upstream
Oil Sands	42-47	6-10	13-16

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2024 planned maintenance
Atlantic	8-10	—	5-7
Conventional	6-8	—	2-4
Downstream
Canadian Refining	2-5	—	12-14
U.S. Refining	10-15	15-20	12-15

Organizational updates

Drew Zieglgansberger, Executive Vice-President & Chief Commercial Officer, has announced his retirement from Cenovus effective August 31, 2024. The current duties of the chief commercial officer will be reassigned to other members of the company’s senior leadership team.

“Drew has made significant contributions in multiple roles during his impressive 25-year career with Cenovus and its predecessor companies,” said McKenzie. “As Chief Commercial Officer, Drew has led the successful integration of the commercial aspects of our business with our operations, which we will continue to build on as we demonstrate the value of our larger, integrated company. I would like to thank Drew for his many contributions over the years and wish him the very best.”

Sustainability

Cenovus’s 2023 Environmental, Social & Governance report was originally scheduled to be published at the end of June. However, due to significant uncertainty created by recent changes to Canada’s Competition Act involving environmental and climate disclosure standards, Cenovus will be issuing an interim Corporate Social Responsibility report in late August, addressing safety, Indigenous reconciliation, inclusion & diversity and governance. The extent to which the Competition Bureau can provide clarity regarding its new environmental disclosure standards will help guide Cenovus’s future communications about the environmental work the company continues to advance.


Conference call today 8 a.m. Mountain Time (10 a.m. Eastern Time) Cenovus will host a conference call today, August 1, 2024, 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 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) Accounting Standards.

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

CENOVUS ENERGY NEWS RELEASE | 6

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.

Product types


Product type by operating segment
			Three months ended June 30, 2024
Oil Sands
Bitumen (Mbbls/d)			591.7
Heavy crude oil (Mbbls/d)			18.1
Conventional natural gas (MMcf/d)			10.5
Total Oil Sands segment production (MBOE/d)			611.5
Conventional
Light crude oil (Mbbls/d)			5.1
Natural gas liquids (Mbbls/d)			21.4
Conventional natural gas (MMcf/d)			579.4
Total Conventional segment production (MBOE/d)			123.1
Offshore
Light crude oil (Mbbls/d)			8.4
Natural gas liquids (Mbbls/d)			11.6
Conventional natural gas (MMcf/d)			277.3
Total Offshore segment production (MBOE/d)			66.2
Total upstream production (MBOE/d)			800.8

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”, “expect”, “focus”, “progress”, “target” and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: returning Excess Free Funds Flow to shareholders; shareholder returns; safety; profitable and predictable operations; growth projects; resiliency; Net Debt; production guidance; the optimization project at Foster Creek; production at Sunrise; drilling activity and production at the Conventional Heavy Oil assets; turnaround activity at Christina Lake; planned maintenance on the SeaRose FPSO; return of the SeaRose FPSO to the White Rose Field; first production from the West White Rose project; optimizing planned turnaround activity for U.S. Refining; allocation of Excess Free Funds Flow; 2024 planned maintenance; dividend payments; and Cenovus’s 2024 corporate guidance available on cenovus.com.

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

CENOVUS ENERGY NEWS RELEASE | 7

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 2024 corporate guidance available on cenovus.com.

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, 2023.

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, 2023 and June 30, 2024, 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 sedarplus.ca, 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 Accounting Standards. Readers should not consider these measures in isolation or as a substitute for analysis of the company’s results as reported under IFRS Accounting Standards. 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 June 30, 2024 (available on SEDAR+ at sedarplus.ca, 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.

Total Operating Margin

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

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	Upstream (1)			Downstream (1)			Total
($ millions)	Q2 2024	Q1 2024	Q2 2023	Q2 2024	Q1 2024	Q2 2023	Q2 2024	Q1 2024	Q2 2023
Revenues
Gross Sales	8,715	7,864	7,285	9,053	8,567	7,427	17,768	16,431	14,712
Less: Royalties	(859)	(747)	(637)	—	—	—	(859)	(747)	(637)
	7,856	7,117	6,648	9,053	8,567	7,427	16,909	15,684	14,075
Expenses
Purchased Product	815	771	751	8,099	7,219	6,447	8,914	7,990	7,198
Transportation and Blending	3,043	2,811	2,770	—	—	—	3,043	2,811	2,770
Operating	889	898	883	1,099	787	843	1,988	1,685	1,726
Realized (Gain) Loss on Risk Management	20	6	(13)	8	1	(6)	28	7	(19)
Operating Margin	3,089	2,631	2,257	(153)	560	143	2,936	3,191	2,400

(1) Found in the June 30, 2024, or the March 31, 2024, interim Consolidated Financial Statements.

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)	Jun. 30, 2024	Mar. 31, 2024	Jun. 30, 2023
Cash From (Used in) Operating Activities (1)	2,807	1,925	1,990
(Add) Deduct:
Settlement of Decommissioning Liabilities	(48)	(48)	(41)
Net Change in Non-Cash Working Capital	494	(269)	132
Adjusted Funds Flow	2,361	2,242	1,899
Capital Investment	1,155	1,036	1,002
Free Funds Flow	1,206	1,206	897
Add (Deduct):
Base Dividends Paid on Common Shares	(334)	(262)	(265)
Dividends Paid on Preferred Shares	(9)	(9)	(9)
Settlement of Decommissioning Liabilities	(48)	(48)	(41)
Principal Repayment of Leases	(75)	(70)	(76)
Acquisitions, Net of Cash Acquired	(5)	(10)	(4)
Proceeds From Divestitures	—	25	3

Excess Free Funds Flow	735	832	505

(1) Found in the June 30, 2024, or the March 31, 2024, 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.

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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 | 10

Exhibit 99.2

Cenovus Energy Inc.

Management’s Discussion and Analysis (unaudited)

For the Periods Ended June 30, 2024

(Canadian Dollars)

MANAGEMENT’S DISCUSSION AND ANALYSIS


For the periods ended June 30, 2024


OVERVIEW OF CENOVUS						3
QUARTERLY RESULTS OVERVIEW						4
OPERATING AND FINANCIAL RESULTS						6
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS						11
OUTLOOK						15
REPORTABLE SEGMENTS						17
UPSTREAM						17
OIL SANDS						17
CONVENTIONAL						22
OFFSHORE						24
DOWNSTREAM						29
CANADIAN REFINING						29
U.S. REFINING						31
CORPORATE AND ELIMINATIONS						33
LIQUIDITY AND CAPITAL RESOURCES						35
RISK MANAGEMENT AND RISK FACTORS						40
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES						40
CONTROL ENVIRONMENT						41
ADVISORY						42
ABBREVIATIONS AND DEFINITIONS						45
SPECIFIED FINANCIAL MEASURES						46
PRIOR PERIOD REVISIONS						58

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, joint arrangements, and partnership interests held directly or indirectly by, Cenovus Energy Inc.) dated July 31, 2024, should be read in conjunction with our June 30, 2024 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2023 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2023 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as at July 31, 2024, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (“the Board”), reviewed and recommended the MD&A for approval by the Board, which occurred on July 31, 2024. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, do not constitute part of this MD&A.

Basis of Presentation

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			2



OVERVIEW OF CENOVUS

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

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

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

Our Strategy

At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five strategic objectives include: delivering top tier safety performance; maximizing value through competitive cost structures and optimizing margins; a focus on financial discipline, including reaching and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle; and the prioritization of 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 14, 2023, we released our 2024 budget focused on disciplined capital investment and balancing growth of our base business with meaningful shareholder returns. We will remain focused on safe operations, reducing costs, capital discipline and realizing the full value of our integrated business. Our 2024 corporate guidance was updated on July 31, 2024, and is available on our website at cenovus.com. For further details, see the Outlook section of this MD&A.

Our Operations

The Company operates through the following reportable segments:

Upstream Segments

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

•Conventional, includes assets rich in NGLs and natural gas 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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia.

Downstream Segments

•Canadian Refining, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			3

•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries, held through WRB Refining LP (“WRB”), a jointly owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.

Corporate and Eliminations

Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.



QUARTERLY RESULTS OVERVIEW

The second quarter’s financial and operational results reflect strong operational performance and constructive crude oil prices at our Oil Sands assets, the impact that the execution of the turnaround at the Lloydminster Upgrader (the “Upgrader”) had on our Canadian Refining segment, and increased crude oil unit throughput (“throughput”) at our U.S. Refineries, offset by the impact of the narrowing WTI-WCS differential at Hardisty and volatile market crack spreads.

•Continued focus on safety. We maintained safe operations throughout our business, and are continually striving to improve our safety record. Safety continues to be a key priority for 2024.

•Achieved our Net Debt target in July. As at June 30, 2024, our Net Debt position was $4.3 billion and in July, we reached our Net Debt target of $4.0 billion. As such, in the third quarter of 2024, we will target to allocate 100 percent of Excess Free Funds Flow to shareholder returns, adjusted for the amount Net Debt exceeded $4.0 billion, which was $258 million at June 30, 2024.

•Strong upstream production. Upstream production averaged 800.8 thousand barrels of oil equivalent per day in the second quarter, consistent with 800.9 thousand barrels of oil equivalent per day in the first quarter of 2024.

•Safely executed the Lloydminster Upgrader turnaround. From May 8 to July 4, 2024, we completed the largest turnaround in the history of the Upgrader. As a result, throughput in the Canadian Refining segment decreased 50.3 thousand barrels per day from the first quarter of 2024 to 53.8 thousand barrels per day. Total Canadian Refining operating expenses of $415 million included $211 million related to the turnaround. The Upgrader has returned to full operations.

•Improved U.S. Refining throughput. Crude throughput at our U.S. refineries was 568.9 thousand barrels per day in the quarter, an increase of 17.8 thousand barrels per day from the first quarter of 2024, due to improved crude unit reliability at our operated and non-operated refineries.

•Drove improvements to our cost structures. Per-Unit Operating Expenses at our Oil Sands and Conventional assets decreased from the first quarter of 2024. We continue to focus on reducing operating, capital and general and administrative costs.

•Progressed key Atlantic projects. The West White Rose project reached a significant milestone with the completion of major construction on two key components of the platform. The concrete gravity structure reached its final height and the last crane was installed, completing the topsides structurally. The SeaRose asset life extension (“ALE”) project continues to progress the refit work that commenced in the first quarter of 2024. The floating production, storage and offloading unit (“FPSO”) is expected to return to the White Rose field late in the third quarter of 2024, with production resuming in the fourth quarter.

•Advanced our Oil Sands growth projects. The Narrows Lake tie-back pipeline to Christina Lake is approximately 88 percent constructed and is expected to achieve mechanical completion by the end of the year. At our Sunrise asset, we began steaming two well pads, which we expect to be brought on production in the third and fourth quarters of 2024. Our Foster Creek optimization project is approximately 26 percent complete and is expected to be operational in 2026. At our Lloydminster conventional heavy oil assets, we have progressed our planned drilling program and currently have four rigs in operation.

•Loaded our first vessels at the Westridge Marine Terminal. With the successful start-up of the Trans Mountain Pipeline expansion project (“TMX”), we loaded our first vessels at the Westridge Marine Terminal and continue to ramp up our position.


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•Reported solid financial results. Adjusted funds flow increased to $2.4 billion from $2.2 billion in the first quarter of 2024, mainly due to improved benchmark prices and strong operating results. Cash flow from operating activities was $2.8 billion, an increase from $1.9 billion in the first quarter of 2024, as lower Operating Margin in the second quarter was more than offset by changes in non-cash working capital. Net earnings were $1.0 billion, a decrease of $176 million from the first quarter of 2024.

•Delivered significant cash returns to common shareholders. We returned $1.0 billion to common shareholders, composed of the purchase of 15.4 million common shares for $440 million through our normal course issuer bid (“NCIB”), $334 million through common share base dividends and $251 million through common share variable dividends. On July 31, 2024, our Board of Directors declared a third quarter base dividend of $0.180 per common share.

Summary of Quarterly Results


	Six Months Ended June 30,		2024		2023				2022
($ millions, except where indicated)	2024	2023	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3

Upstream Production Volumes (1) (MBOE/d)	800.9	754.4	800.8	800.9	808.6	797.0	729.9	779.0	806.9	777.9

Downstream Total Processed Inputs (2) (3) (Mbbls/d)	668.3	524.1	652.9	683.8	605.7	691.3	566.9	480.7	491.3	563.4

Crude Oil Unit Throughput (2) (Mbbls/d)	639.0	498.1	622.7	655.2	579.1	664.3	537.8	457.9	473.3	533.5

Downstream Production Volumes (1) (2) (Mbbls/d)	680.8	530.0	659.5	702.1	627.4	706.0	571.9	487.7	506.3	572.6

Revenues	28,282	24,493	14,885	13,397	13,134	14,577	12,231	12,262	14,063	17,471

Operating Margin (4)	6,127	4,502	2,936	3,191	2,151	4,369	2,400	2,102	2,782	3,339

Cash From (Used In) Operating Activities	4,732	1,704	2,807	1,925	2,946	2,738	1,990	(286)	2,970	4,089

Adjusted Funds Flow (4)	4,603	3,294	2,361	2,242	2,062	3,447	1,899	1,395	2,346	2,951
Per Share - Basic (4) ($)	2.47	1.73	1.27	1.20	1.10	1.82	1.00	0.73	1.22	1.53
Per Share - Diluted (4) ($)	2.45	1.69	1.26	1.19	1.09	1.81	0.98	0.71	1.19	1.49

Capital Investment	2,191	2,103	1,155	1,036	1,170	1,025	1,002	1,101	1,274	866

Free Funds Flow (4)	2,412	1,191	1,206	1,206	892	2,422	897	294	1,072	2,085

Excess Free Funds Flow (4)	n/a	n/a	735	832	471	1,989	505	(499)	786	1,756

Net Earnings (Loss)	2,176	1,502	1,000	1,176	743	1,864	866	636	784	1,609
Per Share - Basic ($)	1.16	0.78	0.53	0.62	0.39	0.98	0.45	0.33	0.40	0.83
Per Share - Diluted ($)	1.15	0.76	0.53	0.62	0.39	0.97	0.44	0.32	0.39	0.81

Total Assets	56,000	53,747	56,000	54,994	53,915	54,427	53,747	54,000	55,869	55,086

Total Long-Term Liabilities	18,945	19,831	18,945	18,884	18,993	18,395	19,831	19,917	20,259	19,378

Long-Term Debt, Including Current Portion	7,275	8,534	7,275	7,227	7,108	7,224	8,534	8,681	8,691	8,774

Net Debt	4,258	6,367	4,258	4,827	5,060	5,976	6,367	6,632	4,282	5,280

Cash Returns to Common Shareholders	1,452	815	1,025	427	722	1,225	575	240	807	864
Common Shares – Base Dividends	596	465	334	262	261	264	265	200	201	205
Base Dividends Per Common Share ($)	0.320	0.245	0.180	0.140	0.140	0.140	0.140	0.105	0.105	0.105
Common Shares – Variable Dividends	251	—	251	—	—	—	—	—	219	—
Variable Dividends Per Common Share ($)	0.135	—	0.135	—	—	—	—	—	0.114	—
Purchase of Common Shares Under NCIB	605	350	440	165	350	361	310	40	387	659
Payment for Purchase of Warrants	—	—	—	—	111	600	—	—	—	—

Preferred Share Dividends	18	27	9	9	9	—	9	18	—	9

(1)Refer to the Operating and Financial Results section of this MD&A for a summary of total production by product type.

(2)Represents Cenovus’s net interest in refining operations.

(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			5



OPERATING AND FINANCIAL RESULTS

Selected Operating and Financial Results — Upstream


	Three Months Ended June 30,			Six Months Ended June 30,
		Percent Change			Percent Change
	2024		2023	2024		2023
Production Volumes by Segment (1) (MBOE/d)
Oil Sands	611.5	7	573.8	613.4	5	581.6
Conventional	123.1	18	104.6	121.9	7	114.2
Offshore	66.2	29	51.5	65.6	12	58.6
Total Production Volumes	800.8	10	729.9	800.9	6	754.4

Production Volumes by Product
Bitumen (Mbbls/d)	591.7	7	554.6	593.5	6	562.5
Heavy Crude Oil (Mbbls/d)	18.1	6	17.0	18.0	7	16.9
Light Crude Oil (Mbbls/d)	13.5	34	10.1	13.0	2	12.7
NGLs (Mbbls/d)	33.0	24	26.7	32.8	9	30.0
Conventional Natural Gas (MMcf/d)	867.2	19	729.4	861.5	9	793.1
Total Production Volumes (MBOE/d)	800.8	10	729.9	800.9	6	754.4

Per-Unit Operating Expenses by Segment (2) ($/BOE)
Oil Sands	11.47	(10)	12.72	11.67	(13)	13.37
Conventional	11.25	(23)	14.59	12.14	(12)	13.77
Offshore (3)	22.34	15	19.48	20.03	6	18.88

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

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

(3)Reflects Cenovus’s 40 percent interest in HCML. Expenses related to the HCML joint venture are accounted for using the equity method in the interim Consolidated Financial Statements.

Total upstream production increased compared with 2023 due to:

•Three new well pads brought online throughout 2023 and one in the first quarter of 2024 at Foster Creek.

•Successful results from the 2023 redevelopment programs, new wells brought online during the year and base well optimizations at our Lloydminster thermal assets.

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

•The temporary unplanned outage in China related to the disconnection of the umbilical by a third-party vessel in April 2023.

•Turnarounds that were completed at our Foster Creek and Atlantic operations in the second quarter of 2023.

•The completion of maintenance activity at the Terra Nova FPSO and returning to the field in August 2023. Production resumed in late November 2023.

The increases were partially offset by:

•The suspended production on the SeaRose FPSO for the planned ALE project in late December 2023. The FPSO is expected to return to the White Rose field late in the third quarter of 2024, with production resuming in the fourth quarter.

Per-Unit Operating Expenses decreased in the Oil Sands segment reflecting the benefit of lower fuel operating costs as a result of significant declines in AECO benchmark prices, as well as efforts made to manage operating expenses by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations. Per-Unit Operating Expenses decreased in our Conventional segment primarily due to the divestiture of assets.


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Selected Operating and Financial Results — Downstream


	Three Months Ended June 30,			Six Months Ended June 30,
		Percent Change			Percent Change
	2024		2023	2024		2023
Crude Oil Unit Throughput by Segment (Mbbls/d)
Canadian Refining	53.8	(44)	95.3	79.0	(19)	97.0
U.S. Refining	568.9	29	442.5	560.0	40	401.1
Total Crude Oil Unit Throughput	622.7	16	537.8	639.0	28	498.1

Production Volumes by Product (1) (Mbbls/d)
Gasoline	278.3	40	199.4	280.1	45	193.2
Distillates (2)	221.5	28	173.3	217.2	34	162.0
Synthetic Crude Oil	20.7	(54)	44.8	33.9	(25)	45.2
Asphalt	40.2	7	37.4	41.0	28	32.0
Ethanol	4.4	13	3.9	4.9	9	4.5
Other	94.4	(17)	113.1	103.7	11	93.1
Total Production Volumes	659.5	15	571.9	680.8	28	530.0

Per-Unit Operating Expenses by Segment (3) ($/bbl)
Canadian Refining (4)	70.44	401	14.05	34.36	153	13.59
U.S. Refining	12.66	(21)	16.09	12.17	(28)	16.86

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

(2)Includes diesel and jet fuel.

(3)Specified financial measure. The definition of Per-Unit Operating Expense has been revised to operating expenses divided by total processed inputs. Prior periods have been re-presented. See the Specified Financial Measures Advisory of this MD&A.

(4)Represents operating expenses associated with the Lloydminster Upgrader, the Lloydminster Refinery and the commercial fuels business.

Total downstream throughput and total downstream production increased compared with 2023 due to:

•Increased throughput in the U.S. Refining segment as we realized the benefit from the purchase of the Toledo Refinery on February 28, 2023 (the “Toledo Acquisition”), which has allowed us to better use existing resources across our U.S. portfolio to improve our product mix.

•Obtaining the benefit of a full period of throughput and production at the Toledo and Superior refineries.

•Improved crude unit reliability at our operated and non-operated refineries.

The increases were partially offset by:

•The turnaround completed at the Upgrader, which significantly impacted throughput in our Canadian Refining segment.

•Planned and unplanned outages at our operated and non-operated refineries.

Canadian Refining Per-Unit Operating Expenses increased compared with 2023, primarily due to increased turnaround costs at the Upgrader and lower total processed inputs.

U.S. Refining Per-Unit Operating Expenses decreased compared with 2023, primarily due to increased total processed inputs at the Toledo and Superior refineries discussed above and total operating expenses remaining relatively consistent.

Selected Consolidated Financial Results

Revenues

Revenues increased 22 percent to $14.9 billion in the three months ended June 30, 2024, compared with 2023. Year-to-date, revenues increased 15 percent to $28.3 billion, compared with 2023. The increases for both periods were primarily due to increased total upstream production and higher crude oil benchmark pricing, combined with increased total downstream production due to obtaining the benefit of a full period of production at the Toledo and Superior refineries, offset by decreased production in the Canadian Refining segment. The increase was partially offset by lower natural gas and refined product pricing in the three and six months ended June 30, 2024, compared with the same periods in 2023.


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Operating Margin

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


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Gross Sales (1)
External Sales	15,744	12,868	29,888	25,726
Intersegment Sales	2,024	1,844	4,311	3,340
	17,768	14,712	34,199	29,066
Royalties	(859)	(637)	(1,606)	(1,233)
Revenues	16,909	14,075	32,593	27,833
Expenses
Purchased Product (1)	8,914	7,198	16,904	14,027
Transportation and Blending (1)	3,043	2,770	5,854	5,797
Operating Expenses	1,988	1,726	3,673	3,509
Realized (Gain) Loss on Risk Management Activities	28	(19)	35	(2)
Operating Margin	2,936	2,400	6,127	4,502

(1)Comparative periods reflect certain revisions. See Note 24 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 June 30, 2024 and 2023

Operating Margin increased $536 million to $2.9 billion in the three months ended June 30, 2024, compared with 2023, primarily due to:

•Higher crude oil benchmark pricing and higher sales volumes impacting our Oil Sands segment.

•Increased sales volumes and higher realized sales prices from our Offshore segment.

•Obtaining the benefit of a full period of production at the Toledo and Superior refineries.


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These increases were partially offset by:

•Lower Operating Margin in the Canadian Refining segment due to turnaround activity.

•Increased royalties in our Oil Sands segment due to higher realized prices combined with higher Alberta sliding scale oil sands royalty rates.

•Lower market crack spreads and narrower light-heavy differentials impacting our U.S. Refining segment.

•Increased transportation expenses as we ramp up our use of TMX.

Operating Margin in the Conventional segment decreased compared to 2023, primarily due to lower realized natural gas prices. The decrease was offset by reduced fuel operating costs in the Oil Sands segment on natural gas purchased from the Conventional segment.

Six Months Ended June 30, 2024 and 2023

Operating Margin increased $1.6 billion to $6.1 billion in the six months ended June 30, 2024, compared with 2023, primarily due to the reasons discussed above.

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


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Cash From (Used in) Operating Activities	2,807	1,990	4,732	1,704
(Add) Deduct:
Settlement of Decommissioning Liabilities	(48)	(41)	(96)	(89)
Net Change in Non-Cash Working Capital	494	132	225	(1,501)
Adjusted Funds Flow	2,361	1,899	4,603	3,294

Cash from operating activities increased in the second quarter of 2024, compared with the same period in 2023. The increase was primarily due to higher Operating Margin combined with changes in non-cash working capital. Changes in non-cash working capital increased cash from operating activities by $494 million in the quarter, primarily due to higher accounts payable, partially offset by higher inventory.

Cash from operating activities was $4.7 billion in the first six months of 2024, compared with $1.7 billion in 2023. The increase was primarily due to changes in non-cash working capital and higher Operating Margin. In the first half of 2023, changes in non-cash working capital decreased cash from operating activities by $1.5 billion, primarily driven by an income tax payment of $1.2 billion that occurred during the period.


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Adjusted Funds Flow was higher in the three and six months ended June 30, 2024, compared with the same periods in 2023. The quarter-over-quarter increase was primarily due to higher Operating Margin, as discussed above, partially offset by higher current income tax expense. The year-over-year increase was primarily due to higher Operating Margin, partially offset by higher current income tax expense and long-term incentive costs paid.

Net Earnings (Loss)

Net earnings in the three and six months ended June 30, 2024, was $1.0 billion and $2.2 billion, respectively, compared with $866 million and $1.5 billion, respectively, in 2023. The increase for both periods was due to higher Operating Margin, as discussed above, partially offset by higher income tax expense, increased DD&A and foreign exchange losses in 2024 compared with gains in 2023.

Net Debt


As at ($ millions)	June 30, 2024	December 31, 2023
Short-Term Borrowings	137	179

Long-Term Portion of Long-Term Debt	7,275	7,108
Total Debt	7,412	7,287
Cash and Cash Equivalents	(3,154)	(2,227)
Net Debt	4,258	5,060

Net Debt decreased by $802 million from December 31, 2023, mainly due to cash from operating activities of $4.7 billion, partially offset by capital investment of $2.2 billion, cash returns to common shareholders of $1.5 billion and the weakening of the Canadian dollar, which impacted our U.S. denominated debt. For further details, see the Liquidity and Capital Resources section of this MD&A.

Capital Investment (1)


	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2024	2023		2024	2023
Upstream
Oil Sands	613		539	1,260	1,174
Conventional	68		82	194	223
Offshore	295		184	454	284
Total Upstream	976		805	1,908	1,681
Downstream
Canadian Refining	70		34	101	61
U.S. Refining	100		153	167	347
Total Downstream	170		187	268	408
Corporate and Eliminations	9		10	15	14
Total Capital Investment	1,155		1,002	2,191	2,103

(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets and capitalized interest. Excludes capital expenditures related to the HCML joint venture.

Capital investment in the first six months of 2024 was mainly related to:

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

•The progression of the West White Rose project and the SeaRose ALE.

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

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

•Sustaining activities at our operated Canadian and U.S. refining assets, and refining reliability projects at our non-operated Wood River and Borger refineries.

•The drilling of an exploration well in China.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			10

Drilling Activity


	Net Stratigraphic Test Wells and Observation Wells		Net Production Wells (1)
Six Months Ended June 30,	2024	2023	2024	2023
Foster Creek	82	87	7	10
Christina Lake	58	53	9	11
Sunrise	40	38	—	7
Lloydminster Thermal	—	1	4	—
Lloydminster Conventional Heavy Oil	—	1	3	5
Other	—	3	—	—
	180	183	23	33

(1)Steam-assisted gravity drainage (“SAGD”) well pairs in the Oil Sands segment are counted as a single producing well.

Stratigraphic test wells were drilled to help identify future well pad locations and to further progress the evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions.

Six Months Ended June 30, 2024

Six Months Ended June 30, 2023

(net wells)

Drilled

Completed

Tied-in

Drilled

Completed

Tied-in

Conventional

In the Offshore segment, we commenced drilling one well in China in the second quarter of 2024. No wells were completed in the Offshore segment in the first six months of 2024 (2023 – drilled and completed one (0.4 net) development well at the MAC field in Indonesia).



COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

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

Selected Benchmark Prices and Exchange Rates (1)



	Six Months Ended June 30,
(Average US$/bbl, unless otherwise indicated)	2024	Percent Change	2023	Q2 2024	Q1 2024	Q2 2023
Dated Brent	84.09	5	79.83	84.94	83.24	78.39
WTI	78.77	5	74.96	80.57	76.96	73.78
Differential Dated Brent - WTI	5.32	9	4.87	4.37	6.28	4.61
WCS at Hardisty	62.30	13	55.05	66.96	57.65	58.74
Differential WTI - WCS at Hardisty	16.47	(17)	19.91	13.61	19.31	15.04
WCS at Hardisty (C$/bbl)	84.70	14	74.17	91.63	77.77	78.90
WCS at Nederland	72.29	12	64.73	74.69	69.89	66.98
Differential WTI - WCS at Nederland	6.48	(37)	10.23	5.88	7.07	6.80
Condensate (C5 at Edmonton)	74.96	(2)	76.13	77.14	72.78	72.39
Differential Condensate - WTI Premium/(Discount)	(3.81)	(426)	1.17	(3.43)	(4.18)	(1.39)
Differential Condensate - WCS at Hardisty Premium/(Discount)	12.66	(40)	21.08	10.18	15.13	13.65
Condensate (C$/bbl)	101.87	(1)	102.61	105.55	98.18	97.25
Synthetic at Edmonton	76.37	(1)	77.42	83.32	69.42	76.66
Differential Synthetic - WTI Premium/(Discount)	(2.40)	(198)	2.46	2.75	(7.54)	2.88
Synthetic at Edmonton (C$/bbl)	103.83	—	104.33	114.01	93.65	102.98

(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.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			11

Selected Benchmark Prices and Exchange Rates – Continued (1)


	Six Months Ended June 30,
(Average US$/bbl, unless otherwise indicated)	2024	Percent Change	2023	Q2 2024	Q1 2024	Q2 2023
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)	94.28	(7)	101.07	99.09	89.48	102.32
Chicago Ultra-low Sulphur Diesel (“ULSD”)	102.04	(6)	108.90	99.80	104.27	102.40
Refining Benchmarks
Upgrading Differential (2) (C$/bbl)	18.97	(36)	29.68	22.28	15.65	23.59
Chicago 3-2-1 Crack Spread (3)	18.10	(37)	28.72	18.76	17.45	28.57
Group 3 3-2-1 Crack Spread (3)	17.82	(44)	31.56	18.13	17.50	31.78
Renewable Identification Numbers (“RINs”)	3.53	(56)	7.98	3.39	3.68	7.72
Natural Gas Prices
AECO (4) (C$/Mcf)	1.84	(35)	2.83	1.18	2.50	2.45
NYMEX (5) (US$/Mcf)	2.07	(25)	2.76	1.89	2.24	2.10
Foreign Exchange Rates
US$ per C$1 - Average	0.736	(1)	0.742	0.731	0.741	0.745
US$ per C$1 - End of Period	0.731	(3)	0.755	0.731	0.738	0.755
RMB per C$1 - Average	5.311	3	5.143	5.293	5.330	5.228

(2)The upgrading differential is the difference between synthetic crude oil at Edmonton and Lloydminster Blend crude oil at Hardisty. The upgrading differential does not precisely mirror the configuration and the product output of our refineries; however, it is used as a general market indicator.

(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)New York Mercantile Exchange (“NYMEX”) natural gas monthly index.

Crude Oil and Condensate Benchmarks

In the second quarter of 2024, crude oil benchmark prices, Brent and WTI, continued to increase compared with the first quarter of 2024. OPEC+ continues to manage global oil markets and support prices with extended production cuts amid robust global demand growth for crude. Geopolitical events related to Russia and Ukraine, Israel and Gaza, Iran, the Red Sea, Venezuela and Guyana continued to add volatility in the second quarter of 2024, but have had a limited impact on global oil markets. Slowing U.S. drilling activity since the beginning of 2023 has further eased some pressure on global crude supply and demand balances.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices, and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties.

The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI differential narrowed in the second quarter of 2024 compared with the first quarter of 2024, in part due to weaker European light crude demand related to refinery turnarounds.

WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude, and the cost of transport. In the three and six months ended June 30, 2024, the WTI-WCS differential at Hardisty narrowed compared with 2023, due in part to the start-up of TMX as well as a strengthening of the heavy oil quality differential as outlined below.

WCS at Nederland is a heavy oil benchmark for sales of our product at the U.S. Gulf Coast (“USGC”). The WTI-WCS at Nederland differential is representative of the heavy oil quality differential and is influenced by global heavy oil refining capacity and global heavy oil supply. In the three and six months ended June 30, 2024, the WTI-WCS at Nederland differential narrowed compared with the same periods in 2023. Decreased global heavy and medium crude supply as a result of OPEC+ cuts and additional heavy crude processing capacity have resulted in a narrowing of the quality differential compared with 2023, which experienced wide light-heavy differentials due to unplanned refinery maintenance, high global refining utilization, rising supply of medium and heavy oil barrels into the market and volatile refined product pricing.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			12

In the second quarters of 2024 and 2023, synthetic crude oil at Edmonton was priced at a premium to WTI. Year-to-date, synthetic crude oil at Edmonton was priced at a discount to WTI. The weakness in pricing in the first quarter of 2024 was a result of high synthetic crude oil production in Alberta, an oversupply of light crude which resulted in light crude being above pipeline capacity on light crude pipelines and limited local storage capacity.

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 25 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 blended product sales.

In the second quarters of 2024 and 2023, the average Edmonton condensate benchmark traded at a discount to WTI. In the six months ended June 30, 2024, Edmonton condensate benchmark traded at a discount compared with a premium in the six months ended June 30, 2023. Weakness was primarily driven by low light crude and synthetic crude oil prices in the first quarter of 2024 in Alberta as oversupply of light crude was above pipeline takeaway capacity. Weak international naphtha demand, which impacts the price of USGC condensate that is exported to Canada, has further weighed on prices in the second quarter of 2024.

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.

Refined product prices declined in the three and six months ended June 30, 2024, compared with 2023, as incremental global capacity additions weighed on global refinery crack spreads, and U.S. refineries operated at very high utilization rates. Excess supply of refined products and large inventory builds in the U.S. Midwest pressured Chicago pricing relative to other markets in the beginning of 2024; however, this was offset by periods of relative strength due to planned and unplanned refinery maintenance in the region during the first half of 2024.

The average RINs costs were also lower in the three and six months ended June 30, 2024, compared with the same periods of 2023 due to growing renewable diesel supply.

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 reflect the differential between Brent and WTI benchmark prices.

Our refining margins are affected by various other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the feedstock is valued on a first in, first out (“FIFO”) accounting basis. The market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as a general market indicator.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			13

Natural Gas Benchmarks

In the three and six months ended June 30, 2024, average NYMEX and AECO natural gas prices decreased compared with 2023, due to high U.S. supply, a mild winter and high levels of inventory. AECO prices weakened further relative to NYMEX natural gas due to limited Western Canadian takeaway capacity. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.

Foreign Exchange Benchmarks

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

In the three and six months ended June 30, 2024, on average, the Canadian dollar weakened relative to the U.S. dollar, compared with the same periods of 2023, positively impacting our reported revenues. The Canadian dollar weakened relative to the U.S. dollar as at June 30, 2024, compared with December 31, 2023, resulting in unrealized foreign exchange impacts on the translation of our U.S. dollar debt.

A portion of our long-term sales contracts in the Asia Pacific region are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. In the three and six months ended June 30, 2024, on average, the Canadian dollar strengthened relative to RMB, compared with the same periods 2023, negatively impacting our reported revenues.

Interest Rate Benchmarks

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

As at June 30, 2024, the Bank of Canada’s Policy Interest Rate was 4.75 percent. On July 24, 2024, the Bank of Canada reduced the overnight rate by 25 basis points to 4.50 percent.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			14



OUTLOOK

Commodity Price Outlook

Global crude oil prices increased quarter over quarter, as continued extensions of OPEC+ production cuts have supported prices. The current voluntary cuts have been extended to the end of the third quarter of 2024 and the group has indicated plans to gradually unwind voluntary cuts over 12 months starting October 2024. Non-OPEC+ supply growth, led by U.S. shale, has been robust and is expected to continue to grow through 2024, though slowing U.S. drilling activity since 2023 has softened the expectations for U.S. supply growth modestly. Demand growth has also been strong, boosted by Chinese consumption. With global crude oil supply and demand balances tight, and high Middle East spare production capacity, OPEC+ policy remains crucial to global oil balances and prices. Current geopolitical risks are causing volatility in global oil prices, with any escalation causing global oil prices to rise and any de-escalation causing prices to settle.

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. 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 the strategic petroleum reserve, the crisis in Israel and Gaza including any spread to a wider conflict, Iran, attacks on vessels in the Red Sea, and tensions between Venezuela and Guyana. In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession, remain a risk to the pace of demand growth.

Refined product prices have declined from elevated levels in 2022 and 2023 as a result of incremental global capacity additions and U.S. refineries operating at very high utilization rates. This has led to storage of gasoline and diesel increasing from low levels. Utilization is expected to remain high through the peak demand summer months, keeping refining margins steady.

In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:

•We expect the WTI-WCS at Hardisty differential will remain largely tied to global supply factors and heavy crude oil processing capacity, as long as supply stays within Canadian crude oil export capacity. As expected, the start-up of TMX in 2024 is having a narrowing impact on WTI-WCS differentials.

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

•NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and ample natural gas in storage. Weather will continue to be a key driver of demand and impact prices.

•We expect the Canadian dollar to continue to be impacted by the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, crude oil prices 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 integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane and used as crude oil feedstock by our downstream operations, and condensate extracted from our blended crude oil is sold back to our Oil Sands operations.

Our refining capacity is focused in the U.S. Midwest, along with smaller exposures in the USGC and Alberta, exposing Cenovus to 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.

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

•Traditional crude oil storage tanks in various geographic locations.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			15

Key Priorities for 2024

Our 2024 priorities are focused on top tier safety performance, returns to shareholders target, project execution, and a continued focus on cost and sustainability improvements.

Top Tier Safety Performance

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

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. In July, we achieved our Net Debt target of $4.0 billion. As a result, we will target to allocate 100 percent of Excess Free Funds Flow in the third quarter to shareholder returns through share buybacks and/or variable dividends, reduced by the amount by which Net Debt exceeds $4.0 billion at the applicable previous quarter’s end. For further details, see the Liquidity and Capital Resources section of this MD&A.

Project Execution

Investing in future growth is a focus for us, with several key projects in flight, including the West White Rose project, the SeaRose FPSO ALE project, the Narrows Lake tie-back to Christina Lake, and the Sunrise and Foster Creek optimization projects. In addition, we have a number of information system upgrades underway in 2024. We plan to execute these multi-year projects on time and on budget.

Cost Leadership

We aim to maximize shareholder value through continued focus on cost structures and margin optimization. We are focused on reducing operating, capital and general and administrative costs, realizing the full value of our integrated strategy while making decisions that support long-term value for Cenovus.

We will continue to target improved reliability of our downstream assets leveraging our upstream expertise to maximize the long-term profitability of our assets.

Sustainability

Sustainability is central to Cenovus’s culture. We have established ambitious targets in our five environmental, social and governance (“ESG”) focus areas and continue to allocate resources and progress tangible plans to meet these targets.

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

2024 Corporate Guidance

Our 2024 guidance, as updated on July 31, 2024, is available on our website at cenovus.com.

Changes to our updated guidance include:

•An increase at the midpoint of total Upstream production due to strong year-to-date performance and reliability.

•An increase at the midpoint of total Downstream throughput due to strong year-to-date performance and optimization of turnaround activities in the second half of the year, including a turnaround that was deferred to 2025.

The following table is a sub-set of our full guidance for 2024:


	Capital Investment ($ millions)	Production (MBOE/d)	Crude Oil Unit Throughput (Mbbls/d)
Upstream
Oil Sands	2,500 - 2,750	600 - 610
Conventional	350 - 425	120 - 125
Offshore	850 - 950	65 - 75
Upstream Total	3,700 - 4,125	785 - 810

Downstream	750 - 850		640 - 670

Corporate and Eliminations	60 - 70


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			16

We continue to execute our capital program and there have been no changes to our full year expected capital investment range of $4.5 billion to $5.0 billion. This includes $3.0 billion directed towards sustaining production and supporting continued safe and reliable operations, and between $1.5 billion and $2.0 billion in optimization and growth capital.



REPORTABLE SEGMENTS

UPSTREAM

Oil Sands

In the second quarter of 2024, we:

•Delivered safe and reliable operations.

•Produced 609.8 thousand barrels of crude oil per day (2023 – 571.6 thousand barrels of crude oil per day).

•Delivered successful results from our sustaining, redevelopment and base well optimization programs at our Foster Creek, Christina Lake, Sunrise and Lloydminster thermal assets.

•Generated Operating Margin of $2.7 billion, an increase of $712 million, compared with the second quarter of 2023, primarily due to higher realized sales prices and lower operating expenses.

•Invested capital of $613 million primarily for sustaining activities and growth projects. Sustaining activities include the drilling of stratigraphic test wells as part of our integrated winter program. Growth projects include the tie-back of Narrows Lake to Christina Lake and optimization projects at Foster Creek and Sunrise.

•Earned a Netback of $52.10 per BOE (2023 – $38.49 per BOE).

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Gross Sales (1)
External Sales	6,056	5,177	11,069	10,009
Intersegment Sales	1,497	1,260	3,112	2,135
	7,553	6,437	14,181	12,144
Royalties	(814)	(620)	(1,511)	(1,136)
Revenues	6,739	5,817	12,670	11,008
Expenses
Purchased Product (1)	403	414	692	769
Transportation and Blending	2,953	2,700	5,686	5,641
Operating	615	676	1,275	1,413
Realized (Gain) Loss on Risk Management	20	(9)	33	(1)
Operating Margin	2,748	2,036	4,984	3,186
Unrealized (Gain) Loss on Risk Management	1	31	(12)	(3)
Depreciation, Depletion and Amortization	772	730	1,546	1,445
Exploration Expense	1	2	4	4
(Income) Loss from Equity-Accounted Affiliates	(14)	6	(14)	6
Segment Income (Loss)	1,988	1,267	3,460	1,734


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			17

Operating Margin Variance

Three Months Ended June 30, 2024

Six Months Ended June 30, 2024

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

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

Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
	2024	2023	2024	2023
Total Sales Volumes (1) (MBOE/d)	584.5	578.1	595.6	577.5

Realized Sales Price (2) (3) ($/BOE)	88.76	71.03	80.62	63.37

Crude Oil Production by Asset (Mbbls/d)
Foster Creek	195.0	167.0	195.5	178.4
Christina Lake	237.1	234.9	236.8	236.0
Sunrise	46.1	46.5	47.4	45.5
Lloydminster Thermal	113.5	106.2	113.8	102.6
Lloydminster Conventional Heavy Oil	18.1	17.0	18.0	16.9
Total Crude Oil Production (4) (Mbbls/d)	609.8	571.6	611.5	579.4
Natural Gas (5) (MMcf/d)	10.5	12.9	11.2	12.7
Total Production (MBOE/d)	611.5	573.8	613.4	581.6

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

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

(3)Comparative periods reflect certain revisions. See Note 24 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

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

(5)Conventional natural gas product type.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			18

Operating Results – Continued


	Three Months Ended June 30,		Six Months Ended June 30,
	2024	2023	2024	2023














Effective Royalty Rate (1) (percent)
Foster Creek	21.1	21.9	22.9	22.5
Christina Lake	25.9	24.6	25.5	27.0
Sunrise	7.3	5.4	5.8	5.2
Lloydminster (2)	11.2	9.3	9.2	8.9
Total Effective Royalty Rate	19.4	18.7	19.4	19.8

Transportation and Blending Expense (3) ($/BOE)	9.98	8.04	8.74	8.55

Operating Expense (3) ($/BOE)	11.47	12.72	11.67	13.37

Per-Unit DD&A (3) ($/BOE)	13.68	13.00	13.51	12.87

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

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

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

Revenues

Gross sales increased for the three and six months ended June 30, 2024, compared with 2023, due to higher WTI benchmark prices, a narrowing of the WTI-WCS differential at Hardisty and increased sales volumes.

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.

For the three and six months ended June 30, 2024, approximately 29 percent and 26 percent, respectively, of our crude oil sales volumes were sold at U.S. destinations. For both the three and six months ended June 30, 2024, approximately 20 percent of our Oil Sands crude oil sales volumes were sold to our Canadian and U.S. downstream operations.

Our realized sales price averaged $88.76 per BOE and $80.62 per BOE, respectively, in the three and six months ended June 30, 2024, (2023 – $71.03 per BOE and $63.37 per BOE, respectively), mainly due to higher WTI benchmark prices, narrower WTI-WCS and condensate-WCS differentials.

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

Production Volumes

In the three and six months ended June 30, 2024, Oil Sands crude oil production was 609.8 thousand barrels per day and 611.5 thousand barrels per day, respectively, (2023 – 571.6 thousand barrels per day and 579.4 thousand barrels per day, respectively) mainly due to increases at our Foster Creek and Lloydminster thermal assets, while production volumes remained relatively consistent at our other Oil Sands assets.

Production at Foster Creek increased by 28.0 thousand barrels per day and 17.1 thousand barrels per day in the three and six months ended June 30, 2024, respectively, compared with 2023. The increases were primarily due to three new well pads that were brought online in 2023, one new pad brought online in the first quarter of 2024, and successful results from our redevelopment program. In addition, we had a turnaround in the second quarter of 2023.

Production from our Lloydminster thermal assets increased 7.3 thousand barrels per day and 11.2 thousand barrels per day in the three and six months ended June 30, 2024, respectively, compared with 2023. The increases were primarily due to successful results from the 2023 redevelopment program and base well optimizations.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			19

Royalties

Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Saskatchewan.

Our Alberta oil sands royalty projects (Foster Creek, Christina Lake and Sunrise) are based on government prescribed pre- and post-payout royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.

Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.

Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales revenues less diluent costs and transportation costs. Net revenues are calculated as sales revenues less diluent costs, transportation costs, and allowed operating and capital costs.

Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.

For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes each project's Crown and freehold split. For Crown royalties, the pre-payout calculation is based on one percent of product revenues and the post-payout calculation is based on 20 percent of operating margin. The freehold calculation is limited to post-payout projects and is based on an eight percent rate.

Oil Sands royalties increased compared with 2023. For the three months ended June 30, 2024, the Oil Sands effective royalty rate increased to 19.4 percent from 18.7 percent in 2023, primarily due to higher realized prices combined with higher Alberta sliding scale oil sands royalty rates. For the six months ended June 30, 2024, the Oil Sands effective royalty rate decreased to 19.4 percent from 19.8 percent in 2023, primarily due to annual adjustments on the end-of-period filings.

Expenses

Transportation and Blending

In the second quarter of 2024, blending expenses increased $159 million to $2.4 billion compared with 2023, due to higher condensate prices and higher sales volumes. In the first half of 2024, blending expenses increased $17 million to $4.7 billion compared with 2023, due to higher sales volumes partially offset by lower condensate prices.

Transportation expenses increased in the three months ended June 30, 2024, due to higher sales volumes exported to destinations outside of Alberta compared with 2023. In the quarter, we started to ramp up our position on TMX, which resulted in higher transportation expenses.

Per-Unit Transportation Expenses

Per-unit transportation expenses increased in the three and six months ended June 30, 2024, compared with the same periods in 2023, due to higher transportation expenses discussed above, partially offset by higher sales volumes.

At Foster Creek, per-unit transportation expenses were $14.69 per barrel and $12.42 per barrel in the three and six months ended June 30, 2024, respectively (2023 – $12.80 per barrel and $13.13 per barrel, respectively). The quarter-over-quarter increase was primarily due to higher transportation expenses as we ramp up the use of TMX, partially offset by higher sales volumes. The year-over-year decrease was primarily due to lower sales to destinations outside of Alberta and an increase in sales volumes, partially offset by increased TMX expenses as discussed above. In the three and six months ended June 30, 2024, we shipped 49 percent and 41 percent, respectively (2023 – 47 percent and 48 percent, respectively) of our volumes from Foster Creek to destinations outside of Alberta.

At Christina Lake, per-unit transportation expenses were $7.16 per barrel and $6.23 per barrel in the three and six months ended June 30, 2024, respectively (2023 – $5.91 per barrel and $6.81 per barrel, respectively). The quarter-over-quarter increase was primarily due to higher sales to U.S. destinations and increased tariff rates, partially offset by lower rail costs. The year-over-year decrease was primarily due to lower rail costs. In the three and six months ended June 30, 2024, we shipped 23 percent and 17 percent, respectively (2023 – 17 percent and 18 percent, respectively) of our volumes from Christina Lake to U.S. destinations.

At Sunrise, per-unit transportation expenses increased in the three and six months ended June 30, 2024, compared with 2023, primarily due to higher transportation costs for the use of TMX and higher sales outside of Alberta. In both the three and six months ended June 30, 2024, we shipped 94 percent (2023 – 50 percent and 48 percent, respectively) of our volumes from Sunrise to destinations outside of Alberta.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			20

At Lloydminster, per-unit transportation expenses increased in the three and six months ended June 30, 2024, mainly due to higher tariff rates for higher sales volumes being sent to U.S. destinations, compared with 2023. In the three and six months ended June 30, 2024, we shipped six percent and five percent, respectively, to U.S. destinations (2023 – nil for both periods).

Operating

Primary drivers of our operating expenses in the first six months of 2024 were fuel, workforce and repairs and maintenance. Total operating expenses decreased due to lower fuel costs as a result of significant declines in AECO benchmark prices in the three and six months ended June 30, 2024, compared with 2023. The decreases were partially offset by higher GHG compliance costs and repairs and maintenance costs. We have experienced some inflationary pressures on our costs; however, we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.

Per-Unit Operating Expenses (1)


	Three Months Ended June 30,			Six Months Ended June 30,
($/BOE)	2024	Percent Change	2023	2024	Percent Change	2023
Foster Creek
Fuel	1.95	(43)	3.40	2.60	(39)	4.27
Non-Fuel	8.11	(8)	8.81	7.84	(6)	8.34
Total	10.06	(18)	12.21	10.44	(17)	12.61
Christina Lake
Fuel	1.91	(31)	2.77	2.36	(28)	3.26
Non-Fuel	6.58	24	5.32	6.14	15	5.34
Total	8.49	5	8.09	8.50	(1)	8.60
Sunrise
Fuel	3.04	(33)	4.52	3.61	(34)	5.49
Non-Fuel	10.13	(21)	12.86	11.30	(19)	14.00
Total	13.17	(24)	17.38	14.91	(23)	19.49
Lloydminster (2)
Fuel	2.25	(43)	3.97	3.20	(35)	4.91
Non-Fuel	15.56	(5)	16.33	14.73	(12)	16.73
Total	17.81	(12)	20.30	17.93	(17)	21.64

Total Oil Sands
Fuel	2.10	(38)	3.36	2.72	(33)	4.09
Non-Fuel	9.37	—	9.36	8.95	(4)	9.28
Total	11.47	(10)	12.72	11.67	(13)	13.37

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

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

Per-unit fuel expenses decreased overall due to lower natural gas prices as discussed above.

Foster Creek per-unit non-fuel expenses decreased in the three and six months ended June 30, 2024, compared with 2023, due to increased sales volumes, partially offset by increased repairs and maintenance costs, workover activity and GHG compliance costs.

Christina Lake per-unit non-fuel expenses increased in the three and six months ended June 30, 2024, compared with 2023, due to increased repairs and maintenance costs, workover activity and decreased sales volumes.

Sunrise per-unit non-fuel expenses decreased in the three and six months ended June 30, 2024, compared with 2023, due to increased sales volumes, partially offset by increased repairs and maintenance costs.

Lloydminster per-unit non-fuel expenses decreased in the three and six months ended June 30, 2024, compared with 2023, due to increased sales volumes, combined with lower workover activity and chemical costs partially offset by increased GHG compliance costs.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			21

Netbacks (1)


	Three Months Ended June 30,		Six Months Ended June 30,
($/BOE)	2024	2023	2024	2023
Sales Price	88.76	71.03	80.62	63.37
Royalties	15.21	11.78	13.88	10.87
Transportation and Blending	9.98	8.04	8.74	8.55
Operating Expenses	11.47	12.72	11.67	13.37
Netback	52.10	38.49	46.33	30.58

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

Conventional

In the second quarter of 2024, we:

•Delivered safe and reliable operations.

•Produced 123.1 thousand BOE per day (2023 – 104.6 thousand BOE per day).

•Generated Operating Margin of $42 million, a decrease of $31 million from the second quarter of 2023.

•Invested capital of $68 million with a continued focus on drilling, completion, tie-in and infrastructure projects.

•Averaged a Netback of $3.68 per BOE (2023 – $5.89 per BOE).

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023

Gross Sales (1)
External Sales	264	253	641	875
Intersegment Sales	427	367	929	782
	691	620	1,570	1,657
Royalties	(22)	(4)	(46)	(58)
Revenues	669	616	1,524	1,599
Expenses
Purchased Product (1)	412	337	894	820
Transportation and Blending (1)	83	66	161	147
Operating	132	144	285	294
Realized (Gain) Loss on Risk Management	—	(4)	(7)	4
Operating Margin	42	73	191	334
Unrealized (Gain) Loss on Risk Management	2	(1)	8	(21)
Depreciation, Depletion and Amortization	111	87	221	182

(Income) Loss From Equity-Accounted Affiliates	—	—	1	—
Segment Income (Loss)	(71)	(13)	(39)	173

Operating Margin Variance

Three Months Ended June 30, 2024


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			22

Six Months Ended June 30, 2024

(1)Changes to price include the impact of realized risk management gains and losses.

(2)Reflects Operating Margin from processing facilities.

Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
	2024	2023	2024	2023
Total Sales Volumes (MBOE/d)	123.1	104.6	121.9	114.2

Realized Sales Price (1) (2) ($/BOE)	22.20	25.09	27.50	35.29
Light Crude Oil ($/bbl)	98.12	104.40	92.96	103.48
NGLs ($/bbl)	56.29	46.59	56.86	47.39
Conventional Natural Gas ($/Mcf)	1.77	2.63	2.87	4.71

Production by Product
Light Crude Oil (Mbbls/d)	5.1	4.8	5.2	5.6
NGLs (Mbbls/d)	21.4	18.0	21.7	20.0
Conventional Natural Gas (MMcf/d)	579.4	491.4	569.9	531.9
Total Production (MBOE/d)	123.1	104.6	121.9	114.2

Conventional Natural Gas Production (percentage of total)	78	78	78	78
Crude Oil and NGLs Production (percentage of total)	22	22	22	22

Effective Royalty Rate (3) (percent)	12.4	2.5	11.0	11.5

Transportation Expense (2) (4) ($/BOE)	5.25	4.08	4.97	4.05

Operating Expense (4) ($/BOE)	11.25	14.59	12.14	13.77

Per-Unit DD&A (4) ($/BOE)	9.88	9.01	9.89	8.76

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

(2)Comparative periods reflect certain revisions. See Note 24 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.

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

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

Revenues

For the three and six months ended June 30, 2024, gross sales were $691 million and $1.6 billion, respectively (2023 – $620 million and $1.7 billion, respectively). The quarter-over-quarter increase was due to increased sales volumes offset by a decline in natural gas benchmark pricing. The year-over-year decrease was primarily due to a decline in natural gas benchmark pricing, partially offset by increased sales volumes.

Price

Our total realized sales price decreased primarily due to lower natural gas benchmark prices. For the three and six months ended June 30, 2024, the AECO benchmark price declined 52 percent and 35 percent, respectively, compared with the same periods in 2023.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			23

Production Volumes

For the three and six months ended June 30, 2024, production volumes increased 18.5 thousand BOE per day and 7.7 thousand BOE per day, respectively, compared with the same periods in 2023. The increases were largely driven by the successful restart of operations following wildfire activity in May and June of 2023 that temporarily shut-in production, partially offset by the divestiture of certain Clearwater and Edson assets in the first quarter of 2024.

Royalties

The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties increased quarter-over-quarter mainly due to higher production volumes, partially offset by lower natural gas benchmark pricing and the divestiture of certain assets discussed above. Royalties decreased year-over-year due to lower natural gas benchmark prices and the divestiture of certain assets, as discussed above, which more than offset the increase in production volumes.

Expenses

Transportation

Our transportation expenses reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. In the three and six months ended June 30, 2024, transportation expenses increased primarily due to increased tariff rates, compared with 2023. The per-unit transportation expenses increased due to higher transportation expenses, partially offset by increased sales volumes.

Operating

Primary drivers of operating expenses in the first six months of 2024 were repairs and maintenance, workforce and property tax costs. In the three and six months ended June 30, 2024, total operating expenses decreased $12 million and $9 million, respectively, compared with the same periods in 2023, primarily due to the divestiture of assets discussed above. Operating expenses per BOE decreased $3.34 per BOE quarter-over-quarter and $1.63 year-over-year, due to lower costs and higher sales volumes.

Netbacks (1)


	Three Months Ended June 30,		Six Months Ended June 30,
($/BOE)	2024	2023	2024	2023
Sales Price (2)	22.20	25.09	27.50	35.29
Royalties	2.02	0.53	2.09	2.84
Transportation and Blending (2)	5.25	4.08	4.97	4.05
Operating Expenses	11.25	14.59	12.14	13.77
Netback	3.68	5.89	8.30	14.63

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

Offshore

In the second quarter of 2024, we:

•Delivered safe and reliable operations.

•Produced 66.2 thousand BOE per day of light crude oil, NGLs and natural gas (2023 – 51.5 thousand BOE per day).

•Generated Operating Margin of $299 million, an increase of $151 million from the second quarter of 2023, mainly due to higher sales volumes in the Atlantic region and in China, and higher Brent benchmark pricing.

•Earned a Netback of $54.33 per BOE (2023 – $45.11 per BOE).

•Invested capital of $295 million, mainly related to the progression of the West White Rose project, SeaRose ALE project and commenced drilling an exploration well in China.

In late December 2023, we suspended production at the White Rose field as we prepared for the planned SeaRose ALE project. Refit work commenced in the first quarter of 2024 and continues to progress. The SeaRose FPSO is expected to return to the White Rose field late in the third quarter of 2024, with production resuming in the fourth quarter.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			24

In the second quarter of 2024, the West White Rose project reached a significant milestone with the completion of major construction on two key components of the platform. The concrete gravity structure reached its final height, and the last crane was installed, completing the topsides structurally. The focus will now be on interior completion and commissioning of the structures. The West White Rose project was approximately 80 percent complete as at June 30, 2024. Since our decision in 2022 to restart the project, we have invested approximately $984 million. First oil is expected in 2026.

Financial Results


	Three Months Ended June 30,
	2024			2023
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	151	320	471	5	223	228
Intersegment Sales	—	—	—	—	—	—
	151	320	471	5	223	228
Royalties	1	(24)	(23)	(1)	(12)	(13)
Revenues	152	296	448	4	211	215
Expenses
Transportation and Blending	7	—	7	4	—	4
Operating	110	32	142	26	37	63
Operating Margin (1)	35	264	299	(26)	174	148
Depreciation, Depletion and Amortization			156			91
Exploration Expense			4			2
(Income) Loss from Equity-Accounted Affiliates			(13)			(12)
Segment Income (Loss)			152			67

(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 June 30, 2024


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			25

Financial Results


	Six Months Ended June 30,
	2024			2023
($ millions)	Atlantic	Asia Pacific	Offshore	Atlantic	Asia Pacific	Offshore
Gross Sales
External Sales	193	635	828	154	547	701
Intersegment Sales	—	—	—	—	—	—
	193	635	828	154	547	701
Royalties	(1)	(48)	(49)	(9)	(30)	(39)
Revenues	192	587	779	145	517	662
Expenses
Transportation and Blending	7	—	7	9	—	9
Operating	167	60	227	143	62	205
Operating Margin (1)	18	527	545	(7)	455	448
Depreciation, Depletion and Amortization			287			219
Exploration Expense			8			4
(Income) Loss from Equity-Accounted Affiliates			(23)			(18)
Segment Income (Loss)			273			243

(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

Six Months Ended June 30, 2024

Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
	2024	2023	2024	2023
Sales Volumes
Atlantic (Mbbls/d)	14.8	—	9.4	7.8
Asia Pacific (MBOE/d)
China	43.5	31.2	43.6	37.2
Indonesia (1)	14.3	15.0	14.2	14.3
Total Asia Pacific	57.8	46.2	57.8	51.5
Total Sales Volumes (MBOE/d)	72.6	46.2	67.2	59.3

Realized Sales Price (1) (2) ($/BOE)	83.38	73.12	79.75	79.51

Atlantic - Light Crude Oil ($/bbl)	112.74	—	113.02	108.73

Asia Pacific (1) ($/BOE)	75.87	71.86	74.36	75.07
NGLs ($/bbl)	102.45	84.95	99.52	91.43
Conventional Natural Gas ($/Mcf)	11.53	11.47	11.40	11.85

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

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			26

Operating Results – Continued


	Three Months Ended June 30,		Six Months Ended June 30,
	2024	2023	2024	2023
















Production by Product
Atlantic - Light Crude Oil (Mbbls/d)	8.4	5.3	7.8	7.1
Asia Pacific (1)
NGLs (Mbbls/d)	11.6	8.7	11.1	10.0
Conventional Natural Gas (MMcf/d)	277.3	225.1	280.4	248.5
Total Asia Pacific (MBOE/d)	57.8	46.2	57.8	51.5
Total Production (MBOE/d)	66.2	51.5	65.6	58.6

Effective Royalty Rate (2) (percent)
Atlantic	(0.6)	—	0.5	5.3
Asia Pacific (1)	9.5	10.1	8.6	10.1

Operating Expense (3) ($/BOE)	22.34	19.48	20.03	18.88
Atlantic	79.03	—	95.82	85.02
Asia Pacific (1)	7.84	10.96	7.74	8.82

Per-Unit DD&A (3) ($/BOE)	22.90	25.31	22.70	25.81

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

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

Revenues

For the three and six months ended June 30, 2024, gross sales increased to $471 million and $828 million, respectively (2023 – $228 million and $701 million, respectively). The increases were due to an increase in sales volumes and an increase in realized sales price due to higher Brent benchmark pricing.

Price

Our Atlantic realized sales price on light crude oil increased in the three and six months ended June 30, 2024, primarily due to higher Brent benchmark pricing. The price we receive for natural gas sold in Asia Pacific is set under long-term contracts.

Production Volumes

Atlantic production increased 3.1 thousand BOE per day and 0.7 thousand BOE per day in the three and six months ended June 30, 2024, compared with 2023, primarily due to resuming production at the Terra Nova FPSO in November 2023, partially offset by the suspension of production at the White Rose field in December 2023 for the SeaRose ALE project. Light crude oil production from the White Rose and Terra Nova fields are offloaded from the SeaRose FPSO and the Terra Nova FPSO, respectively, to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales.

Asia Pacific production increased 11.6 thousand BOE per day and 6.3 thousand BOE per day in the three and six months ended June 30, 2024, respectively, compared with 2023. The increases were due to higher gas and NGL production in China following a temporary unplanned outage in second quarter of 2023, related to the disconnection of the umbilical by a third-party vessel, and first gas production at the MAC field in Indonesia in September 2023. The increases were partially offset by lower production in Indonesia due to lower gas demand and the timing of condensate lifts in the first half of 2024.

Royalties

In the second quarter of 2024, Atlantic royalties reflected a credit received for the 2023 White Rose annual royalty filing.

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 six months ended June 30, 2024, declined to 9.5 percent and 8.6 percent, respectively (2023 – 10.1 percent and 10.1 percent, respectively). The quarter-over-quarter decrease was primarily due to lower sales volumes in Indonesia. The year-over-year decrease was primarily due to a production bonus paid to the Government of Indonesia for achieving a production milestone in the first quarter of 2023, partially offset by a consumption tax implemented in China in June 2023, which contributed to an increase in the NGL royalty rate.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			27

Expenses

Transportation

Transportation expenses include the costs of transporting crude oil from the Terra Nova and SeaRose FPSO units to onshore via tankers, as well as storage costs. Transportation expenses in the three and six months ended June 30, 2024, were $7 million and $7 million, respectively (2023 – $4 million and $9 million, respectively). In the first six months of 2024, transportation costs were lower compared with 2023, due to a nominal recovery in the first quarter of 2024.

Operating

Primary drivers of our Atlantic operating expenses in the first six months of 2024 were repairs and maintenance, costs related to vessels and air services and workforce. In the second quarter of 2024, operating expenses increased by $84 million, compared with 2023, primarily due to increased sales volumes and costs related to the SeaRose ALE project. Operating expenses in the first six months of 2024 increased by $24 million, compared with 2023, primarily due to reasons discussed above. The increase was partially offset by costs related to the restart of the West White Rose project during the first half of 2023. Per-unit operating expenses increased in the three and six months ended June 30, 2024, compared with 2023, mainly due to an increase in operating expenses as discussed above, partially offset by increased sales volumes.

Primary drivers of our China operating expenses in the first six months of 2024 were repairs and maintenance, insurance and workforce costs. In the three and six months ended June 30, 2024, operating expenses decreased by $5 million and $2 million, respectively, compared with 2023, primarily due to additional costs incurred in the second quarter of 2023 related to the umbilical repair. Per-unit operating expenses associated with our assets in China decreased in the three and six months ended June 30, 2024, compared with 2023, due to decreased operating expenses as discussed above, and increased sales volumes. Per-unit operating expenses associated with our Indonesian assets increased in the three and six months ended June 30, 2024, compared with 2023. The MAC field was fully operational in the third quarter of 2023, which increased repairs and maintenance, and workforce expenses.

Netbacks (1)


	Three Months Ended June 30, 2024
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Sales Price		112.74	80.95		60.43		83.38
Royalties		(0.72)	6.20		10.17		5.57
Transportation and Blending		5.60	—		—		1.14
Operating Expenses		79.03	7.24		9.68		22.34
Netback		28.83	67.51		40.58		54.33


	Three Months Ended June 30, 2023
($/BOE, except where indicated)	Atlantic (3) ($/bbl)		China	Indonesia		Total Offshore (2)

Sales Price		—	78.48		58.05		73.12
Royalties		—	4.23		13.60		7.47
Transportation and Blending		—	—		—		1.06
Operating Expenses		—	11.91		8.98		19.48
Netback		—	62.34		35.47		45.11

(1)Contains 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. The HCML joint venture is accounted for using the equity method in the interim Consolidated Financial Statements.

(3)No sales volumes from our Atlantic operations in the second quarter of 2023.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			28

Netbacks – Continued (1)


	Six Months Ended June 30, 2024
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Sales Price		113.02	80.08		56.77		79.75
Royalties		0.50	6.10		7.17		5.54
Transportation and Blending		3.97	—		—		0.55
Operating Expenses		95.82	6.76		10.76		20.03
Netback		12.73	67.22		38.84		53.63


	Six Months Ended June 30, 2023
($/BOE, except where indicated)	Atlantic ($/bbl)		China	Indonesia		Total Offshore (2)

Sales Price		108.73	81.37		58.72		79.51
Royalties		6.14	4.44		15.83		7.42
Transportation and Blending		6.31	—		—		0.83
Operating Expenses		85.02	8.26		10.26		18.88
Netback		11.26	68.67		32.63		52.38

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

DOWNSTREAM

Canadian Refining

In the second quarter of 2024, we:

•Delivered safe operations and safely executed the largest turnaround at the Upgrader in its history.

•Had throughput of 53.8 thousand barrels per day and crude unit utilization of 50 percent (2023 – 95.3 thousand barrels per day and 88 percent, respectively).

•Incurred operating expenses of $415 million, including turnaround costs of $211 million.

•Recorded a negative Operating Margin of $255 million, compared with a positive Operating Margin of $116 million in the second quarter of 2023.

•Invested capital of $70 million.

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2024	2023	2024	2023
Gross Sales
External Sales	1,037	1,151	2,200	2,453
Intersegment Sales	98	212	267	418
Revenues	1,135	1,363	2,467	2,871
Purchased Product	975	1,083	2,062	2,176
Gross Margin (1)	160	280	405	695
Expenses
Operating	415	164	592	316
Operating Margin	(255)	116	(187)	379
Depreciation, Depletion and Amortization	54	43	98	86
Segment Income (Loss)	(309)	73	(285)	293

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			29

Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2024	2023	2024	2023
Operable Capacity (1) (Mbbls/d)	108.0	108.0	108.0	108.0

Total Processed Inputs (2) (Mbbls/d)	58.9	102.7	83.8	104.2

Crude Oil Unit Throughput (Mbbls/d)	53.8	95.3	79.0	97.0

Crude Unit Utilization (3) (percent)	50	88	73	90

Total Production (Mbbls/d)	64.0	108.3	90.1	110.6
Synthetic Crude Oil	20.7	44.8	33.9	45.2
Asphalt	14.0	15.3	14.8	15.5
Diesel	5.2	12.4	9.0	12.4
Other	19.7	31.9	27.5	33.0
Ethanol	4.4	3.9	4.9	4.5

Refining Margin (4) ($/bbl)	25.21	26.54	23.57	33.56

(1)Operable capacity is the capacity based on barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. We previously reported crude oil name plate capacity.

(2)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

(3)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.

(4)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader, commercial fuels business and the Lloydminster Refinery for the three and six months ended June 30, 2024, were $1.1 billion and $2.3 billion, respectively (2023 – $1.3 billion and $2.7 billion, respectively).

In the second quarter of 2024, we safely executed the largest turnaround in the history of the Upgrader, which ran from May 8 to July 4, 2024, with crude re-introduced in the first week of July. The turnaround significantly decreased throughput and increased operating expenses in the quarter.

In the six months ended June 30, 2024, throughput decreased, largely due to the turnaround, as discussed above, offset by high reliability in the first quarter of 2024.

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 are seasonal and increase during paving season, which typically runs from May through October each year.

The Upgrader and Lloydminster Refinery source crude oil feedstock from our Oil Sands segment. In the three and six months ended June 30, 2024, approximately seven percent and 10 percent, respectively, of total crude oil sales volumes from our Oil Sands assets were sold to our Canadian Refining segment (three and six months ended June 30, 2023 – 13 percent).

For the three and six months ended June 30, 2024, revenues decreased $228 million and $404 million compared with the same periods in 2023, primarily due to lower refined product production. In the three months ended June 30, 2024, lower refined product production was offset by increased synthetic crude oil benchmark prices compared with 2023. In the six months ended June 30, 2024, synthetic crude oil benchmark prices were relatively consistent with the same period in 2023.

Gross Margin was $160 million and $405 million in the three and six months ended June 30, 2024, respectively. The decreases from the comparative periods in 2023 were primarily due to lower refined product production, partially offset by higher feedstock costs driven by the increase in the WTI benchmark price and the narrowing of the WTI-WCS differential at Hardisty. The WTI-WCS differential at Hardisty narrowed in the three and six month periods by 10 percent and 17 percent, respectively, compared with the same periods in 2023.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			30

Operating Expenses


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2024	2023	2024	2023
Operating Expenses (1)	377	131	524	256
Operating Expenses - Turnaround Costs	211	—	226	—

Per-Unit Operating Expenses (1) (2) ($/bbl)	70.44	14.05	34.36	13.59
Per-Unit Operating Expenses - Turnaround Costs (2)	39.52	—	14.83	—

(1)Represents operating expenses associated with the Lloydminster Upgrader, the Lloydminster Refinery and the commercial fuels business.

(2)Specified financial measure. The definition of Per-Unit Operating Expense has been revised to operating expenses divided by total processed inputs. Prior periods have been re-presented. The definition of Per-Unit Operating Expense – Turnaround Costs is operating expenses – turnaround costs divided by total processed inputs. See the Specified Financial Measures Advisory of this MD&A.

Primary drivers of operating expenses were turnaround costs, repairs and maintenance, and workforce costs.

Operating expenses for the three and six months ended June 30, 2024, were largely composed of turnaround expenses of $211 million and $226 million, respectively (three and six months ended June 30, 2023 – $nil). Operating expenses in the second quarter also increased due to other projects that were completed during the turnaround period.

Per-unit operating expenses are calculated as operating expenses divided by total processed inputs. Total processed inputs reflect the overall inputs required to produce refined products in our refineries, and is used as the denominator in our per-unit measures. Per-Unit Operating Expenses increased in the three and six months ended June 30, 2024, compared with 2023, due to the Upgrader turnaround which increased costs and reduced total processed inputs.

U.S. Refining

In the second quarter of 2024, we:

•Had crude throughput of 568.9 thousand barrels per day (2023 – 442.5 thousand barrels per day), and achieved crude unit utilization of 93 percent (2023 – 72 percent).

•Generated an Operating Margin of $102 million, an increase of $75 million from the second quarter of 2023.

•Invested capital of $100 million, primarily focused on sustaining activities at the Toledo, Lima and Superior refineries, and refining reliability projects at the Wood River and Borger refineries.

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2024	2023	2024	2023
Gross Sales (1)
External Sales	7,916	6,059	15,150	11,688
Intersegment Sales	2	5	3	5
Revenues	7,918	6,064	15,153	11,693
Purchased Product (1)	7,124	5,364	13,256	10,262
Gross Margin (2)	794	700	1,897	1,431
Expenses

Operating	684	679	1,294	1,281
Realized (Gain) Loss on Risk Management	8	(6)	9	(5)
Operating Margin	102	27	594	155
Unrealized (Gain) Loss on Risk Management	(10)	(5)	(2)	(11)
Depreciation, Depletion and Amortization	112	102	223	205
Segment Income (Loss)	—	(70)	373	(39)

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			31

Operating Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2024	2023	2024	2023
Operable Capacity (1) (Mbbls/d)	612.3	612.3	612.3	612.3

Total Processed Inputs (2) (Mbbls/d)	594.0	464.2	584.5	419.9

Crude Oil Unit Throughput (Mbbls/d)	568.9	442.5	560.0	401.1
Heavy Crude Oil	219.4	155.1	222.1	161.5
Light/Medium Crude Oil	349.5	287.4	337.9	239.6

Crude Unit Utilization (3) (4) (percent)	93	72	91	68

Total Production (Mbbls/d)	595.5	463.6	590.7	419.4
Gasoline	278.3	199.4	280.1	193.2
Distillates (5)	216.3	160.9	208.2	149.6
Asphalt	26.2	22.1	26.2	16.5
Other	74.7	81.2	76.2	60.1

Refining Margin (6) ($/bbl)	14.69	16.57	17.83	18.83
Weighted Average Crack Spread, Net of RINs (7) (US$/bbl)	15.25	21.47	14.52	21.31
Weighted Average Crack Spread, Net of RINs (7) (C$/bbl)	20.86	28.82	19.72	28.72
Market Capture (4) (6) (8) (percent)	70	57	90	66

(2)Total processed inputs include crude oil and other feedstocks. Blending is excluded.

(3)Crude unit utilization is calculated as crude oil unit throughput divided by operable capacity. Prior periods have been re-presented to align with this calculation.

(4)The Superior Refinery’s operable capacity is included in the metrics effective April 1, 2023. The Toledo Refinery includes a weighted average operable capacity in the metrics, as full ownership of the Toledo Refinery was acquired on February 28, 2023.

(5)Includes diesel and jet fuel.

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

(7)Weighted average crack spread, net of RINs is calculated as Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads net of RINs. Average foreign exchange rates per period are used in conversion to Canadian dollars.

(8)The definition of Market Capture is Refining Margin divided by the weighted average crack spread, net of RINs, expressed as a percentage.

In the three months ended June 30, 2024, U.S. Refining throughput increased 126.4 thousand barrels per day and total refined product production increased 131.9 thousand barrels per day, compared with 2023. These increases primarily related to the Toledo Refinery’s return to full operations in June 2023 and the continued ramp-up at the Superior Refinery in the second quarter of 2023. Other factors that impacted total throughput and total refined product production include:

•Improved crude unit reliability at our operated and non-operated refineries.

•A number of planned and unplanned outages at our operated and non-operated refineries, which partially offset the increases in throughput discussed above.

In the first half of 2024, U.S. Refining throughput increased 158.9 thousand barrels per day and refined product production increased 171.3 thousand barrels per day, from the same period in 2023. The increases were primarily due to obtaining the benefit of a full period of operations from the Toledo Acquisition, combined with the other factors discussed above. In addition, early in the year, we increased throughput and refined product production to take advantage of favourable market conditions.

Revenues, Gross Margin and Market Capture

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. Some of these factors include the type of crude oil feedstock processed, refinery configuration and the proportion of gasoline, distillates and secondary product output, the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the refineries, and the cost of feedstock. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued on a FIFO accounting basis.

Revenues increased $1.9 billion and $3.5 billion, respectively, in the three and six months ended June 30, 2024, compared with 2023, primarily due to higher refined product production, offset by lower refined product pricing. Average benchmark gasoline and diesel prices decreased in the three and six months ended June 30, 2024, compared with the same periods in 2023.

For the three and six months ended June 30, 2024, the Chicago 3-2-1 crack spread decreased 34 percent and 37 percent, respectively, to US$18.76 per barrel and US$18.10 per barrel, respectively, from the same periods in 2023. The Group 3 crack spread decreased 43 percent and 44 percent to US$18.13 per barrel and US$17.82 per barrel, respectively, in the three and six months ended June 30, 2024, compared with 2023.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			32

In the three and six months ended June 30, 2024, Gross Margin increased $94 million and $466 million, respectively, compared with 2023, primarily due to higher crude throughput, the benefit of processing feedstock purchased at lower prices in prior periods and the benefits from weaker RINs pricing. The increase was partially offset by lower market crack spreads and higher heavy crude feedstock costs driven by the increase in the WCS benchmark price and the narrowing of the WTI-WCS differential at Hardisty. The WTI-WCS differential at Hardisty narrowed in the three and six month periods by 10 percent and 17 percent, respectively, compared with the same periods in 2023.

Market Capture is the Refining Margin generated as a percentage of the average market crack spread, net of RINs, weighted by operable capacity, calculated on a FIFO basis of accounting. Both the Chicago and Group 3 3-2-1 market crack spreads are relevant for our refining assets. As such, Market Capture has been determined based on an operable capacity-weighted average of these benchmark market crack spreads. For the three and six months ended June 30, 2024, Market Capture was 70 percent and 90 percent, respectively (2023 – 57 percent and 66 percent, respectively).

Operating Expenses


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions, except where indicated)	2024	2023	2024	2023
Operating Expenses	684	679	1,294	1,281
Operating Expenses - Turnaround Costs	58	26	92	43

Per-Unit Operating Expenses (1) ($/bbl)	12.66	16.09	12.17	16.86
Per-Unit Operating Expenses - Turnaround Costs (1)	1.08	0.63	0.87	0.56

(1)Specified financial measure. The definition of Per-Unit Operating Expense has been revised to operating expenses divided by total processed inputs. Prior periods have been re-presented. The definition of Per-Unit Operating Expense – Turnaround Costs is operating expenses – turnaround costs divided by total processed inputs. See the Specified Financial Measures Advisory of this MD&A.

Primary drivers of operating expenses are repairs and maintenance, workforce and turnaround costs.

In the three months ended June 30, 2024, operating expenses remained relatively consistent compared with 2023, due to increases in routine operating expenses related to operations at the Toledo Refinery and higher turnaround expenses. The increases were offset by higher repairs and maintenance costs and project costs as the Toledo Refinery ramped up in the second quarter of 2023.

Turnaround expenses increased in the quarter in preparation for the turnaround at the Lima Refinery combined with a turnaround at our non-operated Borger Refinery, which was smaller in scope than the turnaround at our non-operated Wood River Refinery in 2023.

Operating expenses were relatively consistent in the six months ended June 30, 2024, compared with the same period in 2023, due to higher turnaround expenses, as discussed above, and an increase in workforce costs due to the Toledo Acquisition, offset by a decrease in repairs and maintenance expenses and project costs.

Per-unit operating expenses are calculated as operating expenses divided by total processed inputs. Per-unit operating expenses decreased in the three and six months ended June 30 2024, compared with the same periods in 2023, due to the increase in total processed inputs with the ramp-up of the Superior Refinery in the second quarter of 2023 and the Toledo Refinery returning to full operations in June 2023.

CORPORATE AND ELIMINATIONS

Financial Results


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Realized (Gain) Loss on Risk Management	—	(4)	3	3
Unrealized (Gain) Loss on Risk Management	—	21	30	51
General and Administrative	175	167	421	325
Finance Costs, Net (1)	141	159	276	320
Integration, Transaction and Other Costs	39	17	72	37
Foreign Exchange (Gain) Loss, Net	55	(119)	154	(126)
(Gain) Loss on Divestiture of Assets (1)	1	(10)	(104)	22
Re-measurement of Contingent Payments	2	(1)	30	16
Other (Income) Loss, Net	(40)	(14)	(130)	(20)

(1)Revised presentation as of January 1, 2024. Refer to Note 3 of the interim Consolidated Financial Statements for further detail.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			33

General and Administrative

Primary drivers of our general and administrative expenses in the first half of 2024 were workforce costs and information technology costs. General and administrative expenses increased in the three and six months ended June 30, 2024, compared with 2023, primarily due to non-cash stock-based compensation costs of $34 million and $135 million, respectively (2023 – $29 million and $45 million, respectively).

Finance Costs, Net

Finance costs were lower in the three and six months ended June 30, 2024, compared with the same periods in 2023, due to lower interest expense as a result of the Company’s lower long-term debt. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.

The annualized weighted average interest rate on outstanding debt for the three and six months ended June 30, 2024, was 4.49 percent and 4.48 percent, respectively (2023 – 4.70 and 4.72 percent, respectively).

Integration, Transaction and Other Costs

In the three and six months ended June 30, 2024, we incurred costs of $39 million and $72 million, respectively, largely related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company.

In the three and six months ended June 30, 2023, we incurred integration and transaction costs of $17 million and $37 million, respectively, related to the Toledo Acquisition.

Foreign Exchange (Gain) Loss, Net


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Unrealized Foreign Exchange (Gain) Loss	85	(172)	209	(158)
Realized Foreign Exchange (Gain) Loss	(30)	53	(55)	32
	55	(119)	154	(126)

Unrealized foreign exchange losses were mainly related to the translation of U.S. denominated debt caused by a weaker Canadian dollar. Realized foreign exchange gains were primarily related to working capital.

(Gain) Loss on Divestiture of Assets

For the six months ended June 30, 2024, we recorded gains on asset divestitures of $104 million (2023 – loss of $22 million). On February 6, 2024, we closed a transaction with Athabasca Oil Corporation to create Duvernay Energy Corporation, in which we hold a 30 percent interest, and recorded a before-tax gain of $65 million on the transaction. On March 6, 2024, we closed the sale of certain Clearwater assets in our Conventional segment for net proceeds of $19 million and recorded a before-tax gain of $36 million.

Re-measurement of Contingent Payments

In connection with the acquisition of the remaining 50 percent interest in the Sunrise Oil Sands Partnership from bp Canada Energy Group ULC (“bp Canada”) on August 31, 2022, 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 13 of the interim Consolidated Financial Statements for further details.

The variable payment is accounted for as a financial option with changes in fair value recognized in net earnings (loss). As at June 30, 2024, the fair value of the remaining variable payment was estimated to be $40 million, resulting in non-cash re-measurement losses in the three and six months ended June 30, 2024, of $2 million and $30 million, respectively (2023 – gains of $1 million and losses of $16 million, respectively).

For the six months ended June 30, 2024, we paid $157 million for the quarters ended November 30, 2023, and February 29, 2024 (2023 – $134 million). The payment of $104 million for the quarter ended May 31, 2024, was made on July 30, 2024. The payments are recognized in cash from (used in) investing activities. As at June 30, 2024, the average estimated WCS forward pricing for the remaining term of the variable payment was $91.87 per barrel. The maximum payment over the remaining term of the contract is $40 million.

Other (Income) Loss, Net

For the six months ended June 30, 2024, other income was primarily related to the receipt of business interruption insurance proceeds for the Toledo Refinery.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			34

Income Taxes


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Current Tax
Canada	300	199	646	457
United States	(9)	(17)	2	—
Asia Pacific	56	38	100	84
Other International	8	6	17	12
Total Current Tax Expense (Recovery)	355	226	765	553
Deferred Tax Expense (Recovery)	(46)	(44)	(78)	(414)
	309	182	687	139

For the six months ended June 30, 2024, we recorded current tax expense related to operations in all jurisdictions in which we operate. The increase in current tax expense was due to higher earnings compared with the same period in 2023. The effective tax rate in the first six months of 2024 was 24.0 percent (2023 – 8.5 percent). The lower effective tax rate in the first half of 2023 reflects the impact of the step-up in the tax basis on the Toledo Acquisition.

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


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Cash From (Used In)
Operating Activities	2,807	1,990	4,732	1,704
Investing Activities	(1,170)	(1,159)	(2,305)	(2,914)
Net Cash Provided (Used) Before Financing Activities	1,637	831	2,427	(1,210)
Financing Activities	(912)	(639)	(1,589)	(1,074)
Effect of Foreign Exchange on Cash and Cash Equivalents	29	(74)	89	(73)
Increase (Decrease) in Cash and Cash Equivalents	754	118	927	(2,357)

			June 30,	December 31,
As at ($ millions)			2024	2023
Cash and Cash Equivalents			3,154	2,227
Total Debt			7,412	7,287


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			35

Cash From (Used in) Operating Activities

For the three months ended June 30, 2024, cash from operating activities was $2.8 billion, compared with $2.0 billion in the same period in 2023. The increase was primarily due to higher Operating Margin combined with changes in non-cash working capital. Changes in non-cash working capital increased cash from operating activities by $494 million in the quarter, primarily due to higher accounts payable, partially offset by higher inventory.

For the six months ended June 30, 2024, cash from operating activities was $4.7 billion, compared with $1.7 billion in the same period in 2023. The increase was primarily due to changes in non-cash working capital and higher Operating Margin. In the first half of 2023, changes in non-cash working capital decreased cash from operating activities by $1.5 billion, primarily driven by an income tax payment of $1.2 billion, that occurred during the period.

Cash From (Used in) Investing Activities

Cash used in investing activities increased in the second quarter of 2024 due to a planned increase in capital investment compared with 2023.

Cash used in investing activities decreased in the first half of 2024 compared with 2023, due to the Toledo Acquisition in the first quarter of 2023.

Cash From (Used in) Financing Activities

Cash used in financing activities increased in the three and six months ended June 30, 2024, compared with the same periods in 2023. The increases were primarily due to cash returns to common shareholders of $1.0 billion and $1.5 billion, compared with $575 million and $815 million, respectively, in the same periods of 2023.

Working Capital

Excluding the current portion of the contingent payments, our adjusted working capital at June 30, 2024, was $4.7 billion (December 31, 2023 – $3.7 billion). The increase in working capital was driven by an increase in cash, accounts receivable and inventory, partially offset by an increase in accounts payable. The increases were primarily driven by higher crude oil prices.

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 capital allocation framework.


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Cash From (Used in) Operating Activities	2,807	1,990	4,732	1,704
(Add) Deduct:
Settlement of Decommissioning Liabilities	(48)	(41)	(96)	(89)
Net Change in Non-Cash Working Capital	494	132	225	(1,501)
Adjusted Funds Flow	2,361	1,899	4,603	3,294
Capital Investment	1,155	1,002	2,191	2,103
Free Funds Flow	1,206	897	2,412	1,191
Add (Deduct):
Base Dividends Paid on Common Shares	(334)	(265)
Dividends Paid on Preferred Shares	(9)	(9)
Settlement of Decommissioning Liabilities	(48)	(41)
Principal Repayment of Leases	(75)	(76)
Acquisitions, Net of Cash Acquired	(5)	(4)
Proceeds From Divestitures	—	3

Excess Free Funds Flow	735	505


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			36

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 $4.0 billion. Our $4.0 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, which we believe is approximately US$45.00 per barrel.

Our shareholder return framework is to deliver incremental value to shareholders through share buybacks and/or variable dividends as follows:

•When Net Debt is above $9.0 billion at quarter-end, we target to allocate 100 percent of the following quarter’s Excess Free Funds Flow to deleveraging the balance sheet.

•When Net Debt is less than $9.0 billion and above $4.0 billion at quarter-end, we target to allocate 50 percent of the following quarter’s Excess Free Funds Flow to shareholder returns, while continuing to deleverage the balance sheet until we achieve the Net Debt target.

•When we achieve our Net Debt target, to increase clarity and predictability of returns to shareholders, we will target to allocate 100 percent of each subsequent quarter’s Excess Free Funds Flow to shareholder returns through share buybacks and/or variable dividends, reduced by the amount Net Debt exceeds $4.0 billion at the applicable previous quarter’s end.

In order to efficiently manage working capital and cash, the allocation of Excess Free Funds Flow to shareholder returns in any of the scenarios described above may be accelerated, deferred or reallocated between quarters, while maintaining our target to, over time, allocate 100 percent of Excess Free Funds Flow to shareholder returns and sustain Net Debt at $4.0 billion.

As at March 31, 2024, our long-term debt was $7.2 billion, and our Net Debt position was $4.8 billion. Therefore, our returns to shareholders target for the three months ended June 30, 2024, was 50 percent of the current quarter’s Excess Free Funds Flow of $735 million. Our target return was $368 million, which was exceeded through share buybacks of $440 million.


	Three Months Ended
($ millions)	June 30, 2024	March 31, 2024
Excess Free Funds Flow	735	832

Target Return	368	416
Purchase of Common Shares Under NCIB	(440)	(165)
Amount Available for Variable Dividend	—	251

As at June 30, 2024, our Net Debt position was $4.3 billion and in July, we achieved our Net Debt target of $4.0 billion. Therefore, in the third quarter of 2024, we will target to allocate 100 percent of Excess Free Funds Flow to shareholder returns through share buybacks and/or variable dividends, adjusted for the amount Net Debt exceeded $4.0 billion at the previous quarter end, which was $258 million as at June 30, 2024. As previously noted, we may accelerate, defer or reallocate any quarter’s allocation of Excess Free Funds Flow to effectively manage working capital and cash.

Short-Term Borrowings

As at June 30, 2024, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$100 million (C$137 million) (December 31, 2023 – US$135 million (C$179 million)). There were no direct borrowings on our uncommitted demand facilities as at June 30, 2024, or as at December 31, 2023.

Long-Term Debt, Including Current Portion

Long-term debt, including the current portion, as at June 30, 2024, was $7.3 billion (December 31, 2023 – $7.1 billion). This includes U.S. dollar denominated unsecured notes of US$3.8 billion, or C$5.2 billion (December 31, 2023 – US$3.8 billion, or C$5.0 billion) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2023 – $2.0 billion).

As at June 30, 2024, we were in compliance with all of the terms of our debt agreements.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			37

Available Sources of Liquidity

The following sources of liquidity are available as at June 30, 2024:

($ millions)

Maturity

Amount Available

Cash and Cash Equivalents

n/a

3,154

Committed Credit Facility (1)

Revolving Credit Facility – Tranche A

June 26, 2028

3,300

Revolving Credit Facility – Tranche B

June 26, 2027

2,200

Uncommitted Demand Facilities

Cenovus Energy Inc. (2)

n/a

1,116

WRB (3)

n/a

171

(1)As at June 30, 2024, no amount was drawn on the credit facility (December 31, 2023 – $nil).

(2)Represents amounts available for cash draws. Our uncommitted demand facilities include $1.7 billion, of which $1.4 billion may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at June 30, 2024, there were outstanding letters of credit aggregating to $319 million (December 31, 2023 – $364 million) and no direct borrowings (December 31, 2023 – $nil).

(3)Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at June 30, 2024, US$100 million (C$137 million) of this capacity was drawn (December 31, 2023 – US$135 million (C$179 million)).

On June 26, 2024, Cenovus renewed its existing committed credit facility to extend the maturity dates by more than one year. The committed credit facility consists of a $2.2 billion tranche maturing on June 26, 2027, and a $3.3 billion tranche maturing on June 26, 2028. As at June 30, 2024, no amount was drawn on the credit facility (December 31, 2023 – $nil).

Under the terms of our committed credit facility, we are required to maintain a debt to capitalization ratio, as defined in the debt agreements, not to exceed 65 percent. We are below this limit.

Base Shelf Prospectus

We have a base shelf prospectus that allows us to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, Total Debt, the Net Debt to Adjusted EBITDA ratio, Net Debt to Adjusted Funds Flow ratio and Net Debt to Capitalization ratio. Refer to Note 12 of the interim Consolidated Financial Statements for further details.

We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents, and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholder’s Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA ratio, as net earnings (loss) before finance costs, net, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, (gain) loss on divestiture of assets, re-measurement of contingent payments and net other (income) loss calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and are measures of our overall financial strength.


As at	June 30, 2024	December 31, 2023
Net Debt to Adjusted EBITDA Ratio (times)	0.4	0.5
Net Debt to Adjusted Funds Flow Ratio (times)	0.4	0.6
Net Debt to Capitalization Ratio (percent)	12	15

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$45.00 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 Adjusted Funds Flow ratio and Net Debt to Adjusted EBITDA ratio as at June 30, 2024, decreased compared with December 31, 2023, as a result of lower Net Debt and higher Operating Margin. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			38

Our Net Debt to Capitalization ratio as at June 30, 2024, decreased compared with December 31, 2023, primarily due to lower Net Debt.

Share Capital and Stock-Based Compensation Plans

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

As at June 30, 2024, there were approximately 1,856.6 million common shares outstanding (December 31, 2023 – 1,871.9 million common shares) and 36 million preferred shares outstanding (December 31, 2023 – 36 million preferred shares). Refer to Note 16 of the interim Consolidated Financial Statements for further details.

As at June 30, 2024, there were approximately 5.0 million Cenovus Warrants outstanding (December 31, 2023 – 7.6 million Cenovus Warrants). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years from the date of issue at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to Note 16 of the interim Consolidated Financial Statements for further details.

Refer to Note 18 of the interim Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows:


As at July 29, 2024	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	1,856,102	n/a
Cenovus Warrants	4,985	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	9,358	5,050
Other Stock-Based Compensation Plans	17,446	1,712

Common Share Dividends

In the second quarter of 2024, we paid base dividends of $334 million or $0.180 per common share (2023 – $265 million or $0.140 per common share). In the first six months of 2024, we paid base dividends of $596 million or $0.320 per common share (2023 – $465 million or $0.245 per common share).

On July 31, 2024, the Board of Directors declared a third quarter base dividend of $0.180 per common share. The dividend is payable on September 27, 2024, to common shareholders of record as at September 13, 2024.

In the second quarter, we paid variable dividends of $251 million or $0.135 per common share. No variable dividend was declared or paid in the second quarter of 2023.

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

Cumulative Redeemable Preferred Share Dividends

For the three and six months ended June 30, 2024, dividends of $9 million and $18 million, respectively, were paid on the series 1, 2, 3, 5 and 7 preferred shares (2023 – $9 million and $27 million, respectively). On July 31, 2024, the Board declared a third quarter dividend on the series 1, 2, 3, 5 and 7 preferred shares for a total of $9 million, payable on October 1, 2024, to preferred shareholders of record as at September 13, 2024.

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

Share Repurchases

We have an NCIB program to purchase up to 133.2 million common shares from November 9, 2023, to November 8, 2024.


	Three Months Ended June 30,		Six Months Ended June 30,
	2024	2023	2024	2023
Common Shares Purchased and Cancelled Under NCIB (millions of common shares)	15.4	14.0	22.8	15.6
Weighted Average Price per Common Share ($)	27.88	22.08	26.07	22.43
Purchase of Common Shares Under NCIB ($ millions)	(440)	(310)	(605)	(350)


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			39

From July 1, 2024, to July 29, 2024, the Company purchased an additional 656 thousand common shares for $18 million. As at July 29, 2024, the Company can further purchase up to 99.2 million common shares under the NCIB.

Contractual Obligations and Commitments

We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from our total commitments disclosed below. For further information, see Note 23 to the interim Consolidated Financial Statements.

Our total commitments were $28.3 billion as at June 30, 2024 (December 31, 2023 – $28.8 billion), of which $24.9 billion are for various transportation and storage commitments and $225 million are for product purchase commitments. Transportation commitments include $683 million that are subject to regulatory approval or were approved, but are not yet in service. Terms are up to 20 years on commencement, and should help align with the Company’s future transportation requirements.

As at June 30, 2024, our total commitments included commitments with HMLP of $2.0 billion related to long-term transportation and storage commitments.

As at June 30, 2024, outstanding letters of credit issued as security for performance under certain contracts totaled $319 million (December 31, 2023 – $364 million).

Legal Proceedings

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

Transactions with Related Parties

Cenovus holds a 40 percent interest in the jointly controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture are recorded in (income) loss from equity-accounted affiliates.

For the six months ended June 30, 2024, the Company received $53 million of distributions from HCML (2023 – $38 million) and paid $nil in contributions (2023 – $24 million).

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 six months ended June 30, 2024, we charged HMLP $69 million for construction and management services (2023 – $63 million).

We pay an access fee to HMLP for the use of its pipeline systems that are used by our blending business. We also pay HMLP for transportation and storage services. Payments for access fees and transportation and storage services are made based on rates contractually agreed to with HMLP. For the six months ended June 30, 2024, we incurred costs of $140 million for the use of HMLP’s pipeline systems, as well as for transportation and storage services (2023 – $138 million).



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 2023 annual MD&A.

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



CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, as well as use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2023.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			40

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, 2023.

Update to Accounting Policies

As of January 1, 2024, the Company updated its accounting policies to aggregate certain items presented in the Consolidated Statements of Comprehensive Income (Loss) to more appropriately reflect the integrated operations of the business. There were no re-measurements to balances. Certain historical disaggregated balances continue to be presented in Note 1 of the interim Consolidated Financial Statements.

The following presentation changes were made, with comparative periods being re-presented:

•Gross sales and royalties were aggregated and presented as ‘Revenues’.

•Purchased product and transportation and blending were aggregated and presented as ‘Purchased Product, Transportation and Blending’.

•Depreciation, depletion and amortization, and exploration expense were aggregated and presented as ‘Depreciation, Depletion, Amortization and Exploration Expense’.

•Finance costs and interest income were aggregated and presented as ‘Finance Costs, Net’.

•Revaluation (gain) loss and (gain) loss on divestiture of assets were aggregated and presented as ‘(Gain) Loss on Divestiture of Assets’.

New Accounting Standards and Interpretations Not Yet Adopted

On April 9, 2024, the IASB issued IFRS 18, “Presentation and Disclosure in Financial Statements” (“IFRS 18”), which will replace International Accounting Standard 1, “Presentation of Financial Statements”. IFRS 18 will establish a revised structure for the Consolidated Statements of Comprehensive Income (Loss) and improve comparability across entities and reporting periods.

IFRS 18 is effective for annual periods beginning on or after January 1, 2027. The standard is to be applied retrospectively, with certain transition provisions. The Company is currently evaluating the impact of adopting IFRS 18 on the Consolidated Financial Statements.

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



CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at June 30, 2024. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at June 30, 2024.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			41



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”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “may”, “objective”, “opportunities”, “plan”, “position”, “priority”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our five strategic objectives; shareholder value and returns; safety; sustainability; our commitment to the Pathways Alliance foundational project; maximizing value; financial discipline; disciplined capital allocation; Free Funds Flow; cash flow volatility and stability; managing our balance sheet; liquidity; growth of our base business; capital investment; our 2024 corporate guidance; reducing costs; realizing the full value of our integrated business; reinvesting in our business; diversifying our portfolio; capitalizing on opportunities; Net Debt; allocating Excess Free Funds Flow; project execution; reliable operations; being best in class operators; maintaining a strong balance sheet; costs; margins; realizing the full value of our integrated business; long term-value for Cenovus; downstream reliability and profitability; in respect of the White Rose project, returning the SeaRose FPSO to the field, resuming production and achieving first oil; ramping up TMX; our five ESG focus areas; variable payments; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; cash flow volatility and stability; Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; capitalizing on opportunities throughout the commodity price cycle; Net Debt to Adjusted EBITDA ratio; maintaining sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar 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 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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			42

judgments; the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company’s ability to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability to complete acquisitions and divestitures, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; 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 2024 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.

2024 guidance dated July 31, 2024, and available on cenovus.com, assumes: Brent prices of US$83.50 per barrel, WTI prices of US$79.00 per barrel; WCS of US$63.00 per barrel; Differential WTI-WCS of US$15.90 per barrel; AECO natural gas prices of $1.65 per Mcf; Chicago 3-2-1 crack spread of US$17.40 per barrel; and an exchange rate of $0.73 US$/C$.

The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and divestitures; the Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of ESG targets and ambitions and the commercial viability and scalability of ESG strategies and related technology and products; the development and execution of implementing strategies to meet ESG targets and ambitions; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; 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 refining processes; the occurrence of unexpected events resulting in operational interruptions, including at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, and catastrophic events, including, but not limited to, war, adverse sea conditions, extreme weather events, natural disasters, acts of activism, vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying refining or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			43

business, including potential cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and the Company’s ability to attract and retain, critical and diverse talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets, 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.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			44

ABBREVIATIONS AND DEFINITIONS

Abbreviations

The following abbreviations and definitions are used in this document:

Crude Oil and NGLs

Natural Gas

Other

bbl

barrel

Mcf

thousand cubic feet

BOE

barrel of oil equivalent

Mbbls/d

thousand barrels per day

MMcf

million cubic feet

MBOE

thousand barrels of oil
equivalent

WCS

Western Canadian Select

MMcf/d

million cubic feet per day

MBOE/d

thousand barrels of oil
equivalent per day

WTI

West Texas Intermediate

DD&A

depreciation, depletion and
amortization

ESG

environmental, social and
governance

GHG

greenhouse gas

FPSO

Floating production, storage and
offloading unit

NCIB

normal course issuer bid

AECO

Alberta Energy Company

NYMEX

New York Mercantile Exchange

OPEC

Organization of Petroleum
Exporting Countries

OPEC+

OPEC and a group of 11
non-OPEC members

SAGD

steam-assisted gravity drainage

USGC

U.S. Gulf Coast

Revision of Operational Metrics

Following changes to our downstream portfolio in recent years, we undertook a review of our downstream disclosures with the intent of enhancing the performance reporting of our refining operations and increasing comparability with peers. As a result of this review, we have introduced the following new, and/or revised, operational metrics to our Canadian Refining and our U.S. Refining segments.

•Total processed inputs is a new measure that reflects the overall inputs required to produce refined products in our refineries, and is used as the denominator in our per-unit measures, replacing crude oil unit throughput.

•Market capture is a new measure in our U.S. Refining segment that reflects Refining Margin generated as a percentage of the weighted average crack spread, net of RINs, on a FIFO basis of accounting. The weighted average crack spread, net of RINs is calculated on Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.

•Operable capacity is the capacity based on barrels per calendar day. It is the amount of input that a distillation facility can process under usual operating conditions. Operable capacity has replaced crude oil unit throughput capacity, which was based on barrels per stream day and represents the amount of input that a distillation facility can process under optimal crude and product slate conditions, with no allowance for downtime.

•Crude unit utilization is crude oil unit throughput divided by operable capacity, expressed as a percentage. Previously this measure was calculated using crude oil unit throughput capacity.

The table below details the operable capacity and crude oil unit throughput capacity as at December 31, 2023, and is provided to illustrate the magnitude of the revised metrics detailed above:


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

Definitions and reconciliations of certain Specified Financial Measures, such as Refining Margin, Market Capture, Per-Unit Operating Expenses and Per-Unit Operating Expenses – Turnaround Costs are included in the Specified Financial Measures section of this MD&A.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			45

SPECIFIED FINANCIAL MEASURES

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS Accounting Standards including Operating Margin, Operating Margin by asset, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Gross Margin, Refining Margin, Market Capture, Realized Sales Price and Netbacks (including the total Netback per BOE).

These measures may not be comparable to similar measures presented by other issuers. These measures are described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation, or as a substitute for, measures prepared in accordance with IFRS Accounting Standards. The definition and reconciliation, if applicable, of each specified financial measure is presented in this Advisory and may also be presented in the Operating and Financial Results or Liquidity and Capital Resources sections of this MD&A. Refer to the Specified Financial Measures Advisory of the relevant period’s MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow, Realized Sales Price and Netbacks for prior period information from 2024 and 2023 that is not found below.

Operating Margin

Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for Upstream or Downstream operations are specified financial measures. These are used to provide a consistent measure of the cash generating performance of our operations and assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending expenses, operating expenses, plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.

Operating Margin


	Three Months Ended June 30,
	2024	2023	2024	2023	2024	2023
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales (2)
External Sales	6,791	5,658	8,953	7,210	15,744	12,868
Intersegment Sales	1,924	1,627	100	217	2,024	1,844
	8,715	7,285	9,053	7,427	17,768	14,712
Royalties	(859)	(637)	—	—	(859)	(637)
Revenues	7,856	6,648	9,053	7,427	16,909	14,075
Expenses
Purchased Product (2)	815	751	8,099	6,447	8,914	7,198
Transportation and Blending (2)	3,043	2,770	—	—	3,043	2,770
Operating	889	883	1,099	843	1,988	1,726
Realized (Gain) Loss on Risk Management	20	(13)	8	(6)	28	(19)
Operating Margin	3,089	2,257	(153)	143	2,936	2,400

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			46


	Six Months Ended June 30,
	2024	2023	2024	2023	2024	2023
($ millions)	Upstream (1)		Downstream (1)		Total
Gross Sales (2)
External Sales	12,538	11,585	17,350	14,141	29,888	25,726
Intersegment Sales	4,041	2,917	270	423	4,311	3,340
	16,579	14,502	17,620	14,564	34,199	29,066
Royalties	(1,606)	(1,233)	—	—	(1,606)	(1,233)
Revenues	14,973	13,269	17,620	14,564	32,593	27,833
Expenses
Purchased Product (2)	1,586	1,589	15,318	12,438	16,904	14,027
Transportation and Blending (2)	5,854	5,797	—	—	5,854	5,797
Operating	1,787	1,912	1,886	1,597	3,673	3,509
Realized (Gain) Loss on Risk Management	26	3	9	(5)	35	(2)
Operating Margin	5,720	3,968	407	534	6,127	4,502

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

Operating Margin by Asset


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


	Three Months Ended June 30, 2023			Six Months Ended June 30, 2023
($ millions)	Atlantic	Asia Pacific	Offshore (1)	Atlantic	Asia Pacific	Offshore (1)
Gross Sales	5	223	228	154	547	701
Royalties	(1)	(12)	(13)	(9)	(30)	(39)
Revenues	4	211	215	145	517	662
Expenses
Transportation and Blending	4	—	4	9	—	9
Operating	26	37	63	143	62	205
Operating Margin	(26)	174	148	(7)	455	448

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

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

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

Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities, excluding settlement of decommissioning liabilities and net change in operating non-cash working capital, minus capital investment.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			47

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 net of cash acquired, plus proceeds from, or payments related to, divestitures.

Gross Margin, Refining Margin and Market Capture

Gross Margin is a non-GAAP financial measure and Refining Margin contains a non-GAAP financial measure. These measures are used to evaluate the performance of our downstream operations. We define Gross Margin as revenues less purchased product. We define Refining Margin as Gross Margin from our refineries and Upgrader divided by total processed inputs. Total processed inputs was updated as the denominator to better reflect the overall inputs required to produce refined products. The comparative periods were previously calculated based on barrels of crude oil unit throughput and have been revised to conform with our current presentation.

Market Capture contains a non-GAAP financial measure used in our U.S. Refining segment to provide an indication of margin captured relative to what was available in the market based on widely-used benchmarks. We define Market Capture as Refining Margin divided by the weighted average 3-2-1 market benchmark crack, net of RINs, expressed as a percentage. The weighted average crack spread, net of RINs, is calculated on Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.

Canadian Refining


	Three Months Ended June 30, 2024

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,065	70	1,135
Purchased Product	930	45	975
Gross Margin	135	25	160

Total Processed Inputs (Mbbls/d)	58.9

Refining Margin ($/bbl)	25.21

(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 June 30, 2023

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	1,267	96	1,363
Purchased Product	1,019	64	1,083
Gross Margin	248	32	280

Total Processed Inputs (Mbbls/d)	102.7

Refining Margin ($/bbl)	26.54

(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.


	Six Months Ended June 30, 2024

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	2,314	153	2,467
Purchased Product	1,954	108	2,062
Gross Margin	360	45	405

Total Processed Inputs (Mbbls/d)	83.8

Refining Margin ($/bbl)	23.57

(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. – Q2 2024 Management's Discussion and Analysis			48


	Six Months Ended June 30, 2023

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining (2)
Revenues	2,668	203	2,871
Purchased Product	2,035	141	2,176
Gross Margin	633	62	695

Total Processed Inputs (Mbbls/d)	104.2

Refining Margin ($/bbl)	33.56

(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 March 31, 2024

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining
Revenues	1,249	83	1,332
Purchased Product	1,024	63	1,087
Gross Margin	225	20	245

Total Processed Inputs (Mbbls/d)	108.8

Refining Margin ($/bbl)	22.68

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


	Three Months Ended December 31, 2023

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining
Revenues	1,454	103	1,557
Purchased Product	1,197	66	1,263
Gross Margin	257	37	294

Total Processed Inputs (Mbbls/d)	105.1

Refining Margin ($/bbl)	26.48

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


	Three Months Ended September 30, 2023

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining
Revenues	1,690	115	1,805
Purchased Product	1,399	81	1,480
Gross Margin	291	34	325

Total Processed Inputs (Mbbls/d)	114.7

Refining Margin ($/bbl)	27.57

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			49


	Twelve Months Ended December 31, 2023

($ millions)	Lloydminster Upgrader and Lloydminster Refinery Total	Other (1)	Total Canadian Refining
Revenues	5,812	421	6,233
Purchased Product	4,634	285	4,919
Gross Margin	1,178	136	1,314

Total Processed Inputs (Mbbls/d)	107.1

Refining Margin ($/bbl)	30.13

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

U.S. Refining


	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2024	2023	2024	2023
Revenues (1) (2)	7,918	6,064	15,153	11,693
Purchased Product (1) (2)	7,124	5,364	13,256	10,262
Gross Margin	794	700	1,897	1,431

Total Processed Inputs (Mbbls/d)	594.0	464.2	584.5	419.9

Refining Margin ($/bbl)	14.69	16.57	17.83	18.83

Operable Capacity (Mbbls/d)	612.3	612.3	612.3	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81	81	80
Group 3 3-2-1 Crack Spread Weighting	19	19	19	20

Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	18.76	28.57	18.10	28.72
Group 3 3-2-1 Crack Spread (US$/bbl)	18.13	31.78	17.82	31.56
RINs (US$/bbl)	3.39	7.72	3.53	7.98
US$ per C$1 - Average	0.731	0.745	0.736	0.742

Weighted Average Crack Spread, Net of RINs ($/bbl)	20.86	28.82	19.72	28.72

Market Capture (3) (percent)	70	57	90	66

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

(3)The Superior Refinery’s operable capacity is included in the Market Capture calculation effective April 1, 2023. For the six months ended June 30, 2023, Market Capture includes a weighted average operable capacity for the Toledo Refinery as full ownership was acquired on February 28, 2023.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			50


	Three Months Ended			Twelve Months Ended
($ millions)	March 31, 2024	December 31, 2023	September 30, 2023	December 31, 2023
Revenues (1)	7,235	6,847	7,853	26,393
Purchased Product (1)	6,132	6,625	6,467	23,354
Gross Margin	1,103	222	1,386	3,039

Total Processed Inputs (Mbbls/d)	575.0	500.6	576.6	479.7

Refining Margin ($/bbl)	21.08	4.82	26.13	17.36

Operable Capacity (Mbbls/d)	612.3	612.3	612.3	612.3
Operable Capacity by Regional Benchmark (percent)
Chicago 3-2-1 Crack Spread Weighting	81	81	81	82
Group 3 3-2-1 Crack Spread Weighting	19	19	19	18

Benchmark Prices and Exchange Rate
Chicago 3-2-1 Crack Spread (US$/bbl)	17.45	13.24	26.06	24.19
Group 3 3-2-1 Crack Spread (US$/bbl)	17.50	18.55	36.96	29.66
RINs (US$/bbl)	3.68	4.77	7.42	7.04
US$ per C$1 - Average	0.741	0.734	0.746	0.741

Weighted Average Crack Spread, Net of RINs ($/bbl)	18.59	12.94	27.81	24.49

Market Capture (2) (percent)	113	37	94	71

(2)The Superior Refinery’s operable capacity is included in the Market Capture calculation effective April 1, 2023. For the twelve months ended December 31, 2023, Market Capture includes a weighted average operable capacity for the Toledo Refinery as full ownership was acquired on February 28, 2023.

Per-Unit Operating Expenses and Turnaround Costs

Per-Unit Operating Expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. We define Canadian Refining Per-Unit Operating Expenses as total operating expenses from the Upgrader, the Lloydminster Refinery and the commercial fuels business, divided by total processed inputs. We define U.S. Refining Per-Unit Operating Expenses as operating expenses divided by total processed inputs.

Per-Unit Operating Expenses – Turnaround Costs are specified financial measures used to evaluate the cost of turnarounds for our downstream operations. We define Per-Unit Operating Expenses – Turnaround Costs as turnaround expenses from the refining segments’ operating expenses divided by total processed inputs.

Our Upstream Per-Unit Operating Expenses are defined as total operating expenses divided by sales volumes, and are part of our Netback calculation, which can be found below.

Per-Unit Depreciation, Depletion and Amortization

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

Per-Unit Transportation Expenses

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			51

Netback Reconciliations and Realized Sales Price

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. Our Netback calculation is substantially aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netback is defined as gross sales less royalties, transportation and blending, and operating expenses. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold and exclude risk management activities. Condensate or butane (diluent) is blended with crude oil to transport it to market. In the three months ended March 31, 2024, modifications were made to our netback definition to enhance the clarity of certain costs captured in this metric. These modifications resulted in minor adjustments that are captured in the netback calculation on a prospective basis.

Realized sales price contains a non-GAAP measure. It includes our gross sales, purchased diluent costs and profit from optimization activities, such as cogeneration, third-party processing and trading. Netback per barrel of oil equivalent contains a non-GAAP measure. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Per-unit measures are divided by sales volumes.

The following tables provide a reconciliation of Netback to Operating Margin found in our interim Consolidated Financial Statements.

Oil Sands


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


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

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

(2)Other includes construction, transportation and blending.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			52


	Basis of Netback Calculation
Three Months Ended June 30, 2023 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	1,205	1,398	304	827	3,734	2	3,736
Royalties	(219)	(314)	(14)	(72)	(619)	(2)	(621)
Revenues	986	1,084	290	755	3,115	—	3,115
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	205	124	54	41	424	—	424
Operating	195	170	75	227	667	2	669
Netback	586	790	161	487	2,024	(2)	2,022
Realized (Gain) Loss on Risk Management							(8)
Operating Margin							2,030


	Basis of Netback Calculation	Adjustments
Three Months Ended June 30, 2023 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales (4)	3,736		2,244	351	106	6,437
Royalties	(621)		—	—	1	(620)
Revenues	3,115		2,244	351	107	5,817
Expenses
Purchased Product (4)	—		—	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

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

(2)Other includes construction, transportation and blending.

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

(4)Comparative periods reflect certain revisions. See Note 24 of the interim Consolidated Financial Statements and Prior Period Revisions found in the Advisory section of this MD&A for further details.


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


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

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

(2)Other includes construction, transportation and blending.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			53


	Basis of Netback Calculation
Six Months Ended June 30, 2023 ($ millions)	Foster Creek	Christina Lake	Sunrise	Lloydminster Oil Sands (1)	Total Bitumen and Heavy Oil	Natural Gas	Total Oil Sands
Gross Sales	2,237	2,465	485	1,432	6,619	5	6,624
Royalties	(408)	(587)	(20)	(119)	(1,134)	(3)	(1,137)
Revenues	1,829	1,878	465	1,313	5,485	2	5,487
Expenses
Purchased Product	—	—	—	—	—	—	—
Transportation and Blending	427	289	99	79	894	—	894
Operating	410	365	154	463	1,392	6	1,398
Netback	992	1,224	212	771	3,199	(4)	3,195
Realized (Gain) Loss on Risk Management							(1)
Operating Margin							3,196


	Basis of Netback Calculation	Adjustments
Six Months Ended June 30, 2023 ($ millions)	Total Oil Sands		Condensate	Third-party Sourced	Other (2)	Total Oil Sands (3)
Gross Sales (4)	6,624		4,689	645	186	12,144
Royalties	(1,137)		—	—	1	(1,136)
Revenues	5,487		4,689	645	187	11,008
Expenses
Purchased Product (4)	—		—	645	124	769
Transportation and Blending	894		4,689	—	58	5,641
Operating	1,398		—	—	15	1,413
Netback	3,195		—	—	(10)	3,185
Realized (Gain) Loss on Risk Management	(1)		—	—	—	(1)
Operating Margin	3,196		—	—	(10)	3,186

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

(2)Other includes construction, transportation and blending.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			54

Conventional


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


	Basis of Netback Calculation	Adjustments
Three Months Ended June 30, 2023 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales (3)	238	337	45	620
Royalties	(5)	—	1	(4)
Revenues	233	337	46	616
Expenses
Purchased Product (3)	—	337	—	337
Transportation and Blending (3)	39	—	27	66
Operating	139	—	5	144
Netback	55	—	14	69
Realized (Gain) Loss on Risk Management	(4)	—	—	(4)
Operating Margin	59	—	14	73

(1)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.

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


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


	Basis of Netback Calculation	Adjustments
Six Months Ended June 30, 2023 ($ millions)	Conventional	Third-party Sourced	Other (1)	Conventional (2)
Gross Sales (3)	729	820	108	1,657
Royalties	(59)	—	1	(58)
Revenues	670	820	109	1,599
Expenses
Purchased Product (3)	—	820	—	820
Transportation and Blending (3)	84	—	63	147
Operating	285	—	9	294
Netback	301	—	37	338
Realized (Gain) Loss on Risk Management	4	—	—	4
Operating Margin	297	—	37	334

(1)Other includes reclassification of costs primarily related to third-party cogeneration, processing and transportation.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			55

Offshore


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


	Basis of Netback Calculation					Adjustments
Three Months Ended June 30, 2023 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	5	223	79	302	307	(79)	—	228
Royalties	(1)	(12)	(18)	(30)	(31)	18	—	(13)
Revenues	4	211	61	272	276	(61)	—	215
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	4	—	—	—	4	—	—	4
Operating	36	33	12	45	81	(10)	(8)	63
Netback	(36)	178	49	227	191	(51)	8	148
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					191	(51)	8	148

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

(2)Primarily related to Offshore project expenses.

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


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


	Basis of Netback Calculation					Adjustments
Six Months Ended June 30, 2023 ($ millions)	Atlantic	China	Indonesia (1)	Total Asia Pacific	Total Offshore	Equity Adjustment (1)	Other (2)	Total Offshore (3)
Gross Sales	154	547	152	699	853	(152)	—	701
Royalties	(9)	(30)	(41)	(71)	(80)	41	—	(39)
Revenues	145	517	111	628	773	(111)	—	662
Expenses
Purchased Product	—	—	—	—	—	—	—	—
Transportation and Blending	9	—	—	—	9	—	—	9
Operating	121	55	26	81	202	(20)	23	205
Netback	15	462	85	547	562	(91)	(23)	448
Realized (Gain) Loss on Risk Management					—	—	—	—
Operating Margin					562	(91)	(23)	448

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

(2)Primarily related to Offshore project expenses.

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			56

Upstream Sales Volumes (1)

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


	Three Months Ended June 30,		Six Months Ended June 30,
(MBOE/d)	2024	2023	2024	2023
Oil Sands
Foster Creek	185.4	175.7	189.7	179.6
Christina Lake	218.1	231.4	230.1	234.6
Sunrise	51.0	47.2	46.6	43.5
Lloydminster	130.0	123.8	129.2	119.8
Total Oil Sands	584.5	578.1	595.6	577.5

Conventional	123.1	104.6	121.9	114.2

Offshore
Atlantic	14.8	—	9.4	7.8
Asia Pacific
China	43.5	31.2	43.6	37.2
Indonesia	14.3	15.0	14.2	14.3
Total Asia Pacific	57.8	46.2	57.8	51.5
Total Offshore	72.6	46.2	67.2	59.3

Sales Before Internal Consumption	780.2	728.9	784.7	751.0
Internal Consumption (2)	(96.8)	(86.8)	(101.3)	(89.0)
Total Upstream Sales	683.4	642.1	683.4	662.0

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

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


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			57

Prior Period Revisions

Certain comparative information presented in the Consolidated Statements of Comprehensive Income (Loss) and segment disclosures was revised for classification changes.

Classification Revisions

In September 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. Refining 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 Comprehensive Income (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position.


	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. Refining 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	(2,092)	248	(1,844)	(4,017)	677	(3,340)
Purchased Product	(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
Purchased Product, Transportation and Blending (1)	8,350	(59)	8,291	16,995	(143)	16,852
Operating	1,541	59	1,600	3,093	143	3,236
	9,891	—	9,891	20,088	—	20,088

(1)Revised presentation as of January 1, 2024. See Note 3 to the interim Consolidated Financial Statements.


Cenovus Energy Inc. – Q2 2024 Management's Discussion and Analysis			58

Exhibit 99.3

Cenovus Energy Inc.

Interim Consolidated Financial Statements (unaudited)

For the Periods Ended June 30, 2024

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


For the periods ended June 30, 2024


TABLE OF CONTENTS


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)						3

CONSOLIDATED BALANCE SHEETS (UNAUDITED)						4
CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)						5
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)						6
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)						7
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES						7
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE						14
3. UPDATE TO ACCOUNTING POLICIES						15


4. FINANCE COSTS, NET						15

5. FOREIGN EXCHANGE (GAIN) LOSS, NET						16
6. DIVESTITURES						16

7. INCOME TAXES						16
8. PER SHARE AMOUNTS						17

9. EXPLORATION AND EVALUATION ASSETS, NET						18
10. PROPERTY, PLANT AND EQUIPMENT, NET						18
11. LEASES						19



12. DEBT AND CAPITAL STRUCTURE						19

13. CONTINGENT PAYMENTS						22
14. DECOMMISSIONING LIABILITIES						22
15. OTHER LIABILITIES						22
16. SHARE CAPITAL AND WARRANTS						23
17. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)						24
18. STOCK-BASED COMPENSATION PLANS						24
19. RELATED PARTY TRANSACTIONS						25
20. FINANCIAL INSTRUMENTS						26
21. RISK MANAGEMENT						28
22. SUPPLEMENTARY CASH FLOW INFORMATION						29
23. COMMITMENTS AND CONTINGENCIES						31
24. PRIOR PERIOD REVISIONS						31


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			2



CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)

For the periods ended June 30,

($ millions, except per share amounts)


		Three Months Ended		Six Months Ended
	Notes	2024	2023	2024	2023




Revenues (1)	1	14,885	12,231	28,282	24,493
Expenses	1
Purchased Product, Transportation and Blending (1) (2)		10,049	8,291	18,757	16,852
Operating (2)		1,923	1,600	3,478	3,236
(Gain) Loss on Risk Management	20	21	23	62	17
Depreciation, Depletion, Amortization and Exploration Expense (1)	10,11	1,238	1,076	2,440	2,185
(Income) Loss From Equity-Accounted Affiliates	19	(28)	(6)	(37)	(12)
General and Administrative		175	167	421	325
Finance Costs, Net (1)	4	141	159	276	320
Integration, Transaction and Other Costs		39	17	72	37
Foreign Exchange (Gain) Loss, Net	5	55	(119)	154	(126)
(Gain) Loss on Divestiture of Assets (1)	6	1	(10)	(104)	22
Re-measurement of Contingent Payments	13	2	(1)	30	16
Other (Income) Loss, Net		(40)	(14)	(130)	(20)
Earnings (Loss) Before Income Tax		1,309	1,048	2,863	1,641
Income Tax Expense (Recovery)	7	309	182	687	139
Net Earnings (Loss)		1,000	866	2,176	1,502

Other Comprehensive Income (Loss), Net of Tax	17
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits		4	(1)	18	(4)
Change in the Fair Value of Equity Instruments at FVOCI (3)	20	124	(1)	124	(1)
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		125	(265)	393	(284)
Total Other Comprehensive Income (Loss), Net of Tax		253	(267)	535	(289)
Comprehensive Income (Loss)		1,253	599	2,711	1,213

Net Earnings (Loss) Per Common Share ($)	8
Basic		0.53	0.45	1.16	0.78
Diluted		0.53	0.44	1.15	0.76

(1)Revised presentation as of January 1, 2024. See Note 3.

(2)Comparative periods reflect certain revisions. See Note 24.

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

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


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			3


CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)



	Notes	June 30, 2024	December 31, 2023

Assets
Current Assets
Cash and Cash Equivalents		3,154	2,227
Accounts Receivable and Accrued Revenues		3,648	3,035
Income Tax Receivable		240	416
Inventories		4,605	4,030

Total Current Assets		11,647	9,708
Restricted Cash		224	211
Exploration and Evaluation Assets, Net	1,9	639	738
Property, Plant and Equipment, Net	1,10	37,400	37,250
Right-of-Use Assets, Net	1,11	1,637	1,680
Income Tax Receivable		25	25
Investments in Equity-Accounted Affiliates	19	418	366
Other Assets		456	318
Deferred Income Taxes		631	696
Goodwill	1	2,923	2,923
Total Assets		56,000	53,915

Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		6,482	5,480
Income Tax Payable		74	88
Short-Term Borrowings	12	137	179

Lease Liabilities	11	296	299
Contingent Payments	13	40	164

Total Current Liabilities		7,029	6,210
Long-Term Debt	12	7,275	7,108
Lease Liabilities	11	2,304	2,359

Decommissioning Liabilities	14	4,136	4,155
Other Liabilities	15	1,178	1,183
Deferred Income Taxes		4,052	4,188
Total Liabilities		25,974	25,203
Shareholders’ Equity		30,012	28,698
Non-Controlling Interest		14	14
Total Liabilities and Equity		56,000	53,915

Commitments and Contingencies	23

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


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			4


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 16)	(Note 16)	(Note 16)			(Note 17)

As at December 31, 2022	16,320	519	184	2,691	6,392	1,470	27,576	13
Net Earnings (Loss)	—	—	—	—	1,502	—	1,502	—
Other Comprehensive Income (Loss), Net of Tax	—	—	—	—	—	(289)	(289)	—
Total Comprehensive Income (Loss)	—	—	—	—	1,502	(289)	1,213	—

Common Shares Issued Under Stock Option Plans	23	—	—	(5)	—	—	18	—
Purchase of Common Shares Under NCIB (2)	(133)	—	—	(217)	—	—	(350)	—


Warrants Exercised	16	—	(5)	—	—	—	11	—
Warrants Purchased and Cancelled	—	—	(151)	—	(562)	—	(713)
Stock-Based Compensation Expense	—	—	—	7	—	—	7	—
Base Dividends on Common Shares	—	—	—	—	(465)	—	(465)	—

Dividends on Preferred Shares	—	—	—	—	(18)	—	(18)	—

As at June 30, 2023	16,226	519	28	2,476	6,849	1,181	27,279	13

As at December 31, 2023	16,031	519	25	2,002	8,913	1,208	28,698	14
Net Earnings (Loss)	—	—	—	—	2,176	—	2,176	—
Other Comprehensive Income (Loss), Net of Tax	—	—	—	—	—	535	535	—
Total Comprehensive Income (Loss)	—	—	—	—	2,176	535	2,711	—

Common Shares Issued Under Stock Option Plans	66	—	—	(16)	—	—	50	—

Purchase of Common Shares Under NCIB (2)	(195)	—	—	(410)	—	—	(605)	—


Warrants Exercised	26	—	(9)	—	—	—	17	—

Stock-Based Compensation Expense	—	—	—	6	—	—	6	—
Base Dividends on Common Shares	—	—	—	—	(596)	—	(596)	—
Variable Dividends on Common Shares	—	—	—	—	(251)	—	(251)	—
Dividends on Preferred Shares	—	—	—	—	(18)	—	(18)	—

As at June 30, 2024	15,928	519	16	1,582	10,224	1,743	30,012	14

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

(2)Normal course issuer bid (“NCIB”). Includes taxes on purchase of equity.

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


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			5


CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the periods ended June 30,

($ millions)


		Three Months Ended		Six Months Ended
	Notes	2024	2023	2024	2023

Operating Activities
Net Earnings (Loss)		1,000	866	2,176	1,502
Depreciation, Depletion and Amortization	10,11	1,233	1,072	2,428	2,177



Deferred Income Tax Expense (Recovery)	7	(46)	(44)	(78)	(414)
Unrealized (Gain) Loss on Risk Management	20	(7)	46	24	16
Unrealized Foreign Exchange (Gain) Loss	5	85	(172)	209	(158)


(Gain) Loss on Divestiture of Assets (1)	6	1	(10)	(104)	22
Re-measurement of Contingent Payments	13	2	(1)	30	16
Unwinding of Discount on Decommissioning Liabilities	14	56	55	113	110
(Income) Loss From Equity-Accounted Affiliates	19	(28)	(6)	(37)	(12)
Distributions Received From Equity-Accounted Affiliates	19	87	71	118	94
Stock-Based Compensation, Net of Payments		24	17	(130)	(54)
Other		(46)	5	(146)	(5)
Settlement of Decommissioning Liabilities	14	(48)	(41)	(96)	(89)
Net Change in Non-Cash Working Capital	22	494	132	225	(1,501)
Cash From (Used in) Operating Activities		2,807	1,990	4,732	1,704

Investing Activities
Acquisitions, Net of Cash Acquired		(5)	(4)	(15)	(469)
Capital Investment	1	(1,155)	(1,002)	(2,191)	(2,103)
Proceeds From Divestitures	6	—	3	25	11



Net Change in Investments and Other		(51)	(80)	(64)	(93)
Net Change in Non-Cash Working Capital	22	41	(76)	(60)	(260)
Cash From (Used in) Investing Activities		(1,170)	(1,159)	(2,305)	(2,914)

Net Cash Provided (Used) Before Financing Activities		1,637	831	2,427	(1,210)

Financing Activities	22
Net Issuance (Repayment) of Short-Term Borrowings		136	—	(39)	(115)



Principal Repayment of Leases	11	(75)	(76)	(145)	(146)
Common Shares Issued Under Stock Option Plans		46	14	50	18
Purchase of Common Shares Under NCIB	16	(440)	(310)	(605)	(350)

Proceeds From Exercise of Warrants		15	8	17	11
Base Dividends Paid on Common Shares	8	(334)	(265)	(596)	(465)
Variable Dividends Paid on Common Shares	8	(251)	—	(251)	—
Dividends Paid on Preferred Shares	8	(9)	(9)	(18)	(27)
Other		—	(1)	(2)	—
Cash From (Used in) Financing Activities		(912)	(639)	(1,589)	(1,074)

Effect of Foreign Exchange on Cash and Cash Equivalents		29	(74)	89	(73)
Increase (Decrease) in Cash and Cash Equivalents		754	118	927	(2,357)
Cash and Cash Equivalents, Beginning of Period		2,400	2,049	2,227	4,524
Cash and Cash Equivalents, End of Period		3,154	2,167	3,154	2,167

(1)Revised presentation as of January 1, 2024. See Note 3.

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


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			6

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc. (“Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States (“U.S.”).

Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1, 2, 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

•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.

Downstream Segments

Corporate and Eliminations


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			7

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

A) Results of Operations – Segment and Operational Information

i) Results for the Three Months Ended June 30


	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2024	2023	2024	2023	2024	2023	2024	2023
Gross Sales (1)
External Sales	6,056	5,177	264	253	471	228	6,791	5,658
Intersegment Sales	1,497	1,260	427	367	—	—	1,924	1,627
	7,553	6,437	691	620	471	228	8,715	7,285
Royalties	(814)	(620)	(22)	(4)	(23)	(13)	(859)	(637)
Revenues	6,739	5,817	669	616	448	215	7,856	6,648
Expenses
Purchased Product (1)	403	414	412	337	—	—	815	751
Transportation and Blending (1)	2,953	2,700	83	66	7	4	3,043	2,770
Operating	615	676	132	144	142	63	889	883
Realized (Gain) Loss on Risk Management	20	(9)	—	(4)	—	—	20	(13)
Operating Margin	2,748	2,036	42	73	299	148	3,089	2,257
Unrealized (Gain) Loss on Risk Management	1	31	2	(1)	—	—	3	30
Depreciation, Depletion and Amortization	772	730	111	87	156	91	1,039	908
Exploration Expense	1	2	—	—	4	2	5	4
(Income) Loss From Equity- Accounted Affiliates	(14)	6	—	—	(13)	(12)	(27)	(6)
Segment Income (Loss)	1,988	1,267	(71)	(13)	152	67	2,069	1,321


	Downstream
	Canadian Refining		U.S. Refining		Total
For the three months ended June 30,	2024	2023	2024	2023	2024	2023
Gross Sales (1)
External Sales	1,037	1,151	7,916	6,059	8,953	7,210
Intersegment Sales	98	212	2	5	100	217
	1,135	1,363	7,918	6,064	9,053	7,427
Royalties	—	—	—	—	—	—
Revenues	1,135	1,363	7,918	6,064	9,053	7,427
Expenses
Purchased Product (1)	975	1,083	7,124	5,364	8,099	6,447
Transportation and Blending	—	—	—	—	—	—
Operating	415	164	684	679	1,099	843
Realized (Gain) Loss on Risk Management	—	—	8	(6)	8	(6)
Operating Margin	(255)	116	102	27	(153)	143
Unrealized (Gain) Loss on Risk Management	—	—	(10)	(5)	(10)	(5)
Depreciation, Depletion and Amortization	54	43	112	102	166	145
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	(309)	73	—	(70)	(309)	3

(1)Comparative periods reflect certain revisions. See Note 24.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			8

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024


	Corporate and Eliminations		Consolidated
For the three months ended June 30,		2024		2023	2024	2023
Gross Sales (1)
External Sales				—	—	15,744	12,868
Intersegment Sales				(2,024)	(1,844)	—	—
				(2,024)	(1,844)	15,744	12,868
Royalties				—	—	(859)	(637)
Revenues				(2,024)	(1,844)	14,885	12,231
Expenses
Purchased Product (1)				(1,730)	(1,470)	7,184	5,728
Transportation and Blending (1)				(178)	(207)	2,865	2,563
Purchased Product, Transportation and Blending (2)				(1,908)	(1,677)	10,049	8,291
Operating (1)				(65)	(126)	1,923	1,600
Realized (Gain) Loss on Risk Management				—	(4)	28	(23)
Unrealized (Gain) Loss on Risk Management				—	21	(7)	46
Depreciation, Depletion and Amortization				28	19	1,233	1,072
Exploration Expense				—	—	5	4
(Income) Loss From Equity-Accounted Affiliates				(1)	—	(28)	(6)
Segment Income (Loss)				(78)	(77)	1,682	1,247
General and Administrative				175	167	175	167
Finance Costs, Net (2)				141	159	141	159
Integration, Transaction and Other Costs				39	17	39	17
Foreign Exchange (Gain) Loss, Net				55	(119)	55	(119)
(Gain) Loss on Divestiture of Assets (2)				1	(10)	1	(10)
Re-measurement of Contingent Payments				2	(1)	2	(1)

Other (Income) Loss, Net				(40)	(14)	(40)	(14)
				373	199	373	199
Earnings (Loss) Before Income Tax						1,309	1,048
Income Tax Expense (Recovery)						309	182
Net Earnings (Loss)						1,000	866

(1)Comparative periods reflect certain revisions. See Note 24.

(2)Revised presentation as of January 1, 2024. See Note 3.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			9

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

ii) Results for the Six Months Ended June 30


	Upstream
For the six months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2024	2023	2024	2023	2024	2023	2024	2023
Gross Sales (1)
External Sales	11,069	10,009	641	875	828	701	12,538	11,585
Intersegment Sales	3,112	2,135	929	782	—	—	4,041	2,917
	14,181	12,144	1,570	1,657	828	701	16,579	14,502
Royalties	(1,511)	(1,136)	(46)	(58)	(49)	(39)	(1,606)	(1,233)
Revenues	12,670	11,008	1,524	1,599	779	662	14,973	13,269
Expenses
Purchased Product (1)	692	769	894	820	—	—	1,586	1,589
Transportation and Blending (1)	5,686	5,641	161	147	7	9	5,854	5,797
Operating	1,275	1,413	285	294	227	205	1,787	1,912
Realized (Gain) Loss on Risk Management	33	(1)	(7)	4	—	—	26	3
Operating Margin	4,984	3,186	191	334	545	448	5,720	3,968
Unrealized (Gain) Loss on Risk Management	(12)	(3)	8	(21)	—	—	(4)	(24)
Depreciation, Depletion and Amortization	1,546	1,445	221	182	287	219	2,054	1,846
Exploration Expense	4	4	—	—	8	4	12	8
(Income) Loss From Equity- Accounted Affiliates	(14)	6	1	—	(23)	(18)	(36)	(12)
Segment Income (Loss)	3,460	1,734	(39)	173	273	243	3,694	2,150


	Downstream
	Canadian Refining		U.S. Refining		Total
For the six months ended June 30,	2024	2023	2024	2023	2024	2023
Gross Sales (1)
External Sales	2,200	2,453	15,150	11,688	17,350	14,141
Intersegment Sales	267	418	3	5	270	423
	2,467	2,871	15,153	11,693	17,620	14,564
Royalties	—	—	—	—	—	—
Revenues	2,467	2,871	15,153	11,693	17,620	14,564
Expenses
Purchased Product (1)	2,062	2,176	13,256	10,262	15,318	12,438
Transportation and Blending	—	—	—	—	—	—
Operating	592	316	1,294	1,281	1,886	1,597
Realized (Gain) Loss on Risk Management	—	—	9	(5)	9	(5)
Operating Margin	(187)	379	594	155	407	534
Unrealized (Gain) Loss on Risk Management	—	—	(2)	(11)	(2)	(11)
Depreciation, Depletion and Amortization	98	86	223	205	321	291
Exploration Expense	—	—	—	—	—	—
(Income) Loss From Equity-Accounted Affiliates	—	—	—	—	—	—
Segment Income (Loss)	(285)	293	373	(39)	88	254

(1)Comparative periods reflect certain revisions. See Note 24.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			10

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024


	Corporate and Eliminations		Consolidated
For the six months ended June 30,	2024	2023	2024	2023
Gross Sales (1)
External Sales	—	—	29,888	25,726
Intersegment Sales	(4,311)	(3,340)	—	—
	(4,311)	(3,340)	29,888	25,726
Royalties	—	—	(1,606)	(1,233)
Revenues	(4,311)	(3,340)	28,282	24,493
Expenses
Purchased Product (1)	(3,587)	(2,490)	13,317	11,537
Transportation and Blending (1)	(414)	(482)	5,440	5,315
Purchased Product, Transportation and Blending (2)	(4,001)	(2,972)	18,757	16,852
Operating (1)	(195)	(273)	3,478	3,236
Realized (Gain) Loss on Risk Management	3	3	38	1
Unrealized (Gain) Loss on Risk Management	30	51	24	16
Depreciation, Depletion and Amortization	53	40	2,428	2,177
Exploration Expense	—	—	12	8
(Income) Loss From Equity-Accounted Affiliates	(1)	—	(37)	(12)
Segment Income (Loss)	(200)	(189)	3,582	2,215
General and Administrative	421	325	421	325
Finance Costs, Net (2)	276	320	276	320
Integration, Transaction and Other Costs	72	37	72	37
Foreign Exchange (Gain) Loss, Net	154	(126)	154	(126)
(Gain) Loss on Divestiture of Assets (2)	(104)	22	(104)	22
Re-measurement of Contingent Payments	30	16	30	16
Other (Income) Loss, Net	(130)	(20)	(130)	(20)
	719	574	719	574
Earnings (Loss) Before Income Tax			2,863	1,641
Income Tax Expense (Recovery)			687	139
Net Earnings (Loss)			2,176	1,502

(1)Comparative periods reflect certain revisions. See Note 24.

(2)Revised presentation as of January 1, 2024. See Note 3.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			11

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

B) External Sales by Product


	Upstream
For the three months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2024	2023	2024	2023	2024	2023	2024	2023
Crude Oil	5,819	4,967	69	41	151	4	6,039	5,012
Natural Gas and Other	100	87	110	168	232	177	442	432
NGLs (1)	137	123	85	44	88	47	310	214
External Sales	6,056	5,177	264	253	471	228	6,791	5,658


	Downstream
	Canadian Refining		U.S. Refining		Total
For the three months ended June 30,	2024	2023	2024	2023	2024	2023
Synthetic Crude Oil	270	389	—	—	270	389
Distillates (2)	356	346	2,814	2,029	3,170	2,375
Gasoline	132	137	3,782	2,854	3,914	2,991
Asphalt	152	129	285	217	437	346
Other Products and Services	127	150	1,035	959	1,162	1,109
External Sales	1,037	1,151	7,916	6,059	8,953	7,210

(1)Third-party condensate sales are included within NGLs.

(2)Includes diesel and jet fuel.


	Upstream
For the six months ended	Oil Sands		Conventional		Offshore		Total
June 30,	2024	2023	2024	2023	2024	2023	2024	2023
Crude Oil	10,694	9,634	124	143	192	154	11,010	9,931
Natural Gas and Other	180	180	346	619	465	419	991	1,218
NGLs (1)	195	195	171	113	171	128	537	436
External Sales	11,069	10,009	641	875	828	701	12,538	11,585


	Downstream
	Canadian Refining		U.S. Refining		Total
For the six months ended June 30,	2024	2023	2024	2023	2024	2023
Synthetic Crude Oil	735	851	—	—	735	851
Distillates (2)	748	826	5,545	4,298	6,293	5,124
Gasoline	235	248	7,100	5,514	7,335	5,762
Asphalt	225	218	431	284	656	502
Other Products and Services	257	310	2,074	1,592	2,331	1,902
External Sales	2,200	2,453	15,150	11,688	17,350	14,141

(1)Third-party condensate sales are included within NGLs.

(2)Includes diesel and jet fuel.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			12

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

C) Geographical Information


	Revenues (1)
	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Canada (2)	8,094	6,057	13,298	12,162
United States (2)	6,495	5,963	14,397	11,814
China	296	211	587	517
Consolidated	14,885	12,231	28,282	24,493

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

(2)Comparative periods reflect certain revisions. See Note 24.


	Non-Current Assets (1)
	June 30,	December 31,
As at	2024	2023
Canada	35,943	35,876
United States	5,439	5,230
China	1,436	1,608
Indonesia	313	344
Consolidated	43,131	43,058

(1)Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill.

D) Assets by Segment


	E&E Assets		PP&E		ROU Assets
	June 30,	December 31,	June 30,	December 31,	June 30,	December 31,
As at	2024	2023	2024	2023	2024	2023
Oil Sands	594	729	24,362	24,443	819	849
Conventional	7	—	2,145	2,209	—	1
Offshore	38	9	2,954	2,798	99	102
Canadian Refining	—	—	2,483	2,469	43	28
U.S. Refining	—	—	5,163	5,014	258	268
Corporate and Eliminations	—	—	293	317	418	432
Consolidated	639	738	37,400	37,250	1,637	1,680


	Goodwill		Total Assets
	June 30,	December 31,	June 30,	December 31,
As at	2024	2023	2024	2023
Oil Sands	2,923	2,923	31,759	31,673
Conventional	—	—	2,466	2,429
Offshore	—	—	3,783	3,511
Canadian Refining	—	—	3,038	2,960
U.S. Refining	—	—	9,526	8,660
Corporate and Eliminations	—	—	5,428	4,682
Consolidated	2,923	2,923	56,000	53,915


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			13

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

E) Capital Expenditures (1)


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Capital Investment
Oil Sands	613	539	1,260	1,174
Conventional	68	82	194	223
Offshore
Atlantic	266	183	424	283
Asia Pacific	29	1	30	1
Total Upstream	976	805	1,908	1,681

Canadian Refining	70	34	101	61
U.S. Refining	100	153	167	347
Total Downstream	170	187	268	408

Corporate and Eliminations	9	10	15	14
	1,155	1,002	2,191	2,103
Acquisitions
Oil Sands	4	1	6	3
Conventional	1	2	9	4


U.S. Refining	—	1	—	337

	5	4	15	344

Total Capital Expenditures	1,160	1,006	2,206	2,447

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



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 International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”) 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, 2023, except for updates to accounting policies as disclosed in Note 3 and 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 annual earnings or loss.

Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements were condensed. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2023, which were prepared in accordance with IFRS Accounting Standards.

These interim Consolidated Financial Statements were approved by the Board of Directors effective July 31, 2024.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			14

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



3. UPDATE TO ACCOUNTING POLICIES

A) Adjustments to the Consolidated Statements of Comprehensive Income (Loss)

The following presentation changes were made, with comparative periods being re-presented:

•Gross sales and royalties were aggregated and presented as ‘Revenues’.

•Purchased product and transportation and blending were aggregated and presented as ‘Purchased Product, Transportation and Blending’.

•Depreciation, depletion and amortization, and exploration expense were aggregated and presented as ‘Depreciation, Depletion, Amortization and Exploration Expense’.

•Finance costs and interest income were aggregated and presented as ‘Finance Costs, Net’.

•Revaluation (gain) loss and (gain) loss on divestiture of assets were aggregated and presented as ‘(Gain) Loss on Divestiture of Assets’.

B) Recent Accounting Pronouncements

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



4. FINANCE COSTS, NET


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Interest Expense – Short-Term Borrowings and Long-Term Debt	77	95	153	191

Interest Expense – Lease Liabilities (Note 11)	40	40	79	80
Unwinding of Discount on Decommissioning Liabilities (Note 14)	56	55	113	110
Other	15	7	21	13

Capitalized Interest	(10)	(4)	(18)	(7)
Finance Costs	178	193	348	387
Interest Income	(37)	(34)	(72)	(67)
	141	159	276	320


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			15

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



5. FOREIGN EXCHANGE (GAIN) LOSS, NET



	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt	52	(142)	175	(147)
Other	33	(30)	34	(11)
Unrealized Foreign Exchange (Gain) Loss	85	(172)	209	(158)
Realized Foreign Exchange (Gain) Loss	(30)	53	(55)	32
	55	(119)	154	(126)



6. DIVESTITURES

On February 6, 2024, the Company closed a transaction with Athabasca Oil Corporation (“Athabasca”) to create Duvernay Energy Corporation (“Duvernay”). Cenovus contributed non-monetary assets with a fair value of $94 million and cash of $18 million, before closing adjustments, in exchange for a 30 percent interest in Duvernay. The Company recognized an investment of $84 million in Duvernay and a before-tax gain on divestiture of assets of $65 million (after-tax gain – $50 million), reflecting the difference between the carrying value and fair value of contributed assets to the extent of Athabasca’s share.

On March 6, 2024, the Company closed the sale of certain Clearwater assets in its Conventional segment for net proceeds of $19 million and recorded a before-tax gain of $36 million (after-tax gain – $27 million).



7. INCOME TAXES



	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Current Tax
Canada	300	199	646	457
United States	(9)	(17)	2	—
Asia Pacific	56	38	100	84
Other International	8	6	17	12
Total Current Tax Expense (Recovery)	355	226	765	553
Deferred Tax Expense (Recovery)	(46)	(44)	(78)	(414)
	309	182	687	139


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			16

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



8. PER SHARE AMOUNTS

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


	Three Months Ended		Six Months Ended
For periods ended June 30,	2024	2023	2024	2023
Net Earnings (Loss)	1,000	866	2,176	1,502
Effect of Cumulative Dividends on Preferred Shares	(9)	(9)	(18)	(18)
Net Earnings (Loss) – Basic and Diluted	991	857	2,158	1,484

Basic – Weighted Average Number of Shares (thousands)	1,859,377	1,902,820	1,863,585	1,905,535
Dilutive Effect of Warrants	4,696	33,292	5,426	37,281
Dilutive Effect of Net Settlement Rights	5,645	6,286	6,336	7,015
Dilutive Effect of Cenovus Replacement Stock Options (1)	317	856	—	876
Diluted – Weighted Average Number of Shares (thousands)	1,870,035	1,943,254	1,875,347	1,950,707

Net Earnings (Loss) Per Common Share – Basic ($)	0.53	0.45	1.16	0.78
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)	0.53	0.44	1.15	0.76

(1)For the three months ended June 30, 2024, the dilutive effect of Cenovus replacement stock options was 0.3 million common shares. For the six months ended June 30, 2024, net earnings of $3 million and 0.3 million common shares related to the assumed exercise of Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive. For the three and six months ended June 30, 2023, the dilutive effect of Cenovus replacement stock options was 0.9 million common shares.

(2)For the three and six months ended June 30, 2024, net settlement rights (“NSRs”) of 2.1 million and 3.1 million, respectively, (three and six months ended June 30, 2023 – 1.6 million) were excluded from the calculation of diluted weighted average number of shares as the effect was anti-dilutive.

B) Common Share Dividends


	2024		2023
For the six months ended June 30,	Per Share	Amount	Per Share	Amount
Base Dividends	0.320	596	0.245	465
Variable Dividends	0.135	251	—	—
Total Common Share Dividends Declared and Paid	0.455	847	0.245	465

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

On July 31, 2024, the Company’s Board of Directors declared a third quarter base dividend of $0.180 per common share, payable on September 27, 2024, to common shareholders of record as at September 13, 2024.

C) Preferred Share Dividends


For the six months ended June 30,	2024	2023
Series 1 First Preferred Shares	3	3
Series 2 First Preferred Shares	1	1
Series 3 First Preferred Shares	6	6
Series 5 First Preferred Shares	5	5
Series 7 First Preferred Shares	3	3
Total Preferred Share Dividends Declared	18	18

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

In the six months ended June 30, 2024, the Company paid preferred share dividends of $18 million (2023 – $27 million). On July 2, 2024, the Company paid preferred share dividends of $9 million, as declared on April 30, 2024.

On July 31, 2024, the Company’s Board of Directors declared third quarter dividends of $9 million payable on October 1, 2024, to preferred shareholders of record as at September 13, 2024.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			17

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



9. EXPLORATION AND EVALUATION ASSETS, NET


			Total
As at December 31, 2023			738
Acquisition			7
Additions			33
Transfer to PP&E (Note 10)			(139)





As at June 30, 2024			639



10. PROPERTY, PLANT AND EQUIPMENT, NET


	Crude Oil and Natural Gas Properties	Processing, Transportation and Storage Assets	Refining Assets	Other Assets (1)	Total
COST
As at December 31, 2023	47,425	272	12,770	1,908	62,375
Acquisitions	8	—	—	—	8
Additions	1,875	2	265	16	2,158
Transfer from E&E (Note 9)	139	—	—	—	139
Change in Decommissioning Liabilities	11	—	—	—	11
Divestitures (Note 6)	(122)	—	—	—	(122)
Exchange Rate Movements and Other	48	—	350	1	399

As at June 30, 2024	49,384	274	13,385	1,925	64,968

ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2023	17,975	129	5,667	1,354	25,125
Depreciation, Depletion and Amortization	1,971	6	269	43	2,289


Divestitures (Note 6)	(80)	—	—	—	(80)
Exchange Rate Movements and Other	57	(1)	177	1	234

As at June 30, 2024	19,923	134	6,113	1,398	27,568

CARRYING VALUE
As at December 31, 2023	29,450	143	7,103	554	37,250
As at June 30, 2024	29,461	140	7,272	527	37,400

(1)Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			18

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



11. LEASES

A) Right-of-Use Assets, Net


	Real Estate	Transportation and Storage Assets (1)	Refining Assets	Other Assets (2)	Total
COST
As at December 31, 2023	588	1,964	161	70	2,783

Additions	1	7	—	14	22





Exchange Rate Movements and Other	—	68	10	4	82

As at June 30, 2024	589	2,039	171	88	2,887

ACCUMULATED DEPRECIATION
As at December 31, 2023	156	863	65	19	1,103
Depreciation	18	98	12	11	139


Exchange Rate Movements and Other	1	3	4	—	8

As at June 30, 2024	175	964	81	30	1,250

CARRYING VALUE
As at December 31, 2023	432	1,101	96	51	1,680
As at June 30, 2024	414	1,075	90	58	1,637

(1)Includes railcars, barges, vessels, pipelines, caverns and storage tanks.

(2)Includes assets in the commercial fuels business, fleet vehicles, camp and other equipment.

B) Lease Liabilities


			Total
As at December 31, 2023			2,658

Additions			20
Interest Expense (Note 4)			79
Lease Payments			(224)




Exchange Rate Movements and Other			67

As at June 30, 2024			2,600
Less: Current Portion			296
Long-Term Portion			2,304



12. DEBT AND CAPITAL STRUCTURE

A) Short-Term Borrowings


		June 30,	December 31,
As at	Notes	2024	2023
Uncommitted Demand Facilities	i	—	—

WRB Uncommitted Demand Facilities	ii	137	179
Total Debt Principal		137	179

i) Uncommitted Demand Facilities

As at June 30, 2024, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2023 – $1.7 billion) in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at June 30, 2024, there were outstanding letters of credit aggregating to $319 million (December 31, 2023 – $364 million) and no direct borrowings.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			19

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

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 June 30, 2024, US$200 million was drawn on these facilities, of which Cenovus’s proportionate share was US$100 million (C$137 million). As at December 31, 2023, Cenovus’s proportionate share of the capacity was US$225 million and US$135 million (C$179 million) of this capacity was drawn.

B) Long-Term Debt


	June 30,	December 31,
As at	2024	2023
Committed Credit Facility (1)	—	—
U.S. Dollar Denominated Unsecured Notes (2)	5,203	5,028
Canadian Dollar Unsecured Notes	2,000	2,000
Total Debt Principal	7,203	7,028
Debt Premiums (Discounts), Net, and Transaction Costs	72	80
Long-Term Debt	7,275	7,108

(1)The committed credit facility may include Canadian overnight repo rate average loans, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.

(2)Total U.S. dollar denominated unsecured notes as at June 30, 2024, was US$3.8 billion (December 31, 2023 — US$3.8 billion).

As at June 30, 2024, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is below this limit.

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 depreciation, depletion and amortization (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.

Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times and Net Debt at or below $4.0 billion over the long-term at a 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.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			20

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

Net Debt to Adjusted EBITDA


	June 30,	December 31,
As at	2024	2023
Short-Term Borrowings	137	179
Current Portion of Long-Term Debt	—	—
Long-Term Portion of Long-Term Debt	7,275	7,108
Total Debt	7,412	7,287
Less: Cash and Cash Equivalents	(3,154)	(2,227)
Net Debt	4,258	5,060

Net Earnings (Loss)	4,783	4,109
Add (Deduct):
Finance Costs, Net (1)	494	538

Income Tax Expense (Recovery)	1,479	931
Depreciation, Depletion and Amortization	4,895	4,644
Exploration and Evaluation Asset Write-downs	29	29
(Income) Loss From Equity-Accounted Affiliates	(76)	(51)
Unrealized (Gain) Loss on Risk Management	60	52
Foreign Exchange (Gain) Loss, Net	213	(67)
(Gain) Loss on Divestiture of Assets (1)	(106)	20
Re-measurement of Contingent Payments	73	59

Other (Income) Loss, Net	(174)	(63)
Adjusted EBITDA (2)	11,670	10,201

Net Debt to Adjusted EBITDA (times)	0.4	0.5

(1)Revised presentation as of January 1, 2024. See Note 3.

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

Net Debt to Adjusted Funds Flow


	June 30,	December 31,
As at	2024	2023
Net Debt	4,258	5,060

Cash From (Used in) Operating Activities	10,416	7,388
(Add) Deduct:
Settlement of Decommissioning Liabilities	(229)	(222)
Net Change in Non-Cash Working Capital	533	(1,193)
Adjusted Funds Flow (1)	10,112	8,803

Net Debt to Adjusted Funds Flow (times)	0.4	0.6

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

Net Debt to Capitalization


	June 30,	December 31,
As at	2024	2023
Net Debt	4,258	5,060
Shareholders’ Equity	30,012	28,698
Capitalization	34,270	33,758

Net Debt to Capitalization (percent)	12	15


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			21

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



13. CONTINGENT PAYMENTS

In connection with the transaction with BP Canada Energy Group ULC (“bp Canada”) to purchase the remaining 50 percent interest in Sunrise Oil Sands Partnership (“SOSP”), Cenovus agreed to make quarterly variable payments totaling 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 term of the contract is $40 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.

Payments made during the six months ended June 30, 2024, totaled $157 million for the quarterly payment periods ending November 30, 2023, and February 29, 2024.


			Total
As at December 31, 2023			164

Liabilities Settled or Payable			(154)
Re-measurement			30
As at June 30, 2024			40



14. DECOMMISSIONING LIABILITIES


			Total
As at December 31, 2023			4,155

Liabilities Incurred			11

Liabilities Settled			(96)
Liabilities Disposed			(57)



Unwinding of Discount on Decommissioning Liabilities (Note 4)			113
Exchange Rate Movements			10
As at June 30, 2024			4,136

As at June 30, 2024, the undiscounted amount of estimated future cash flows required to settle the obligation was discounted using a credit-adjusted risk-free rate of 5.5 percent (December 31, 2023 – 5.5 percent) and assumes an inflation rate of two percent (December 31, 2023 – two percent).



15. OTHER LIABILITIES


	June 30,	December 31,
As at	2024	2023
Renewable Volume Obligation, Net (1)	483	397
Pension and Other Post-Employment Benefit Plan	260	276
Provision for West White Rose Expansion Project	115	156
Provisions for Onerous and Unfavourable Contracts	66	72
Employee Long-Term Incentives	88	100
Drilling Provisions	3	25


Other	163	157
	1,178	1,183

(1)The gross amounts of the renewable volume obligation and renewable identification numbers asset were $553 million and $70 million, respectively (December 31, 2023 – $785 million and $388 million, respectively).


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			22

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



16. 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


	June 30, 2024		December 31, 2023
	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	1,871,868	16,031	1,909,190	16,320

Issued Upon Exercise of Warrants	2,639	26	2,610	26
Issued Under Stock Option Plans	4,943	66	3,679	58
Purchase of Common Shares Under NCIB	(22,804)	(195)	(43,611)	(373)
Outstanding, End of Period	1,856,646	15,928	1,871,868	16,031

As at June 30, 2024, there were 48.6 million (December 31, 2023 – 45.5 million) common shares available for future issuance under the stock option plan.

C) Normal Course Issuer Bid

On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 133.2 million common shares from November 9, 2023, to November 8, 2024.

For the six months ended June 30, 2024, the Company purchased and cancelled 22.8 million common shares through the NCIB. The shares were purchased at a volume weighted average price of $26.07 per common share for a total of $595 million. Paid in surplus was reduced by $410 million, representing the excess of the purchase price of the common shares over their average carrying value of $400 million and taxes paid of $10 million.

D) Issued and Outstanding – Preferred Shares

For the six months ended June 30, 2024, there were no preferred shares issued. As at June 30, 2024, there were 36 million preferred shares outstanding (December 31, 2023 – 36 million), with a carrying value of $519 million (December 31, 2023 – $519 million).


As at June 30, 2024	Dividend Reset Date	Dividend Rate (percent)	Number of Preferred Shares (thousands)
Series 1 First Preferred Shares	March 31, 2026	2.58	10,740
Series 2 First Preferred Shares (1)	Quarterly	6.60	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 6.77 percent from December 31, 2023, to March 30, 2024, and 6.71 percent for the period from March 31, 2024, to June 29, 2024.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			23

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

E) Issued and Outstanding – Warrants


	June 30, 2024		December 31, 2023
	Number of Warrants (thousands)	Amount	Number of Warrants (thousands)	Amount
Outstanding, Beginning of Year	7,625	25	55,720	184

Exercised	(2,639)	(9)	(2,610)	(8)
Purchased and Cancelled	—	—	(45,485)	(151)
Outstanding, End of Period	4,986	16	7,625	25

The exercise price of the warrants is $6.54 per share. The warrants expire on January 1, 2026.



17. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)


	Pension and Other Post-Employment Benefits	Private Equity Investments	Foreign Currency Translation Adjustment	Total
As at December 31, 2022	99	29	1,342	1,470
Other Comprehensive Income (Loss), Before Tax	(5)	(1)	(296)	(302)
Reclassification on Divestiture	—	—	12	12
Income Tax (Expense) Recovery	1	—	—	1
As at June 30, 2023	95	28	1,058	1,181

As at December 31, 2023	55	85	1,068	1,208
Other Comprehensive Income (Loss), Before Tax	24	140	393	557

Income Tax (Expense) Recovery	(6)	(16)	—	(22)
As at June 30, 2024	73	209	1,461	1,743



18. 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.

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


	Units Outstanding	Units Exercisable
As at June 30, 2024	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	8,788	4,614
Cenovus Replacement Stock Options	441	441
Performance Share Units	7,400	—
Restricted Share Units	8,239	—
Deferred Share Units	1,712	1,712

The weighted average exercise price of NSRs and Cenovus replacement stock options outstanding as at June 30, 2024, were $17.71 and $3.54, respectively.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			24

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024


	Units Granted	Units Vested and Exercised/ Paid Out
For the six months ended June 30, 2024	(thousands)	(thousands)
Stock Options With Associated Net Settlement Rights	2,214	5,144
Cenovus Replacement Stock Options	—	521
Performance Share Units	6,213	8,729
Restricted Share Units	3,324	2,252
Deferred Share Units	177	179


	Weighted Average Exercise Price	Units Exercised
For the six months ended June 30, 2024	($/unit)	(thousands)
Stock Options With Associated Net Settlement Rights Exercised for Net Cash Payment	10.48	4,353
Stock Options With Associated Net Settlement Rights Exercised and Net Settled for Common Shares(1)	11.98	791
Cenovus Replacement Stock Options Exercised and Net Settled for Cash	8.24	484
Cenovus Replacement Stock Options Exercised and Net Settled for Common Shares (2)	5.17	37

(1)NSRs were net settled for 561 thousand common shares.

(2)Cenovus replacement stock options were net settled for 29 thousand common shares.

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


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Stock Options With Associated Net Settlement Rights	3	3	7	7
Cenovus Replacement Stock Options	—	(1)	3	(7)
Performance Share Units	13	18	61	27
Restricted Share Units	17	10	52	21
Deferred Share Units	1	(1)	12	(3)
Stock-Based Compensation Expense (Recovery)	34	29	135	45

PSUs and RSUs granted under the Performance Share Unit Plan and Restricted Share Unit Plan for Local Employees in the Asia Pacific region may only be settled in cash.



19. RELATED PARTY TRANSACTIONS

A) Husky-CNOOC Madura Ltd.

The Company holds a 40 percent interest in the jointly controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture are recorded in (income) loss from equity-accounted affiliates.

For the six months ended June 30, 2024, the Company received $53 million of distributions from HCML (2023 – $38 million) and paid $nil in contributions (2023 – $24 million).

B) Husky Midstream Limited Partnership

The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. The Company’s share of equity investment income related to the joint venture, in excess of cumulated unrecognized losses, distributions received and contributions paid, is recorded in (income) loss from equity-accounted affiliates. The Company charges HMLP for construction and management services, and incurs costs for the use of HMLP’s pipeline systems and transportation and storage services.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			25

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

For the six months ended June 30, 2024, the Company received $65 million in distributions from HMLP (2023 – $56 million) and paid $51 million in contributions (2023 – $62 million).

The carrying value of the Company’s investment in HMLP as at June 30, 2024, was $nil (December 31, 2023 – $nil) due to losses in excess of the equity investment. Cenovus had unrecognized cumulative losses from earnings and OCI, net of tax, of $33 million as at June 30, 2024 (December 31, 2023 – $31 million).

The following table summarizes revenues and associated expenses related to HMLP:


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Revenues from Construction and Management Services	38	31	69	63
Transportation Expenses	71	71	140	138



20. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt, certain portions of other assets and certain portions of 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, certain portions of other assets and certain portions of other liabilities approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end trading prices of long-term debt on the secondary market (Level 2). As at June 30, 2024, the carrying value of Cenovus’s long-term debt was $7.3 billion and the fair value was $6.7 billion (December 31, 2023, carrying value – $7.1 billion; fair value – $6.6 billion).

The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value in other assets. Fair value is determined based on recent market activity, which may include equity transactions of the entity when available (Level 3).

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



			Total
As at December 31, 2023			131
Acquisitions			2
Changes in Fair Value			140
As at June 30, 2024			273

B) Fair Value of Risk Management Assets and Liabilities

Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable and accrued liabilities (for short-term positions), other assets and other liabilities (for long-term positions). Changes in fair value are recorded in (gain) loss on risk management.

The Company’s risk management assets and liabilities consist of 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.

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 is calculated using external valuation models that incorporate observable market data and foreign exchange forward curves (Level 2).


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			26

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

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, which consists of individuals who are knowledgeable and have experience in fair value techniques.

Summary of Risk Management Positions



	June 30, 2024			December 31, 2023
	Risk Management			Risk Management
As at	Asset	Liability	Net	Asset	Liability	Net
Crude Oil, Natural Gas, Condensate and Refined Products	2	1	1	11	19	(8)
Power Contracts	7	—	7	2	—	2
Renewable Power Contracts	—	11	(11)	18	—	18
Foreign Exchange Rate Contracts	—	1	(1)	—	—	—
	9	13	(4)	31	19	12

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:


	June 30,	December 31,
As at	2024	2023
Level 2 – Prices Sourced From Observable Data or Market Corroboration	7	(6)
Level 3 – Prices Sourced From Partially Unobservable Data	(11)	18
	(4)	12

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, 2023			12

Change in Fair Value of Contracts in Place, Beginning of Year			(11)
Change in Fair Value of Contracts Entered Into During the Period			(43)
Fair Value of Contracts Realized During the Period			38

As at June 30, 2024			(4)

C) Earnings Impact of (Gains) Losses From Risk Management Positions


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Realized (Gain) Loss	28	(23)	38	1
Unrealized (Gain) Loss	(7)	46	24	16
(Gain) Loss on Risk Management	21	23	62	17

Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

D) Fair Value of Contingent Payments

The variable payment (Level 3) is carried at fair value. 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 June 30, 2024, the fair value of the variable payment was estimated to be $40 million, applying a credit-adjusted risk-free rate of 5.3 percent.

As at June 30, 2024, average WCS forward pricing for the remaining term of the variable payment is $91.87 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 35.7 percent and 4.9 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 no 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.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			27

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



21. 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.

As at June 30, 2024, the fair value of risk management positions was a net liability of $4 million. As at June 30, 2024, there were foreign exchange contracts with a notional value of US$150 million (December 31, 2023 –$nil) and no interest rate contracts or cross currency interest rate swap contracts outstanding (December 31, 2023 – $nil).

Net Fair Value of Risk Management Positions

As at June 30, 2024

Notional Volumes (1) (2)

Terms (3)

Weighted

Average

Price (2)

Fair Value Asset (Liability)

Futures Contracts Related to Blending (4)

WTI Fixed – Sell

1.7 MMbbls

July 2024 - June 2025

US$76.79/bbl

(7)

WTI Fixed – Buy

1.5 MMbbls

July 2024 - June 2025

US$75.17/bbl

Power Contracts

Renewable Power Contracts

(11)

Other Financial Positions (5)

—

Foreign Exchange Rate Contracts

(1)

Total Fair Value

(4)

(1) Million barrels (“MMbbls”).

(2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month.

(3) Includes individual contracts with varying terms, the longest of which is 12 months.

(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 differentials, light oil differentials and condensate differentials, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts and the Company’s U.S. refining and marketing activities.

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 June 30, 2024	Sensitivity Range	Increase	Decrease
Crude Oil and Condensate Commodity Price	± US$10.00/bbl Applied to WTI, Condensate and Related Hedges	—	—
Crude Oil and Condensate Differential Price (1)	± US$2.50/bbl Applied to Differential Hedges Tied to Production	2	(2)
WCS (Hardisty) Differential Price	± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production	(3)	3
Refined Products Commodity Price	± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges	(1)	1
Natural Gas Commodity Price	± US$1.00/Mcf (2) Applied to Natural Gas Hedges Tied to Production	—	—
Natural Gas Basis Price	± US$0.50/Mcf Applied to Natural Gas Basis Hedges	—	—
Power Commodity Price	± C$20.00/MWh (3) Applied to Power Hedges	87	(87)
U.S. to Canadian Dollar Exchange Rate	± $0.05 in the U.S. to Canadian Dollar Exchange Rate	13	(15)

(1)Excluding WCS at Hardisty.

(2)One thousand cubic feet (“Mcf”).

(3)One thousand kilowatts of electricity per hour (“MWh”).


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			28

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

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 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.

As at June 30, 2024, approximately 77 percent (December 31, 2023 – 83 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 0.4 percent as at June 30, 2024 (December 31, 2023 – 0.4 percent).

C) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price.

As disclosed in Note 12, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at a WTI price of US$45.00 per barrel to manage the Company’s overall debt position.

Undiscounted cash outflows relating to financial liabilities are:


As at June 30, 2024	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities (1)	6,482	—	—	—	6,482
Short-Term Borrowings	137	—	—	—	137
Contingent Payments	40	—	—	—	40
Lease Liabilities (2)	445	715	587	2,509	4,256
Long-Term Debt (2)	321	2,071	1,982	7,035	11,409

(1)Includes current risk management liabilities.

(2)Principal and interest, including current portion, if applicable.



22. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital


	June 30,	December 31,
As at	2024	2023
Total Current Assets	11,647	9,708
Total Current Liabilities	7,029	6,210
Working Capital	4,618	3,498

As at June 30, 2024, adjusted working capital, which excludes the contingent payments, was $4.7 billion (December 31, 2023 – $3.7 billion).

Changes in non-cash working capital are as follows:


	Three Months Ended		Six Months Ended
For the periods ended June 30,	2024	2023	2024	2023
Accounts Receivable and Accrued Revenues	111	126	(578)	191
Income Tax Receivable	(39)	(32)	177	(169)
Inventories	(140)	(83)	(381)	162
Accounts Payable and Accrued Liabilities	640	68	956	(782)
Income Tax Payable	(37)	(23)	(9)	(1,163)
Total Change in Non-Cash Working Capital	535	56	165	(1,761)

Net Change in Non-Cash Working Capital – Operating Activities	494	132	225	(1,501)
Net Change in Non-Cash Working Capital – Investing Activities	41	(76)	(60)	(260)
Total Change in Non-Cash Working Capital	535	56	165	(1,761)


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			29

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

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, 2022	9	—	115	8,691	2,836

Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(115)	—	—



Principal Repayment of Leases	—	—	—	—	(146)
Base Dividends Paid on Common Shares	(465)	—	—	—	—

Dividends Paid on Preferred Shares	(27)	—	—	—	—
Non-Cash Changes:

Finance and Transaction Costs	—	2	—	(10)	—
Lease Acquisitions	—	—	—	—	33
Lease Additions	—	—	—	—	26




Base Dividends Declared on Common Shares	465	—	—	—	—

Dividends Declared on Preferred Shares	18	—	—	—	—
Warrants Purchased and Cancelled	—	711	—	—	—
Exchange Rate Movements and Other	—	—	—	(147)	25
As at June 30, 2023	—	713	—	8,534	2,774

As at December 31, 2023	9	—	179	7,108	2,658
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings	—	—	(39)	—	—



Principal Repayment of Leases	—	—	—	—	(145)
Base Dividends Paid on Common Shares	(596)	—	—	—	—
Variable Dividends Paid on Common Shares	(251)	—	—	—	—

Dividends Paid on Preferred Shares	(18)	—	—	—	—


Non-Cash Changes:

Finance and Transaction Costs	—	—	—	(8)	—

Lease Additions	—	—	—	—	20




Base Dividends Declared on Common Shares	596	—	—	—	—
Variable Dividends Declared on Common Shares	251	—	—	—	—
Dividends Declared on Preferred Shares	18	—	—	—	—

Exchange Rate Movements and Other	—	—	(3)	175	67

As at June 30, 2024	9	—	137	7,275	2,600


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			30

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024



23. 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 June 30, 2024	Remainder of Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1) (2)	1,062	2,053	1,860	1,841	1,832	16,225	24,873
Product Purchases	225	—	—	—	—	—	225

Real Estate	31	63	63	61	60	605	883
Obligation to Fund HCML	49	97	97	92	54	93	482
Other Long-Term Commitments	351	201	185	166	159	728	1,790
Total Commitments	1,718	2,414	2,205	2,160	2,105	17,651	28,253

(1)Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $683 million. Terms are up to 20 years on commencement.

(2)As at June 30, 2024, includes $2.0 billion related to transportation and storage commitments with HMLP.

There were outstanding letters of credit aggregating to $319 million (December 31, 2023 – $364 million) issued as security for financial and performance conditions under certain contracts.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its 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.



24. PRIOR PERIOD REVISIONS

Certain comparative information presented in the Consolidated Statements of Comprehensive Income (Loss) and segment disclosures was revised for classification changes.

•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. Refining segments on a net basis, which resulted in a reclassification between gross sales and purchased product.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			31

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the periods ended June 30, 2024

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


	Three Months Ended June 30, 2023			Six Months Ended June 30, 2023
Oil Sands Segment	Previously Reported	Revisions	Revised Balance	Previously Reported	Revisions	Revised Balance
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. Refining 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	(2,092)	248	(1,844)	(4,017)	677	(3,340)
Purchased Product	(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
Purchased Product, Transportation and Blending (1)	8,350	(59)	8,291	16,995	(143)	16,852
Operating	1,541	59	1,600	3,093	143	3,236
	9,891	—	9,891	20,088	—	20,088

(1)Revised presentation as of January 1, 2024. See Note 3.


Cenovus Energy Inc. – Q2 2024 Interim Consolidated Financial Statements			32

Exhibit 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 June 30, 2024.

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: N/A

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 April 1, 2024 and ended on June 30, 2024 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 1, 2024

/s/ Jonathan M. McKenzie

Jonathan M. McKenzie

President & Chief Executive Officer

Exhibit 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 June 30, 2024.

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

5.2 ICFR - material weakness relating to design: N/A

5.3 Limitation on scope of design: N/A

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 April 1, 2024 and ended on June 30, 2024 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 1, 2024

/s/ Karamjit S. Sandhar

Karamjit S. Sandar

Executive Vice-President & Chief Financial Officer

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