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

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


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

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