Cenovus Energy Inc.

Management's Discussion and Analysis (unaudited)

For the Period Ended March 31, 2026 (Canadian Dollars)



MANAGEMENT'S DISCUSSION AND ANALYSIS

For the period ended March 31, 2026

TABLE OF CONTENTS

OVERVIEW OF CENOVUS ......................................................................................................................................................... 3

QUARTERLY RESULTS OVERVIEW ............................................................................................................................................ 3

OPERATING AND FINANCIAL RESULTS..................................................................................................................................... 5

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS................................................................................................ 9

OUTLOOK 12

REPORTABLE SEGMENTS 13

UPSTREAM 13

OIL SANDS 13

CONVENTIONAL 17

OFFSHORE 18

DOWNSTREAM 20

CANADIAN REFINING 20

U.S. REFINING 22

CORPORATE AND ELIMINATIONS 23

LIQUIDITY AND CAPITAL RESOURCES 24

RISK MANAGEMENT AND RISK FACTORS 28

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES 28

CONTROL ENVIRONMENT 29

ADVISORY 29

ABBREVIATIONS AND DEFINITIONS 32

SPECIFIED FINANCIAL MEASURES 33

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 May 5, 2026, should be read in conjunction with our March 31, 2026 unaudited interim Consolidated Financial Statements and accompanying notes ("interim Consolidated Financial Statements"), the December 31, 2025 audited Consolidated Financial Statements and accompanying notes ("Consolidated Financial Statements") and the December 31, 2025 MD&A ("annual MD&A"). All of the information and statements contained in this MD&A are made as at May 5, 2026, 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 May 5, 2026. 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.

‌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.

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 North America and internationally. Our physically and economically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil price differentials and contribute to our net earnings by capturing value from crude oil, natural gas and NGLs production through to the sale of finished products such as transportation fuels.

‌QUARTERLY RESULTS OVERVIEW

In the first quarter of 2026, we continue to deliver strong and reliable operations across all areas of our business through the disciplined execution of our business plan. Our financial results reflect solid operational performance and an overall improvement in the commodity price environment compared with the fourth quarter of 2025.

  • Ongoing commitment to safety. Safety is our top value. Strengthening our safety record and maintaining reliable operations throughout our portfolio continues to be our focus.

  • Strong upstream production. Total upstream production increased to 972.1 thousand BOE per day, primarily due to a full quarter of additional production from the acquisition of MEG Energy Corp. ("MEG") through a plan of arrangement that closed on November 13, 2025 (the "MEG Acquisition").

  • Integration of MEG. Following the MEG Acquisition, we accelerated our redevelopment program at Christina Lake North, with the first redevelopment wells achieving first oil in April. In parallel, we executed a delineation program to further progress the expansion project and continued advancing optimization activities at the Christina Lake North facility. By the end of the first quarter of 2026, corporate integration and initial synergy capture initiatives were substantially complete.

  • Advanced key Oil Sands growth projects. Our results in the first quarter reflect the success of key growth projects completed in the second half of 2025, including the continued ramp-up of production from the Narrows Lake tie-back to Christina Lake and incremental volumes from the Foster Creek optimization project. We continued to progress the heavy oil drilling program at our Lloydminster conventional heavy oil assets. In April 2026, the first of the new well pads in the east development area was brought online for the Sunrise growth project and production commenced. The Foster Creek Amine Claus project was mechanically completed and commissioning work is underway.

  • Progressed the West White Rose project. Subsequent to March 31, 2026, we completed systems integration testing and commenced drilling operations. We are now on track to deliver first oil in the third quarter of 2026.

  • Strong downstream operations. Average crude oil throughput ("throughput") across our downstream assets was

    458.5 thousand barrels per day, representing crude unit utilization of 97 percent. Our Canadian assets continue to run at or above capacity, while our U.S. assets continue to demonstrate reliable operations, allowing us to capture opportunities from changing market conditions.

  • Reported solid financial results. Adjusted Funds Flow increased to $3.4 billion from $2.7 billion in the fourth quarter of 2025, driven by higher commodity prices, increased Oil Sands sales volumes and strong operational performance across our assets. Cash from operating activities was $2.2 billion, a decrease from $2.4 billion in the fourth quarter of 2025, mainly due to changes in non-cash working capital.

  • Reduced long-term debt. We repaid $500 million under our term loan facility, which was obtained to fund a portion of the cash consideration for the MEG Acquisition.

  • Delivered significant returns to shareholders. We returned $1.0 billion to common and preferred shareholders, including $379 million through common and preferred share dividends, $356 million through the purchase of 11.5 million common shares under our normal course issuer bid ("NCIB") and $300 million for the redemption of the Company's series 1 and 2 preferred shares.

  • Base dividend increase. On May 5, 2026, the Board declared a second quarter base dividend of $0.220 per common share, an increase of 10 percent from the first quarter dividend declared in February 2026.

Summary of Quarterly Results

2026 2025 2024

($ millions, except where indicated) Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2

Upstream Production Volumes (1) (2) (MBOE/d)

972.1

917.9

832.9

765.9

818.9

816.0

771.3

800.8

Downstream Total Processed Inputs (3) (4) (Mbbls/d)

484.4

498.4

757.6

714.9

700.5

700.5

674.4

652.9

Crude Oil Unit Throughput (3) (Mbbls/d)

458.5

465.5

710.7

665.8

665.4

666.7

642.9

622.7

Downstream Production Volumes (1) (3) (Mbbls/d)

509.3

527.5

770.3

729.4

722.4

722.6

685.2

659.5

Revenues (5)

12,356

10,883

13,195

12,319

13,299

12,813

13,819

14,582

Operating Margin (6)

4,442

2,777

2,954

2,066

2,811

2,274

2,408

2,936

Operating Margin - Upstream (7)

3,708

2,628

2,590

2,137

3,048

2,670

2,731

3,089

Operating Margin - Downstream (7)

734

149

364

(71)

(237)

(396)

(323)

(153)

Cash From (Used In) Operating Activities

2,181

2,408

2,131

2,374

1,315

2,029

2,474

2,807

Adjusted Funds Flow (6)

3,377

2,674

2,466

1,519

2,212

1,601

1,960

2,361

Per Share - Basic (6) ($)

1.80

1.47

1.38

0.84

1.21

0.88

1.06

1.27

Per Share - Diluted (6) ($)

1.80

1.46

1.38

0.84

1.21

0.87

1.05

1.26

Capital Investment

1,170

1,360

1,154

1,164

1,229

1,478

1,346

1,155

Free Funds Flow (6)

2,207

1,314

1,312

355

983

123

614

1,206

Excess Free Funds Flow (6)

1,723

(1,597)

745

(306)

373

(416)

146

735

Net Earnings (Loss)

1,570

934

1,286

851

859

146

820

1,000

Per Share - Basic ($)

0.84

0.51

0.72

0.47

0.47

0.08

0.44

0.53

Per Share - Diluted ($)

0.83

0.50

0.72

0.45

0.47

0.07

0.42

0.53

Total Assets

64,848

63,424

53,573

55,820

56,380

56,539

54,680

56,000

Long-Term Debt, Including Current Portion

10,633

11,032

7,156

7,241

7,524

7,534

7,199

7,275

Net Debt

8,058

8,292

5,255

4,934

5,079

4,614

4,196

4,258

Cash Returns to Common and Preferred Shareholders

1,035

1,094

1,274

819

595

706

1,070

1,034

Common Shares - Base Dividends

377

376

356

364

327

330

329

334

Base Dividends Per Common Share ($)

0.200

0.200

0.200

0.200

0.180

0.180

0.180

0.180

Common Shares - Variable Dividends

-

-

-

-

-

-

-

251

Variable Dividends Per Common Share ($)

-

-

-

-

-

-

-

0.135

Purchase of Common Shares Under NCIB

356

714

918

301

62

108

732

440

Dividends Paid on Preferred Shares

2

4

-

4

6

18

9

9

Preferred Share Redemptions

300

-

-

150

200

250

-

-

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

  2. Includes results of the MEG Acquisition from November 13, 2025.

  3. Represents Cenovus's net interest in refining operations. On September 30, 2025, Cenovus divested its entire 50 percent interest in the jointly-owned Wood River and Borger refineries held through WRB Refining LP ("WRB") (the "WRB Divestiture"). Following the WRB Divestiture, all refining operations are wholly-owned.

  4. Total processed inputs include crude oil and other feedstocks. Blending is excluded.

  5. 2024 comparative periods reflect certain revisions. See the Prior Period Revisions section in our annual MD&A for the year ended December 31, 2024, for further details.

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

  7. Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.

‌OPERATING AND FINANCIAL RESULTS

Selected Operating Results - Upstream

Three Months Ended March 31, Percent 2026 Change

2025

Production Volumes by Segment (1) (MBOE/d)

Oil Sands (2)

775.0

24

626.2

Conventional (3)

121.7

(2)

123.9

Offshore (3)

75.4

10

68.8

Total Production Volumes

972.1

19

818.9

Production Volumes by Product (1)

Bitumen (Mbbls/d)

743.6

23

602.5

Heavy Crude Oil (Mbbls/d)

29.0

33

21.8

Light Crude Oil (Mbbls/d)

24.3

45

16.8

NGLs (Mbbls/d)

33.2

11

29.8

Conventional Natural Gas (MMcf/d)

852.0

(4)

887.9

Total Production Volumes (MBOE/d)

972.1

19

818.9

  1. Refer to the Oil Sands, Conventional and Offshore reportable segments section of this MD&A for a summary of production by product type.

  2. Results for the three months ended March 31, 2026, include the MEG Acquisition, which closed on November 13, 2025.

  3. Reported production volumes in the Conventional and Offshore segments include Cenovus's 30 percent equity interest in the Duvernay Energy Corporation ("Duvernay") joint venture and 40 percent equity interest in the Husky-CNOOC Madura Limited ("HCML") joint venture, respectively. Our equity interests in Duvernay and HCML are accounted for using the equity method in the interim Consolidated Financial Statements.

    Production

    Total upstream production increased in the first quarter of 2026 compared with the first quarter of 2025, primarily due to:

    • Additional production at Christina Lake from the MEG Acquisition and the continued ramp-up of production following the completion of the Narrows Lake tie-back to Christina Lake in the third quarter of 2025.

    • Incremental production from the completion of the Foster Creek optimization project in the fourth quarter of 2025 and successful base well optimization activities.

    • Successful results from redevelopment and sustaining programs at Sunrise.

    • Strong production from our Atlantic operations in the Offshore segment following the completion of the SeaRose

asset life extension ("ALE") project in the first quarter of 2025.

Selected Operating Results - Downstream

Three Months Ended March 31, Percent 2026 Change

2025

Crude Oil Unit Throughput by Segment (Mbbls/d) Canadian Refining

U.S. Refining

115.3

343.2

3

(38)

111.9

553.5

Total Crude Oil Unit Throughput

458.5

(31)

665.4

Production Volumes by Product (1) (Mbbls/d)

Gasoline

185.1

(35)

284.7

Distillates (2)

138.5

(38)

224.3

Synthetic Crude Oil

52.0

(1)

52.4

Asphalt

34.7

(18)

42.3

Ethanol

5.5

28

4.3

Other

93.5

(18)

114.4

Total Production Volumes

509.3

(29)

722.4

  1. Refer to the Canadian Refining and U.S. Refining reportable segments section of this MD&A for a summary of production by product type.

  2. Includes diesel and jet fuel.

    In the first quarter of 2026, total downstream throughput and refined product production decreased compared with the same period in 2025, primarily due to the WRB Divestiture completed on September 30, 2025. The decreases were partially offset by our Canadian Refining assets running at, or above, full capacity, and reliable operations at our U.S. Refining assets.

    Selected Consolidated Financial Results

    Revenues

    During the first quarter of 2026, revenues decreased seven percent compared with the first quarter of 2025, primarily due to lower sales volumes from our U.S. Refining segment as a result of the WRB Divestiture. The decrease was partially offset by higher Oil Sands sales volumes following the MEG Acquisition and our downstream results being positively impacted by higher distillate pricing.

    Operating Margin

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

    Three Months Ended March 31,

    ($ millions)

    2026

    2025

    Gross Sales

    External Sales

    13,339

    14,205

    Intersegment Sales

    2,658

    2,752

    15,997

    16,957

    Royalties

    (983)

    (906)

    Revenues

    15,014

    16,051

    Expenses

    Purchased Product

    5,622

    8,249

    Transportation and Blending

    3,375

    3,247

    Operating Expenses

    1,573

    1,747

    Realized (Gain) Loss on Risk Management

    2

    (3)

    Operating Margin

    4,442

    2,811

    Operating Margin by Segment

    Three Months Ended March 31, 2026 and 2025

    3,095

    2,544

    211

    173

    402 331

    201

    533

    68

    (305)

    4,000

    ($ millions)

    2,000

    -

    (2,000)

    Oil Sands Conventional Offshore Canadian Refining U.S. Refining

    Q1 2026 Q1 2025

    Operating Margin increased in the first quarter of 2026 compared with the first quarter of 2025, primarily due to:

    • Higher Gross Margin in our downstream segments, due to the benefit of processing feedstock purchased at lower prices and higher distillate pricing.

    • Higher Operating Margin in our Oil Sands segment, primarily due to a full quarter of operations from the MEG Acquisition.

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 March 31,

($ millions)

2026

2025

Cash From (Used in) Operating Activities

2,181

1,315

(Add) Deduct:

Settlement of Decommissioning Liabilities

(53)

(36)

Net Change in Non-Cash Working Capital

(1,143)

(861)

Adjusted Funds Flow

3,377

2,212

Adjusted Funds Flow was higher in the first quarter of 2026 compared with the same period in 2025, primarily due to increased Operating Margin, partially offset by higher current tax expense.

Cash from operating activities increased in the first quarter of 2026 compared with the first quarter of 2025, primarily due to increased Operating Margin, partially offset by changes in non-cash working capital and higher current tax expense. The net change in non-cash working capital was a use of cash of $1.1 billion, compared with $861 million in first quarter of 2025, primarily due to an increase in accounts receivable and inventories, partially offset by higher accounts payable and lower income tax receivable.

Net Earnings (Loss)

Net earnings in the first quarter of 2026 was $1.6 billion, compared with $859 million in first quarter of 2025, due to higher Operating Margin, as discussed above, partially offset by higher income tax expense, general and administrative expense, and DD&A expense.

Net Debt

As at

March 31, 2026

December 31, 2025

Current Portion of Long-Term Debt

-

-

Long-Term Portion of Long-Term Debt

10,633

11,032

Total Debt

10,633

11,032

Less: Cash and Cash Equivalents

(2,575)

(2,740)

Net Debt

8,058

8,292

Total Debt decreased $399 million from December 31, 2025, primarily due to the repayment of $500 million under our term loan facility, partially offset by unrealized foreign exchange losses on U.S. dollar denominated long-term debt due to the weakening of the Canadian dollar.

Net Debt decreased $234 million from December 31, 2025, due to cash from operating activities of $2.2 billion and net proceeds on repurchase agreements of $294 million, partially offset by capital investment of $1.2 billion and returns to shareholders of $1.0 billion. For further details, see the Liquidity and Capital Resources section of this MD&A.

Capital Investment (1) Three Months Ended March 31,

($ millions)

2026

2025

Upstream

Oil Sands

851

763

Conventional

93

122

Offshore

142

241

Total Upstream

1,086

1,126

Downstream

Canadian Refining

24

22

U.S. Refining

58

77

Total Downstream

82

99

Corporate and Eliminations

2

4

Total Capital Investment

1,170

1,229

  1. Includes expenditures on property, plant and equipment ("PP&E"), exploration and evaluation ("E&E") assets, and capitalized interest. Excludes capital expenditures related to joint ventures accounted for using the equity method in the interim Consolidated Financial Statements.

    Capital investment in the first quarter of 2026 was primarily related to:

    • Sustaining activities in our Oil Sands segment including the delivery of our integrated winter program.

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

    • Sustaining activities in our refining segments.

    • The support and progression of growth projects.

      During the first quarter of 2026, we advanced key growth projects across our business:

    • At Christina Lake, we accelerated our redevelopment program at Christina Lake North, with the first redevelopment wells achieving first oil in April. In parallel, we executed a delineation program to further progress the expansion project and continued advancing optimization activities at the Christina Lake North facility.

    • At Lloydminster, the conventional heavy oil drilling program continued to progress with new production brought online during the quarter.

    • As part of the Sunrise growth project, we brought the first of the new well pads online in the east development area in April 2026.

    • We achieved mechanical completion for the Foster Creek Amine Claus project and commissioning work is underway.

Subsequent to March 31, 2026, we completed systems integration testing and commenced drilling operations at the West White Rose project. We are now on track to deliver first oil in the third quarter of 2026.

Drilling Activity

Net Stratigraphic Test Wells

and Observation Wells

Net Production Wells (1)

Three Months Ended March 31,

2026

2025

2026

2025

Foster Creek

78

73

5

8

Christina Lake (2)

111

65

19

5

Sunrise

18

21

-

-

Lloydminster Thermal

2

-

11

2

Lloydminster Conventional Heavy Oil

-

-

6

9

209

159

41

24

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

  2. Results for the three months ended March 31, 2026, include the MEG Acquisition, which closed on November 13, 2025.

Stratigraphic test wells were drilled to help identify future well pad locations and to further evaluate our assets. Observation wells were drilled to gather information and monitor reservoir conditions.

Three Months Ended March 31, 2026 Three Months Ended March 31, 2025

(net wells)

Drilled

Completed

Tied-in

Drilled

Completed

Tied-in

Conventional (1)

15

7

7

13

14

13

  1. Includes values attributable to Cenovus's 30 percent equity interest in the Duvernay joint venture.

In the Offshore segment, no wells were drilled or completed in the first quarter of 2026 or 2025.

‌COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results. For a full discussion of our commodity prices and related key performance drivers, refer to our 2025 annual MD&A.

Selected Benchmark Prices and Exchange Rates (1)

(Average US$/bbl, unless otherwise indicated) Q1 2026

Percent Change Q1 2025 Q4 2025

Dated Brent

80.61

7

75.66 63.69

WTI

71.93

1

71.42 59.14

Differential Dated Brent - WTI

8.68

105

4.24 4.55

WCS at Hardisty

57.76

(2)

58.75 47.94

Differential WTI - WCS at Hardisty

14.17

12

12.67 11.20

WCS at Hardisty (C$/bbl)

79.21

(6)

84.31 66.89

WCS at Nederland

65.21

(4)

67.74 55.63

Differential WTI - WCS at Nederland

6.72

83

3.68 3.51

Condensate (C5 at Edmonton)

71.40

2

69.88 57.01

Differential Condensate - WTI Premium/(Discount)

(0.53)

(66)

(1.54) (2.13)

Differential Condensate - WCS at Hardisty Premium/(Discount)

13.64

23

11.13 9.07

Condensate (C$/bbl)

97.91

(2)

100.29 79.54

Synthetic at Edmonton

71.54

4

69.07 57.84

Differential Synthetic - WTI Premium/(Discount)

(0.39)

(83)

(2.35) (1.30)

Synthetic at Edmonton (C$/bbl)

98.10

(1)

99.12 80.69

Refined Product Prices

Chicago Regular Unleaded Gasoline ("RUL")

81.24

(2)

83.08 70.66

Chicago Ultra-low Sulphur Diesel ("ULSD")

105.95

19

89.12 90.70

Refining Benchmarks

Chicago 3-2-1 Crack Spread (2)

17.55

28

13.68 18.20

Group 3 3-2-1 Crack Spread (2)

17.16

4

16.48 19.25

Renewable Identification Numbers ("RINs")

8.71

83

4.76 6.04

Upgrading Differential (3) (C$/bbl)

18.55

26

14.69 13.53

Natural Gas Prices

AECO (4) (C$/Mcf)

2.01

(7)

2.17 2.23

NYMEX (5) (US$/Mcf)

5.04

38

3.65 3.55

Differential AECO - NYMEX (US$/Mcf)

(3.58)

67

(2.14) (1.94)

Foreign Exchange Rates

US$ per C$1 - Average

0.729

5

0.697 0.717

US$ per C$1 - End of Period

0.717

3

0.696 0.730

Chinese Yuan ("RMB") per C$1 - Average

5.048

-

5.069 5.084

  1. These benchmark prices are not our Realized Sales Prices and represent approximate values. For our Realized Sales Prices refer to the Netback tables in the upstream reportable segments section of this MD&A.

  2. The average 3-2-1 crack spread is an indicator of the adjusted refining margin and is valued on a last-in, first-out accounting basis.

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

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

  5. New York Mercantile Exchange ("NYMEX") natural gas monthly index.

Crude Oil and Condensate Benchmarks

In the first quarter of 2026, global crude oil benchmark prices, Brent and WTI, increased compared with the first quarter of 2025. Prices entered 2026 at lower levels than the previous year, as global supply exceeded demand, leading to a continued building of inventory globally. However, prices spiked following the commencement of the U.S.-Iran conflict as markets rapidly priced in a higher risk of supply disruption. The effective closure of the Strait of Hormuz, a narrow maritime choke point crucial to large volumes of global crude and refined products trade, stranded volumes resulting in a near-term shortfall in global supply. Markets continue to experience very high volatility as this conflict evolves.

The WTI-WCS differential at both Hardisty and Nederland widened in the first quarter of 2026, compared with the same period in 2025. Heavy crude weakened relative to WTI due to high global supply of heavy grades as OPEC+ continued to unwind production cuts, with further downward pressure due to incremental Venezuelan heavy barrels re-entering the export market following the capture of former Venezuela President Nicolas Maduro.

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

In the first quarter of 2026, synthetic crude oil at Edmonton strengthened relative to WTI compared with the same period in 2025. The strength in pricing relative to the first quarter of 2025 was driven in part by strong diesel pricing, as synthetic crude yields a higher proportion of diesel than other crude grades.

In the first quarter of 2026, the average Edmonton condensate benchmark traded at a smaller discount to WTI compared with the first quarter of 2025, due to tight Canadian supply and strong demand for heavy crude blending.

Crude Oil Benchmark Prices (1)

100

(average US$/bbl)

80

60

40

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

2024

2024

2024

2025

2025

2025

2025

2026

2026F

2026F

2026F

2027F

Forward Pricing WTI WCS at Hardisty WCS at Nederland Dated Brent Synthetic at Edmonton

  1. Forward pricing as at March 31, 2026.

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 adjusted refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel, using current-month WTI-based crude oil feedstock prices and valued on a last-in, first-out basis.

In the first quarter of 2026, refined product crack spreads in Chicago and Group 3 increased compared with the first quarter of 2025. The increase is largely a result of sharp price spikes for diesel following the U.S.-Iran conflict, which has limited global supply of refined products, as well as crude. The average cost of RINs was higher in the first quarter of 2026, compared with the same period in 2025, due to weaker U.S. production and imports of renewable diesel and biodiesel causing a decline in RINs generation.

North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices. The strength of refining market crack spreads in the U.S. Midwest and Midcontinent generally reflects the differential between Brent and WTI benchmark prices.

Our adjusted refining margin is affected by various other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output. The benchmark market crack spreads do not precisely mirror the configuration and product output of our refineries, or the location we sell product; however, they are used as a general market indicator. Refer to the Specified Financial Measures Advisory of this MD&A for further details.

Refined Product Benchmarks (1)

60

150

(average US$/bbl - RUL and ULSD)

(average US$/bbl - crack spread)

50 125

40 100

30 75

20 50

10 25

0

Q2 2024

Q3 2024

Q4 2024

Q1 2025

Q2 2025

Q3 2025

Q4 2025

Q1 2026

Q2 2026F

Q3 2026F

Q4 2026F

0

Q1 2027F

Forward Pricing Chicago 3-2-1 Crack Spread Group 3 3-2-1 Crack Spread RUL ULSD

  1. Forward pricing as at March 31, 2026.

Natural Gas Benchmarks

In the first quarter of 2026, AECO prices decreased while NYMEX prices increased, compared with the same period in 2025. The increase in NYMEX prices was supported by strong liquified natural gas ("LNG") demand and winter-driven heating demand, while the decrease in AECO prices was impacted by limited Western Canadian takeaway capacity, causing the AECO discount to NYMEX to widen. In the first quarter of 2026, both Western Canadian and U.S. natural gas production increased compared with the first quarter of 2025. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.

Foreign Exchange and Interest Rate 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. In the first quarter of 2026, on average, the Canadian dollar strengthened relative to the U.S. dollar compared with the first quarter of 2025, negatively impacting our reported revenues and positively impacting our U.S. Refining operating expenses.

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 first quarter of 2026, on average, the Canadian dollar remained relatively consistent to the RMB, compared with the first quarter of 2025.

Our interest income, floating rate 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 March 31, 2026, the Bank of Canada's policy interest rate was 2.25 percent. On April 29, 2026, the Bank of Canada held the policy interest rate at 2.25 percent.

‌OUTLOOK

Commodity Price Outlook

Global crude oil prices entered 2026 lower than the first quarter of 2025, as supply growth outpaced demand following the unwinding of OPEC+ voluntary cuts, with risks that oversupply was likely to continue throughout the year and weigh on prices. The U.S.-Iran conflict resulted in an immediate spike in global prices and altered the short-to-medium-term outlook for all aspects of the energy industry. The effective closure of the Strait of Hormuz introduced high volatility across crude, refined products and natural gas prices, stranding energy supply and introducing a wide range of potential outcomes. Price direction remains highly uncertain and dependent on any deescalation or intensification of the conflict, damage to infrastructure, inventory constraints, production shut-ins, refinery curtailment in the Middle East and other areas dependent on supply from that region and the impact to the economy amongst other unpredictable variables. OPEC+ policy continues to remain crucial to global oil supply and demand balances and prices amid this conflict. Policy and sanction uncertainty related to Venezuelan crude exports continues to influence global heavy crude oil supply and trade flows. The global trade war and ongoing geopolitical tensions may reduce global GDP growth and oil demand, while increasing recessionary risks and potentially having additional knock-on effects to the economy.

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

  • OPEC+ policy and the pace at which OPEC+ unwinds production cuts.

  • In the near-term, there is a higher risk of a tariff-induced global economic slowdown that could slow oil demand.

  • 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 does not exceed Canadian crude oil export capacity.

  • 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.

  • Condensate prices will fluctuate seasonally with oil sands blending demand, import pipeline utilization, and global supply and demand factors.

  • AECO and NYMEX natural gas prices are expected to remain volatile, impacted by LNG export capacity and weather-driven demand factors.

  • 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, the U.S. Administration's policies toward Canada-U.S. trade, crude oil prices and emerging macro-economic factors.

    While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product differentials through the following:

  • Transportation commitments and arrangements - using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.

  • Integration - heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil and spreads on refined products.

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

  • Traditional crude oil storage tanks in various geographic locations.

2026 Corporate Guidance

Our 2026 corporate guidance dated December 10, 2025, remains unchanged and is available on our website at cenovus.com. The following table is a sub-set of our full guidance for 2026:

Capital Investment

($ millions)

Production

(MBOE/d)

Crude Oil Unit Throughput (Mbbls/d)

Upstream

Oil Sands

3,500 - 3,600

755 - 780

Conventional

450 - 500

120 - 125

Offshore

450 - 500

70 - 80

Upstream Total

4,400 - 4,600

945 - 985

Downstream

Canadian Refining

105 - 110

U.S. Refining

325 - 340

Downstream Total

600 - 700

430 - 450

Corporate and Eliminations

Up to 25

‌REPORTABLE SEGMENTS

For a description of our reportable segments, refer to Note 1 of the interim Consolidated Financial Statements.

‌UPSTREAM

‌Oil Sands Financial Results

Three Months Ended March 31,

($ millions)

2026

2025

Gross Sales

External Sales

6,892

5,904

Intersegment Sales

1,892

1,953

8,784

7,857

Royalties

(940)

(861)

Revenues

Expenses

7,844

6,996

Purchased Product

617

632

Transportation and Blending

3,283

3,151

Operating

826

677

Realized (Gain) Loss on Risk Management

23

(8)

Operating Margin

3,095

2,544

Unrealized (Gain) Loss on Risk Management

(90)

(7)

Depreciation, Depletion and Amortization

1,027

834

Exploration Expense

1

4

(Income) Loss from Equity-Accounted Affiliates

-

-

Segment Income (Loss)

2,157

1,713

Operating Results

Three Months Ended March 31,

2026

2025

Total Sales Volumes (1) (MBOE/d)

766.2

636.8

Crude Oil Production by Asset (Mbbls/d)

Foster Creek

223.0

202.7

Christina Lake (2)

358.9

237.8

Sunrise

59.4

52.1

Lloydminster Thermal

102.3

109.9

Lloydminster Conventional Heavy Oil

29.0

21.8

Total Crude Oil Production (3) (Mbbls/d)

772.6

624.3

Natural Gas (1) (MMcf/d)

14.4

11.4

Total Production (MBOE/d)

775.0

626.2

Effective Royalty Rate (4) (percent)

19.2

21.1

Netback (5) ($/bbl)

Realized Sales Price

79.80

80.99

Royalties

13.57

15.03

Transportation and Blending

8.86

9.85

Operating

11.92

11.77

Total Netback ($/bbl)

45.45

44.34

  1. Bitumen, heavy crude oil and natural gas. Natural gas is a conventional natural gas product type.

  2. Results for the three months ended March 31, 2026, include the MEG Acquisition, which closed on November 13, 2025.

  3. Crude oil production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.

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

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

Revenues

Gross sales increased in the first quarter of 2026 compared with the same period in 2025, due to higher sales volumes, partially offset by a slightly lower Realized Sales Price.

Price

Our bitumen and heavy oil production is blended with condensate in order to transport it to market through pipelines. In our Netback calculations, Realized Sales Price excludes the impact of purchased condensate but is influenced by condensate pricing. As the cost of condensate increases relative to the price of blended crude oil or our blend ratio increases, our realized bitumen and heavy oil sales price decreases.

Our Realized Sales Price in the first quarter of 2026 decreased slightly compared with the same period in 2025, reflecting a wider WTI-WCS differential, partially offset by slightly higher WTI benchmark prices.

Sales by Location

Three months ended March 31, 2026

Three months ended March 31, 2025

13%

11% 7%

12%

11%

46%

12% 6%

17%

14%

11%

40%

Alberta West Coast of Canada USGC PADD II Canadian Refining U.S. Refining

In the first quarter of 2026, approximately 31 percent of our sales volumes were sold to third-parties at destinations outside of Alberta, which includes the West Coast of Canada, PADD II and USGC. Approximately 23 percent of our sales volumes were sold to our downstream operations in the quarter.

Production Volumes

Oil Sands crude oil production increased in the first quarter of 2026, compared with the same period in 2025, primarily due to:

  • Additional production at Christina Lake from the MEG Acquisition and the continued ramp-up of production following the completion of the Narrows Lake tie-back to Christina Lake in the third quarter of 2025.

  • Incremental production from the completion of the Foster Creek optimization project in the fourth quarter of 2025 and successful base well optimization activities.

  • Successful redevelopment at our Lloydminster assets resulting in higher reservoir performance.

  • Successful results from the redevelopment and sustaining programs at Sunrise.

The increases were partially offset by the ramp-up of production at our Rush Lake facilities following an incident in the second quarter of 2025. In the fourth quarter of 2025, we successfully restarted production and ramp-up activities are progressing.

Royalties

Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Saskatchewan. Refer to our 2025 annual MD&A for further details.

In the first quarter of 2026, Oil Sands royalties increased compared with the same period in 2025, primarily due to higher sales volumes as a result of the MEG Acquisition, partially offset by lower Alberta sliding scale oil sands royalty rates. The Oil Sands effective royalty rate in the first quarter of 2026 decreased compared with the same period in 2025, mainly due to lower Alberta sliding scale oil sands royalty rates.

Expenses

Transportation and Blending

In the first quarter of 2026, blending expenses increased compared with the same period in 2025, primarily due to higher sales volumes, partially offset by the use of lower priced condensate purchased in prior periods.

In the first quarter of 2026, transportation expenses increased compared with the same period in 2025, primarily due to higher sales volumes, partially offset by a decrease in per-unit transportation expenses.

Per-Unit Transportation Expenses (1)

Three Months Ended March 31,

($/bbl) 2026 2025

Foster Creek

12.28

Christina Lake

8.08

Sunrise

13.55

Lloydminster (2)

2.87

Total Oil Sands

8.86

15.85

6.12

18.07

3.42

9.85

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

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

    Per-unit transportation expenses decreased in the first quarter of 2026 compared with first quarter of 2025, due to:

    • Lower per-unit transportation expenses at Foster Creek, primarily due to lower sales volumes on TMX and lower rail costs. In the first quarter of 2026, 24 percent and 35 percent of our sales volumes were sold at West Coast and U.S. destinations, respectively (2025 - 32 percent and 35 percent, respectively).

    • Lower per-unit transportation expenses at Sunrise, primarily due to lower sales volumes on TMX, partially offset by higher sales volumes to U.S. destinations. In the first quarter of 2026, 28 percent and 37 percent of our sales volumes were sold at West Coast and U.S. destinations, respectively (2025 - 73 percent and 27 percent, respectively).

    • Lower per-unit transportation expenses at Lloydminster, primarily due to lower sales volumes sold at U.S. destinations. During the first quarter of 2026, no sales volumes were sold at U.S. destinations (2025 - two percent).

Lower Oil Sands per-unit transportation expenses, as discussed above, were partially offset by higher per-unit transportation expenses at Christina Lake, primarily due to higher sales volumes on TMX following the MEG Acquisition. During the first quarter of 2026, we shipped eight percent and 16 percent of our total sales volumes at West Coast and U.S. destinations, respectively (2025 - nil and 15 percent, respectively).

Operating

Primary drivers of our operating expenses in the three months ended March 31, 2026, were energy, workforce, and repairs and maintenance. Total operating expenses in the first quarter of 2026 increased compared with the first quarter of 2025, primarily due to higher overall operating costs at our Christina Lake assets related to the additional production from the MEG Acquisition.

Per-Unit Operating Expenses (1)

Three Months Ended March 31, Percent

($/bbl) 2026

Change 2025

Foster Creek

Fuel

2.53

5

2.41

Non-Fuel

7.75

5

7.41

Total

10.28

5

9.82

Christina Lake

Fuel

3.03

21

2.50

Non-Fuel

6.20

(1)

6.26

Total

9.23

5

8.76

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

Per-Unit Operating Expenses (1) - Continued

Three Months Ended March 31, Percent

($/bbl) 2026 Change 2025

Sunrise

Fuel

4.18

(3)

4.33

Non-Fuel

13.57

3

13.22

Total

17.75

1

17.55

Lloydminster (2)

Fuel

3.19

(13)

3.68

Non-Fuel

16.09

9

14.78

Total

19.28

4

18.46

Total Oil Sands

Fuel

3.00

5

2.85

Non-Fuel

8.92

-

8.92

Total

11.92

1

11.77

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

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

    Total Oil Sands per-unit fuel expenses increased in the first quarter of 2026, compared with the same period in 2025, primarily due to higher natural gas consumption from the MEG Acquisition, partially offset by lower average AECO benchmark pricing and lower natural gas consumption at our Lloydminster thermal assets.

    Total Oil Sands per-unit non-fuel expenses were consistent between the first quarter of 2026 and 2025 as the increases in per-unit non-fuel operating expenses at our Foster Creek, Sunrise and Lloydminster assets were offset by the decrease in per-unit non-fuel operating expenses at Christina Lake.

    • Increased per-unit non-fuel costs at our Lloydminster assets were driven by higher workover and GHG compliance costs.

    • Increased per-unit non-fuel costs at Foster Creek primarily due to higher GHG compliance costs, partially offset by slightly higher sales volumes.

    • Slight increase in per-unit non-fuel costs at Sunrise primarily due to higher repairs and maintenance, waste management and workforce costs, partially offset by higher sales volumes.

    • Slight decrease in per-unit non-fuel costs at Christina Lake primarily due to higher sales volumes, partially offset by higher workforce, repairs and maintenance, and chemicals costs.

Depreciation, Depletion and Amortization

In the first quarter of 2026, Oil Sands DD&A expense increased $193 million compared with first quarter of 2025, primarily as a result of the MEG Acquisition.

‌Conventional Financial Results

Three Months Ended March 31,

($ millions)

2026

2025

Gross Sales

External Sales

568

443

Intersegment Sales

469

501

1,037

944

Royalties

(18)

(20)

Revenues Expenses

Purchased Product

1,019

623

924

535

Transportation and Blending

85

90

Operating

110

127

Realized (Gain) Loss on Risk Management

(10)

(1)

Operating Margin

211

173

Unrealized (Gain) Loss on Risk Management

4

-

Depreciation, Depletion and Amortization

134

120

Exploration Expense

-

-

(Income) Loss From Equity-Accounted Affiliates

(1)

-

Segment Income (Loss)

74

53

Operating Results (1)

Three Months Ended March 31,

2026

2025

Total Sales Volumes (MBOE/d)

120.5

123.9

Realized Sales Price (2) ($/BOE) Light Crude Oil ($/bbl)

91.25

89.17

NGLs ($/bbl)

53.98

64.91

Conventional Natural Gas ($/Mcf)

4.31

4.11

Production by Product

Light Crude Oil (Mbbls/d)

6.0

5.2

NGLs (Mbbls/d)

22.9

20.5

Conventional Natural Gas (MMcf/d)

556.4

589.3

Total Production (MBOE/d)

121.7

123.9

Conventional Natural Gas Production (percentage of total)

76

79

Crude Oil and NGLs Production (percentage of total)

24

21

Effective Royalty Rate (3) (percent)

8.8

9.0

Netback (2) ($/BOE) Realized Sales Price

34.49

34.01

Royalties

1.77

1.83

Transportation and Blending

4.22

5.49

Operating

9.60

10.92

Total Netback ($/BOE)

18.90

15.77

  1. Reported production volumes, sales volumes, associated per-unit values and effective royalty rates include Cenovus's 30 percent equity interest in the Duvernay joint venture.

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

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

Revenues

Gross sales increased in the first quarter of 2026, compared with the first quarter of 2025, due to higher commodity trading volumes sourced from third parties and a higher Realized Sales Price, partially offset by lower sales volumes.

Price

Our Realized Sales Price increased slightly in the first quarter of 2026 compared with the same period in 2025, primarily reflecting increased sales volumes to U.S. destinations and a higher average NYMEX natural gas benchmark price, partially offset by lower AECO pricing. In the first quarter of 2026, 30 percent of our natural gas sales volumes were sold at U.S. destinations (2025 - 27 percent) where NYMEX natural gas benchmark prices increased to US$5.04 per Mcf (2025 - US$3.65 per Mcf). The increase was partially offset by AECO natural gas benchmark prices decreasing to $2.01 per Mcf (2025 - $2.17 per Mcf).

Production Volumes

Production volumes decreased slightly in the first quarter of 2026, compared with the same period in 2025. In the first quarter of 2026, we focused on liquids-rich production resulting in higher oil and NGL volumes, offset by lower natural gas volumes.

Royalties

The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties decreased in the first quarter of 2026 compared with the same period in 2025, primarily due to lower benchmark prices used to calculate our royalties. The effective royalty rate in the first quarter of 2026 was relatively consistent with the same period in 2025.

Expenses

Transportation

In the first quarter of 2026, transportation expenses and per-unit transportation expenses decreased compared with the first quarter of 2025, due to lower NGL delivery costs and natural gas tolls.

Operating

Primary drivers of operating expenses in the first quarter of 2026 were repairs and maintenance, workforce and property tax costs. Total operating expenses and per-unit operating expenses decreased compared with the first quarter of 2025, primarily due to lower repairs and maintenance costs.

‌Offshore Financial Results

Three Months Ended March 31,

2026

2025

($ millions)

Atlantic

Asia Pacific

Offshore

Atlantic

Asia Pacific

Offshore

Gross Sales

External Sales

252

297

549

146

305

451

Intersegment Sales

-

-

-

-

-

-

252

297

549

146

305

451

Royalties

(2)

(23)

(25)

(2)

(23)

(25)

Revenues

Expenses

250

274

524

144

282

426

Purchased Product

4

-

4

-

-

-

Transportation and Blending

7

-

7

6

-

6

Operating

82

29

111

64

25

89

Operating Margin (1)

157

245

402

74

257

331

Depreciation, Depletion and Amortization

129

130

Exploration Expense

11

1

(Income) Loss from Equity-Accounted Affiliates

(15)

(8)

Segment Income (Loss)

277

208

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

Operating Results Three Months Ended March 31, 2026 2025

Sales Volumes

Atlantic (Mbbls/d) Asia Pacific (MBOE/d)

China Indonesia (1)

Total Asia Pacific

Total Sales Volumes (MBOE/d)

Production by Product

Atlantic - Light Crude Oil (Mbbls/d) Asia Pacific (1)

NGLs (Mbbls/d)

Conventional Natural Gas (MMcf/d) Total Asia Pacific (MBOE/d)

Total Production (MBOE/d)

Effective Royalty Rate (2) (percent)

Atlantic

Asia Pacific (1)

23.1

15.8

41.5

42.0

15.6

15.2

57.1

57.2

80.2

73.0

18.3

11.6

10.3

9.3

281.2

287.2

57.1

57.2

75.4

68.8

0.9

1.0

11.3

12.6

  1. Reported sales volumes, production volumes and royalty rates reflect Cenovus's 40 percent equity interest in the HCML joint venture.

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

Netbacks (1) Three Months Ended March 31, 2026

($/BOE, except where indicated) Atlantic ($/bbl) China Indonesia Total Offshore (2)

Realized Sales Price

117.24

79.38

58.75

86.27

Royalties

1.03

6.02

14.51

6.24

Transportation and Blending

3.56

-

-

1.02

Operating Expenses

39.36

7.43

9.03

16.93

Netback

73.29

65.93

35.21

62.08

Three Months Ended March 31, 2025

($/BOE, except where indicated)

Atlantic ($/bbl)

China

Indonesia

Total Offshore (2)

Realized Sales Price

102.63

81.01

64.65

82.26

Royalties

1.04

6.13

19.44

7.81

Transportation and Blending

4.25

-

-

0.92

Operating Expenses

45.47

6.00

10.67

15.50

Netback

51.87

68.88

34.54

58.03

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

  2. Reported per-unit values reflect Cenovus's 40 percent equity interest in the HCML joint venture.

Revenues

Gross sales increased in the first quarter of 2026, compared with the same period in 2025, primarily due to higher sales volumes and higher Realized Sales Prices in our Atlantic operations.

Price

Our Atlantic Realized Sales Price increased in the first quarter of 2026, compared with the first quarter of 2025, due to higher benchmark Brent pricing. The prices we receive for natural gas sold in Asia Pacific are set under long-term contracts.

Production Volumes

Atlantic production increased in the first quarter of 2026, compared with the same period in 2025, due to strong production from the White Rose field. In the first and second quarters of 2025, production at the White Rose field was ramping up following the completion of the SeaRose ALE project in the first quarter of 2025.

Asia Pacific production in the first quarter of 2026 was consistent with the same period in 2025.

Royalties

Atlantic royalties were consistent in the first quarter of 2026 compared with the first quarter of 2025. The Atlantic effective royalty rate was 0.9 percent in the first quarter of 2026 (2025 - one percent).

The Asia Pacific effective royalty rate decreased for the first quarter of 2026 compared with the same period in 2025, due to Indonesian government-issued gas price adjustments applied in the period.

Expenses

Transportation

Transportation expenses include the costs of transporting crude oil from the SeaRose and Terra Nova floating production, storage and offloading units ("FPSO") to onshore terminals and storage costs. Transportation expenses for the three months ended March 31, 2026, increased to $7 million (2025 - $6 million), primarily due to higher Atlantic sales volumes.

Operating

Primary drivers of our Atlantic operating expenses in the first quarter of 2026 were repairs and maintenance, and workforce costs. Operating expenses increased compared with the same period in 2025, primarily due to higher sales volumes, and higher repairs and maintenance costs.

Per-unit operating expenses decreased compared with the first quarter of 2025, due to higher Atlantic sales volumes, partially offset by the increase in operating expenses, as discussed above.

Primary drivers of our China operating expenses in the first quarter of 2026 were repairs and maintenance, workforce and insurance costs. Per-unit operating expenses increased in the first quarter of 2026, compared with the same period in 2025, primarily due to higher repairs and maintenance, and workforce costs.

Primary drivers of our Indonesia operating expenses in the first quarter of 2026 were repairs and maintenance, and workforce costs. Per-unit operating expenses decreased compared with the same period in 2025, due to lower vessel and workforce costs.

‌DOWNSTREAM

‌Canadian Refining Financial Results

Three Months Ended March 31,

($ millions)

2026

2025

Revenues

1,407

1,282

Purchased Product

1,060

1,076

Gross Margin (1)

347

206

Expenses

Operating

146

138

Operating Margin

201

68

Depreciation, Depletion and Amortization

45

47

Segment Income (Loss)

156

21

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

Financial Results - Continued Three Months Ended March 31,

($ millions, except where indicated) 2026 2025

Gross Margin

347

206

Add (Deduct):

Inventory Holding (Gain) Loss (1)

(47)

3

Adjusted Gross Margin (2)

300

209

Adjusted Refining Margin (3) ($/bbl)

24.27

17.33

  1. Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the first-in, first-out ("FIFO") or weighted average cost basis, as required by IFRS Accounting Standards.

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

  3. Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader, the Lloydminster Refinery and the commercial fuels business for the three months ended March 31, 2026, were $1.3 billion (2025 - $1.2 billion).

Revenues, Adjusted Gross Margin and Adjusted Refining Margin

Revenues increased in the first quarter of 2026 compared with the first quarter of 2025, due to higher refined product pricing, mainly driven by an increase in diesel pricing, and higher sales volumes. Sales from the Lloydminster Refinery are seasonal and increase during paving season, which typically runs from May through October each year.

Adjusted Gross Margin and Adjusted Refining Margin increased in the first quarter of 2026, compared with the first quarter of 2025, primarily due to the widening of the WTI-WCS differential, higher refined product pricing, as discussed above, and higher sales volumes.

Operating Results Three Months Ended March 31,

(Mbbls/d, except where indicated) 2026 2025

Operable Capacity

108.0

108.0

Total Processed Inputs

124.5

119.5

Crude Oil Unit Throughput

115.3

111.9

Crude Unit Utilization (percent)

107

104

Total Production

132.5

126.5

Synthetic Crude Oil

52.0

52.4

Asphalt

17.8

16.6

Diesel

16.9

15.5

Other

40.3

37.7

Ethanol

5.5

4.3

During the first quarter of 2026, throughput and total production increased slightly compared with the same period in 2025, as our assets continue to run at, or above full capacity, reflecting high reliability.

In the first quarter of 2026, approximately 12 percent of our Oil Sands segment's sales volumes were purchased by our Canadian Refining segment as a source of crude oil feedstock (2025 - 14 percent).

Operating Expenses (1) Three Months Ended March 31,

($ millions, except where indicated) 2026 2025

Operating Expenses - Upgrading and Refining

125

116

Per-Unit Operating Expenses (2) ($/bbl)

11.16

10.81

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

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

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

In the first quarter of 2026, total operating expenses and per-unit operating expenses increased compared with the first quarter of 2025, mainly due to higher repairs and maintenance, including routine tank maintenance. The per-unit increase was partially offset by higher total processed inputs, compared with the first quarter of 2025.

‌U.S. Refining Financial Results

Three Months Ended March 31,

($ millions)

2026

2025

Revenues

4,220

6,423

Purchased Product

3,318

6,006

Gross Margin (1)

902

417

Expenses

Operating

380

716

Realized (Gain) Loss on Risk Management

(11)

6

Operating Margin

533

(305)

Unrealized (Gain) Loss on Risk Management

30

(8)

Depreciation, Depletion and Amortization

112

158

Segment Income (Loss)

391

(455)

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

Three Months Ended March 31,

($ millions, except where indicated) 2026 2025

Gross Margin

902

417

Add (Deduct):

Inventory Holding (Gain) Loss (1)

(457)

23

Adjusted Gross Margin (2)

445

440

Adjusted Refining Margin (2) ($/bbl)

13.74

8.41

Weighted Average Crack Spread, Net of RINs (US$/bbl)

8.79

9.46

Weighted Average Crack Spread, Net of RINs (C$/bbl)

12.06

13.58

Adjusted Market Capture (2) (percent)

114

62

  1. Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the FIFO or weighted average cost basis, as required by IFRS Accounting Standards.

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

    Revenues

    Revenues decreased in the first quarter of 2026, compared with the first quarter of 2025, primarily due to lower sales volumes as a result of the WRB Divestiture, partially offset by higher refined product pricing, mainly driven by strong distillate pricing.

    Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture

    Adjusted Gross Margin increased in the first quarter of 2026, compared with the first quarter of 2025, primarily due to:

    • Achieving safe and reliable operations across our refineries, while maximizing our ability to process heavy crude volumes and capture value from wider WTI-WCS differentials.

    • Business improvement initiatives which began in 2025 and continued to deliver value into 2026, improving our capability to optimize our product yields as market dynamics shifted in a seasonally weaker gasoline pricing environment. This allowed us to benefit from the strong distillate pricing, as discussed above.

    • Seasonal commercial and blending opportunities.

    • Optimization across the portfolio provided greater margin through various regional synergies.

This was partially offset by the impact of the WRB Divestiture and a lower weighted average market crack spread, net of RINs. In the first quarter of 2026, the Group 3 3-2-1 crack spread increased four percent while the Chicago 3-2-1 crack spread increased 28 percent, compared with the first quarter of 2025. The increase in crack spreads was more than offset by an 83 percent increase in the average cost of RINs, compared with the same period in 2025.

Adjusted Refining Margin and Adjusted Market Capture increased in the first quarter of 2026, compared with the same period in 2025, due to the increase in Adjusted Gross Margin discussed above, and lower total processed inputs.

Operating Results Three Months Ended March 31,

(Mbbls/d, except where indicated) 2026 2025

Operable Capacity (1)

364.8

612.3

Total Processed Inputs

359.9

581.0

Crude Oil Unit Throughput

343.2

553.5

Heavy Crude Oil

152.2

226.3

Light/Medium Crude Oil

191.0

327.2

Crude Unit Utilization (percent)

94

90

Total Refined Product Production

376.8

595.9

Gasoline

185.1

284.7

Distillates (2)

121.6

208.8

Asphalt

16.9

25.7

Other

53.2

76.7

  1. Reported operable capacity reflects the impact of the WRB Divestiture completed on September 30, 2025.

  2. Includes diesel and jet fuel.

Throughput and refined product production decreased in the first quarter of 2026, compared with the same period in 2025, primarily due to the WRB Divestiture, partially offset by reliable operations across our assets.

Operating Expenses Three Months Ended March 31,

($ millions, except where indicated) 2026 2025

Operating Expenses

380

716

Per-Unit Operating Expenses (1) ($/bbl)

11.74

13.69

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

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

Overall, operating expenses decreased in the first quarter of 2026, compared with the first quarter of 2025, due to the WRB Divestiture.

Operating expenses and related per-unit metrics decreased across our operated assets in the first quarter of 2026, compared with the first quarter of 2025, primarily due to lower repairs and maintenance costs, partially offset by higher electricity costs.

‌CORPORATE AND ELIMINATIONS

Financial Results

Three Months Ended March 31,

($ millions) 2026 2025

Realized (Gain) Loss on Risk Management

8

(5)

Unrealized (Gain) Loss on Risk Management

55

38

General and Administrative

411

197

Finance Costs, Net

194

136

Integration, Transaction and Other Costs

32

2

Foreign Exchange (Gain) Loss, Net

179

-

(Gain) Loss on Divestiture of Assets

(86)

-

Other (Income) Loss, Net

(38)

(6)

General and Administrative

Primary drivers of our general and administrative expense in the first quarter of 2026 were long-term incentive costs and workforce costs. General and administrative expense increased in the first quarter of 2026, compared with the same period in 2025, primarily due to higher long-term incentive costs, as our closing common share price increased to $36.92 on March 31, 2026, from $23.22 on December 31, 2025.

Finance Costs, Net

Net finance costs were higher in the first quarter of 2026, compared with the same period in 2025, primarily due to increased interest expense from higher average debt. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.

The annualized weighted average interest rate on outstanding debt for the three months ended March 31, 2026, was

4.4 percent (2025 - 4.5 percent).

Foreign Exchange (Gain) Loss, Net Three Months Ended March 31,

($ millions) 2026 2025

Unrealized Foreign Exchange (Gain) Loss

180

Realized Foreign Exchange (Gain) Loss

(1)

179

19

(19)

-

Unrealized foreign exchange losses were primarily due to the translation of U.S. dollar denominated debt. As at March 31, 2026, the Canadian dollar weakened slightly relative to the U.S. dollar as at December 31, 2025.

Income Taxes Three Months Ended March 31,

($ millions) 2026 2025

Current Tax

Canada

479

279

United States

6

-

Asia Pacific

54

45

Other International

8

13

Total Current Tax Expense (Recovery)

547

337

Deferred Tax Expense (Recovery)

(33)

(66)

514

271

For the three months ended March 31, 2026, we recorded current tax expense related to operations in all jurisdictions in which we operate. The increase in current tax expense is due to higher earnings compared with the same period in 2025. The effective tax rate for the first three months was 24.7 percent, relatively consistent with 24.0 percent in the first quarter of 2025.

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review, and with consideration of the current economic environment, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.

‌LIQUIDITY AND CAPITAL RESOURCES

Our capital allocation framework enables us to preserve our balance sheet, provide flexibility in both high and low commodity price environments, and deliver value to shareholders.

We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and cash equivalents, and other sources of liquidity. Our other sources of liquidity include draws on our committed credit facility, draws on our uncommitted demand facilities, and other corporate and financial opportunities, which provide timely access to funding to supplement cash flow. The cost and availability of borrowing, and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.

Three Months Ended March 31,

($ millions) 2026 2025

Cash From (Used In)

Operating Activities

2,181

1,315

Investing Activities

(1,070)

(1,348)

Net Cash Provided (Used) Before Financing Activities

1,111

(33)

Financing Activities

(1,335)

(294)

Effect of Foreign Exchange on Cash and Cash Equivalents

59

2

Increase (Decrease) in Cash and Cash Equivalents

(165)

(325)

March 31, December 31,

As at ($ millions) 2026 2025

Cash and Cash Equivalents

2,575

2,740

Total Debt

10,633

11,032

Cash From (Used in) Operating Activities

In the first quarter of 2026, cash from operating activities increased compared with the same period in 2025, primarily due to increased Operating Margin, partially offset by changes in non-cash working capital and higher current tax expense. Non-cash working capital decreased cash from operating activities by $1.1 billion, primarily due to an increase in accounts receivable and inventories, partially offset by higher accounts payable and lower income tax receivable.

Cash From (Used in) Investing Activities

Cash used in investing activities decreased in the first quarter of 2026 compared with the same period in 2025, primarily due to higher proceeds from divestitures and lower acquisition capital. Cash used in investing activities primarily relates to capital investment.

Cash From (Used in) Financing Activities

In the first quarter of 2026, cash used in financing activities was $1.3 billion, compared with $294 million in the first quarter of 2025, primarily due to the repayment of $500 million under the term loan facility, higher share purchases under the Company's NCIB, and the issuance of $150 million in short-term borrowings in the first quarter of 2025, compared with no issuances in the first quarter of 2026.

Working Capital

Working capital as at March 31, 2026, was $4.1 billion (December 31, 2025 - $3.6 billion). The increase was primarily driven by higher accounts receivable and inventories, partially offset by an increase in accounts payable.

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

Short-Term Borrowings

As at March 31, 2026, the Company had uncommitted demand facilities of $1.5 billion (December 31, 2025 - $1.5 billion) in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. There were no direct borrowings on our uncommitted demand facilities as at March 31, 2026, or December 31, 2025.

Long-Term Debt, Including Current Portion

March 31, December 31,

As at ($ millions) 2026 2025

Term Loan Facility

2,200

U.S. Dollar Denominated Senior Unsecured Notes

5,988

Canadian Dollar Senior Unsecured Notes

2,450

Total Debt Principal

10,638

2,700

5,887

2,450

11,037

As at March 31, 2026, the Company had in place a $2.2 billion term loan facility maturing on February 28, 2029. In the first quarter of 2026, we repaid $500 million under the term loan facility. Subsequent to March 31, 2026, we repaid an additional

$700 million under the term loan facility.

As at March 31, 2026, we were in compliance with all of the terms of our debt agreements, which includes the terms of our committed credit facility and term loan facility. We are required to maintain a debt to capitalization ratio, as defined in the debt agreements, not to exceed 65 percent. We are below this limit.

Available Sources of Liquidity

The following sources of liquidity are available as at March 31, 2026:

($ millions) Maturity Amount Available

Cash and Cash Equivalents

n/a

2,575

Committed Credit Facility (1)

Revolving Credit Facility - Tranche A

September 19, 2029

3,300

Revolving Credit Facility - Tranche B

September 19, 2028

2,200

Uncommitted Demand Facilities (2)

n/a

1,083

  1. No amounts were drawn on the committed credit facility as at March 31, 2026 (December 31, 2025- $nil).

  2. Represents amounts available for cash draws. Our uncommitted demand facilities include $1.5 billion, of which $1.4 billion may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at March 31, 2026, there were outstanding letters of credit aggregating to $372 million (December 31, 2025 - $341 million) and no direct borrowings (December 31, 2025 - $nil).

As at March 31, 2026, the Company had in place a committed credit facility that consists of a $3.3 billion tranche maturing on September 19, 2029, and a $2.2 billion tranche maturing on September 19, 2028. As at March 31, 2026, no amount was drawn on the credit facility (December 31, 2025 - $nil).

Base Shelf Prospectus

On November 28, 2025, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the

U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2028. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.

Financial Metrics

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

As at March 31, 2026 December 31, 2025

Net Debt to Adjusted EBITDA Ratio (times)

0.7

0.9

Net Debt to Adjusted Funds Flow Ratio (times)

0.8

0.9

Net Debt to Capitalization Ratio (percent)

20

21

Our Net Debt to Adjusted EBITDA ratio and our Net Debt to Adjusted Funds Flow ratio targets are approximately 1.0 times and Net Debt at or below $4.0 billion over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices or the strengthening or weakening of the Canadian dollar relative to the U.S. dollar. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, steward working capital, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares. Our Net Debt to Adjusted EBITDA ratio, Net Debt to Adjusted Funds Flow ratio and Net Debt to Capitalization ratio as at March 31, 2026, decreased compared with December 31, 2025, primarily as a result of higher Operating Margin and lower Net Debt. See the Operating and Financial Results section of this MD&A for more information on changes in Operating Margin and Net Debt.

Share Capital and Stock-Based Compensation Plans

Our common shares are listed on the Toronto Stock Exchange and New York Stock Exchange. On March 31, 2026, Cenovus exercised its right to redeem all 10.7 million of the Company's series 1 preferred shares and all 1.3 million of the Company's series 2 preferred shares. The preferred shares were redeemed at a price of $25.00 per share, for a total of $300 million. Following the redemptions on March 31, 2026, the Company no longer has preferred shares outstanding within its capital structure.

As at March 31, 2026, there were approximately 1,875.0 million common shares outstanding (December 31, 2025 -1,883.4 million common shares).

For the three months ended March 31, 2026, the employee benefit plan trust (the "Trust"), through an independent trustee, purchased 1.8 million common shares for a total of $51 million and distributed 3.6 million common shares for a total of $80 million under the employee benefit plan. As at March 31, 2026, there were 3.5 million common shares held by the Trust (December 31, 2025 - 5.3 million common shares). Refer to Note 15 of the interim Consolidated Financial Statements for further details.

The common share purchase warrants expired on January 1, 2026. Refer to Note 15 of the interim Consolidated Financial Statements for further details.

Refer to Note 17 of the interim Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows:

As at May 1, 2026

Units Outstanding

(thousands)

Units Exercisable

(thousands)

Common Shares

1,868,318

n/a

Stock Options

10,591

4,125

Other Stock-Based Compensation Plans

20,749

2,079

Returns to Shareholders

For a full discussion of our returns to shareholders target, refer to the Liquidity and Capital Resources section of our 2025 annual MD&A.

In the first quarter of 2026, we returned $1.0 billion to common and preferred shareholders, including $379 million through common and preferred share dividends, $356 million through the purchase of 11.5 million common shares under our NCIB program and $300 million for the redemption of the Company's series 1 and 2 preferred shares.

The allocation of Excess Free Funds Flow to shareholder returns may be accelerated, deferred or reallocated between quarters at Management's discretion.

Dividends

Common Share Dividends

In the first quarter of 2026, we declared and paid base dividends of $377 million or $0.200 per common share (2025 - $327 million or $0.180 per common share).

On May 5, 2026, the Board declared a second quarter base dividend of $0.220 per common share, an increase of 10 percent from the first quarter dividend declared in February 2026. The dividend is payable on June 30, 2026, to common shareholders of record as at June 15, 2026.

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

Cumulative Redeemable Preferred Share Dividends

In the first quarter of 2026, the Company paid preferred share dividends of $2 million (2025 - $6 million).

Share Repurchases

We have an NCIB program to purchase up to 120.3 million common shares from November 11, 2025, to November 10, 2026.

Three Months Ended March 31, 2026 2025

Common Shares Purchased and Cancelled Under NCIB (millions of common shares)

11.5

3.0

Weighted Average Price per Common Share ($)

30.35

20.68

Purchase of Common Shares Under NCIB ($ millions)

356

62

From April 1, 2026, to May 1, 2026, the Company purchased an additional 7.3 million common shares for $264 million. As at May 1, 2026, the Company can further purchase up to 94.1 million common shares under the NCIB.

Contractual Commitments and Obligations

We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from our total commitments disclosed below. For further information, see Note 22 of the interim Consolidated Financial Statements.

Our total commitments were $39.4 billion as at March 31, 2026 (December 31, 2025 - $39.7 billion), of which $36.7 billion are for various transportation and storage commitments. Transportation commitments include $7.8 billion that are subject to regulatory approval or were approved but are not yet in service. Terms are up to 15 years on commencement.

As at March 31, 2026, our total commitments included commitments with Husky Midstream Limited Partnership ("HMLP") of

$1.8 billion related to long-term transportation and storage commitments (December 31, 2025 - $1.7 billion).

As at March 31, 2026, outstanding letters of credit issued as security for performance under certain contracts totaled

$372 million (December 31, 2025 - $341 million).

Legal Proceedings

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

Transactions with Related Parties Husky Midstream Limited Partnership

The Company holds a 35 percent interest in and is the operator of HMLP. The Company charges HMLP for construction and management services, and incurs costs for the use of HMLP's pipeline systems, as well as transportation and storage services. Access fees and transportation and storage services are based on contractually agreed rates with HMLP.

The following table summarizes revenues and associated expenses related to HMLP:

Three Months Ended March 31,

Revenues from Construction and Management Services

33

29

Transportation Expenses

65

68

($ millions) 2026 2025

‌RISK MANAGEMENT AND RISK FACTORS

For a full understanding of the risks that impact us, the following discussion should be read in conjunction with the Risk Management and Risk Factors section of our 2025 annual MD&A.

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

‌CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, as well as use judgment, in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2025.

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

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements. A full list of the critical judgments used in applying accounting policies and key sources of estimation uncertainty can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2025.

Update to Accounting Policies

Effective January 1, 2026, the Company adopted the amendments to IFRS 9, "Financial Instruments" ("IFRS 9") and IFRS 7, "Financial Instruments: Disclosures" ("IFRS 7"). The amendments clarify the derecognition of financial liabilities and the classification of certain financial assets. The adoption of the amendments to IFRS 9 and IFRS 7 did not have a material impact on the Company's interim Consolidated Financial Statements.

New Accounting Standards and Interpretations Not Yet Adopted

On April 9, 2024, the IASB issued IFRS 18, "Presentation and Disclosure in Financial Statements" ("IFRS 18"), which will replace International Accounting Standard 1, "Presentation of Financial Statements". IFRS 18 will establish a revised structure for the Consolidated Statements of Comprehensive Income (Loss), including new defined subtotals, enhanced principles on aggregation and disaggregation, and additional disclosure requirements related to management-defined performance measures ("MPMs").

The objective of the standard is to improve comparability across entities and reporting periods. IFRS 18 will not impact recognition or measurement of income and expenses.

Cenovus has executed a parallel system environment to reflect the new presentation requirements. The changes will primarily reflect a re-mapping of line items on the Consolidated Statements of Comprehensive Income (Loss) to newly defined categories. Items such as foreign exchange gains and losses will require segregation. The primary impact on the Consolidated Statements of Cash Flows will be the movement of certain finance costs from operating activities to financing activities. The Company has also identified metrics anticipated to be defined as MPMs.

The Company will continue to evaluate the impacts until adoption on January 1, 2027. The standard will be applied retrospectively, with certain transition provisions.

‌CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of Internal Control Over Financial Reporting ("ICFR") and Disclosure Controls and Procedures ("DC&P") as at March 31, 2026. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control - Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at March 31, 2026.

On November 13, 2025, Cenovus completed the MEG Acquisition. As permitted by, and in accordance with, National Instrument 52-109, "Certification and Disclosure in Issuers' Annual and Interim Filings", and guidance issued by the U.S. Securities and Exchange Commission, Management has limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures in respect of the business acquired from MEG. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P relating to the business acquired from MEG in a manner consistent with our other operations. Further integration will take place throughout the remainder of 2026 as processes and systems align.

Assets attributable to MEG as at March 31, 2026, represented approximately 15 percent of Cenovus's total assets, and revenues attributable to MEG for the period of January 1, 2026, to March 31, 2026, represented approximately nine percent of Cenovus's total revenues for the three months ended March 31, 2026.

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

‌ ADVISORY

Oil and Gas Information

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

Light crude oil - Light crude oil corresponds to light crude oil and medium crude oil combined as defined by National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101"). Cenovus does not produce medium crude oil.

Forward-looking Information

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

This forward-looking information is identified by words such as "allocate", "anticipate", "believe", "commit", "continue", "could", "deliver", "expect", "F", "focus", "grow", "maintain", "may", "maximize", "mitigate", "on track", "objective", "ongoing", "opportunities", "optimize", "plan", "potential", "priority", "progress", "steward", "target", and "will", or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our strategic objectives; shareholder returns; commitment to safety and strengthening our safety record while maintaining reliable operations throughout our portfolio; capital allocation framework enabling us to preserve our balance sheet, provide flexibility in both high and low commodity price environments and deliver value to shareholders; our physically and economically integrated upstream and downstream operations helping us mitigate the impact of volatility in light-heavy crude oil price

differentials and contribute to our net earnings by capturing value from crude oil, natural gas and NGLs production through the sale of finished products such as transportation fuels; market and commodity price volatility and stability; price alignment and volatility management strategies; dividends; liquidity; funding our near-term cash requirements through cash from operating activities, the prudent use of our cash and cash equivalents, and other sources of liquidity; our 2026 corporate guidance; factors influencing commodity price outlook; the impact of the global trade war and geopolitical tensions, including the closure of the Strait of Hormuz; capturing on opportunities from changing market conditions; allocating Excess Free Funds Flow to shareholder returns; progressing key growth projects, including continued development of Christina Lake North expansion project with production to come online in the second quarter of 2026, commissioning work at the Foster Creek Amine Claus project, and timing for first oil at West White Rose; heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil and spreads on refined products monitoring market fundamentals and optimizing run rates at our refineries; safe and reliable operations; being best-in-class operators; maintaining a strong balance sheet; costs; margins; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; general outlook for crude oil and refined product prices; price volatility and geopolitical risks; impact of current and future economic arrangements between Canada and the U.S. including tariffs and other measures and countermeasures and responses thereto on market access and transportation; Net Debt to Adjusted EBITDA, Net Debt to Adjusted Funds Flow and Net Debt to Capitalization ratios; maintaining capital discipline to ensure sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company's outlook for commodities and the Canadian dollar, the factors that affect such outlook, and the influences and effects on Cenovus.

Readers are cautioned not to place undue reliance on forward-looking information as the Company's actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast bitumen, crude oil and natural gas, NGLs, condensate and refined products prices, and light-heavy and light-medium crude oil price differentials; the Company's ability to realize the anticipated benefits of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs, projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change Indigenous relations, title or rights claims, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions, trade sanctions, restrictive trade measures or countermeasures, and the supply and demand for bitumen, crude oil and natural gas, NGLs, condensate and refined products and the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, third-party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company's operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company's share price and market capitalization over the long-term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the Company's ability to use financial risk management activities and physical positions to manage its exposure to fluctuations in commodity prices and, foreign exchange and interest rates, optimize supply costs or sales of production; the Company's ability to use fixed-price commitments for the purchase or sale of commodities; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company's asset portfolio and access to capital and insurance coverage to pursue and fund future investments and development plans and dividends, including any increase thereto; realization of expected capacity to store within the Company's oil sands reservoirs barrels not yet produced, including that the Company will be able to time production and sales of its inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and future crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to global supply factors and heavy crude oil processing capacity, as long as supply does not exceed Canadian crude oil export capacity; the Company's ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, NGLs from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; the Company's ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company's ability to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company's ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company's ability to complete acquisitions and divestitures, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third-party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of sustainability commitments and the Oil Sands Alliance Pathways project, and the commercial viability and scalability of related technology and products; expected benefits of investments in sustainability focus areas; collaboration with the government, Oil Sands Alliance and other industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company's 2026 guidance available on cenovus.com and as set out below; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.

2026 guidance dated December 10, 2025, and available on cenovus.com, assumes: Brent prices of US$64.00 per barrel, WTI prices of US$60.00 per barrel; WCS of US$47.50 per barrel; Differential WTI-WCS of US$12.50 per barrel; AECO natural gas prices of $2.50 per Mcf; Chicago 3-2-1 crack spread of US$20.00 per barrel; RINs of US$6.00 per barrel; and an exchange rate of

$0.72 US$/C$.

The risk factors and uncertainties that could cause the Company's actual results to differ materially from the forward-looking information, include, but are not limited to: the Company's ability to realize the anticipated benefits of acquisitions in a timely manner or at all; the Company's ability to successfully integrate acquired business with its own in a timely and cost effective manner or at all; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and divestitures; the Company's ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of sustainability commitments and the Oil Sands Alliance and the commercial viability and scalability of related technology and products; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration and impact of any market downturn; the Company's ability to integrate upstream and downstream operations to help mitigate the impact of volatility in light-heavy crude oil differentials and contribute to its net earnings; foreign exchange risk, including related to agreements denominated in foreign currencies; the Company's continued liquidity being sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential at Hardisty does not remain largely tied to global supply factors and heavy crude processing capacity; the Company's ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company's risk management program; the accuracy of the Company's outlook for commodity prices and currency and interest rates; changes in laws or enforcement of existing laws, exchange rate fluctuations, trade disputes, trade agreements or treaties, new or increased tariffs, economic sanctions and other restrictive trade measures or countermeasures, and responses thereto; product supply and demand; the accuracy of the Company's share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company's marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company's crude-by-rail terminal, including health, safety and environmental risks; the Company's ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company's ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company's ability to finance growth and sustaining capital expenditures; the ability to complete and optimize drilling, completion, tie in and infrastructure projects; the ability of the Company to ramp-up activities at its refineries on its anticipated timelines; changes in credit ratings applicable to the Company or any of its securities; changes to the Company's dividend plans; the Company's ability to utilize tax losses in the future; tax audits and reassessments; the accuracy of the Company's reserves, future production and future net revenue estimates; the accuracy of factors influencing decisions on the priority and timing of development of undeveloped reserves; potential disruptions and risks associated with the adoption, development and integration of AI; the accuracy of the Company's accounting estimates and judgements; the Company's ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company's assets or goodwill from time to time; the Company's ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company's assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and refining processes; the occurrence of unexpected events resulting in operational interruptions, including at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics and pandemics; and catastrophic events, including, but not limited to, war, adverse sea conditions, extreme weather events, natural disasters, acts of activism, vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company's operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry's and the Company's reputation, social licence to operate and litigation related thereto; legal challenges or opposition to infrastructure projects associated with Indigenous title or other rights claims; unexpected cost increases or technical difficulties in operating, constructing or modifying refining or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company's business, including potential cyberattacks; geo-political and other risks associated with the Company's international operations; risks associated with climate change and the Company's assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company's ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps

caused by constraints in the pipeline system or storage capacity; availability of, and the Company's ability to attract and retain, critical talent and integrate new personnel acquired in transactions; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; climate change-related regulatory, climactic transition risks; failure to achieve our sustainability goals, or a perception among key stakeholders that our actions or goals are insufficient or unattainable; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company's business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; OPEC+ policy; actions of OPEC and non-OPEC members, including compliance or non-compliance with agreed upon quotas and decisions to impose production quotas; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company's relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in attempting to achieve goals for sustainability focus areas may have a negative impact on our existing business, growth plans and future results from operations, or that the benefits may be less than expected.

Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company's material risk factors, see Risk Management and Risk Factors in the Company's most recently filed annual MD&A, and the risk factors described in other documents the Company files from time to time with securities regulatory authorities in Canada, available on SEDAR+ at sedarplus.ca, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Company's website at cenovus.com.

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

‌ABBREVIATIONS AND DEFINITIONS

Abbreviations

The following abbreviations and definitions are used in this document:

Crude Oil and NGLs Natural Gas Other

bbl barrel Mcf thousand cubic feet BOE barrel of oil equivalent MBOE/d thousand barrels of oil

Mbbls/d thousand barrels per day MMcf million cubic feet equivalent per day

MMbbls million barrels MMcf/d million cubic feet per day MMBOE million barrels of oil equivalent

DD&A depreciation, depletion and

WCS Western Canadian Select Bcf billion cubic feet amortization

WTI West Texas Intermediate GHG greenhouse gas

FPSO floating production, storage and offloading vessel

NCIB normal course issuer bid

AECO Alberta Energy Company NYMEX New York Mercantile Exchange OPEC Organization of Petroleum

Exporting Countries

OPEC+ OPEC and a group of 11

non-OPEC members

PADD II Petroleum Administration for

Defense District II

USGC U.S. Gulf Coast

‌SPECIFIED FINANCIAL MEASURES

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

These measures may not be comparable to similar measures presented by other issuers. These measures are described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation, or as a substitute for, measures prepared in accordance with IFRS Accounting Standards. The definition and reconciliation, if applicable, of each specified financial measure is presented in this Advisory and may also be presented in the Operating and Financial Results section of this MD&A. Refer to the Specified Financial Measures Advisory of the relevant period's MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow for prior period information from 2025 and 2024 that is not found below.

Non-GAAP Financial Measures and Non-GAAP Ratios Operating Margin

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

Operating Margin

Three Months Ended March 31,

2026

2025

2026

2025

2026

2025

($ millions)

Upstream (1)

Downstream (1)

Total

Gross Sales

External Sales

8,009

6,798

5,330

7,407

13,339

14,205

Intersegment Sales

2,361

2,454

297

298

2,658

2,752

10,370

9,252

5,627

7,705

15,997

16,957

Royalties

(983)

(906)

-

-

(983)

(906)

Revenues

9,387

8,346

5,627

7,705

15,014

16,051

Expenses

Purchased Product

1,244

1,167

4,378

7,082

5,622

8,249

Transportation and Blending

3,375

3,247

-

-

3,375

3,247

Operating

1,047

893

526

854

1,573

1,747

Realized (Gain) Loss on Risk Management

13

(9)

(11)

6

2

(3)

Operating Margin

3,708

3,048

734

(237)

4,442

2,811

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

Operating Margin by Asset

Three Months Ended March 31, 2026

($ millions)

Atlantic

Asia Pacific

Offshore (1)

Gross Sales

252

297

549

Royalties

(2)

(23)

(25)

Revenues

Expenses

250

274

524

Purchased Product

4

-

4

Transportation and Blending

7

-

7

Operating

82

29

111

Operating Margin

157

245

402

Three Months Ended March 31, 2025

($ millions)

Atlantic

Asia Pacific

Offshore (1)

Gross Sales

146

305

451

Royalties

(2)

(23)

(25)

Revenues

Expenses

144

282

426

Purchased Product

-

-

-

Transportation and Blending

6

-

6

Operating

64

25

89

Operating Margin

74

257

331

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

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

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

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

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

Three Months Ended March 31,

($ millions)

2026

2025

Cash From (Used in) Operating Activities

2,181

1,315

(Add) Deduct:

Settlement of Decommissioning Liabilities

(53)

(36)

Net Change in Non-Cash Working Capital

(1,143)

(861)

Adjusted Funds Flow

3,377

2,212

Capital Investment

1,170

1,229

Free Funds Flow

2,207

983

Add (Deduct):

Base Dividends Paid on Common Shares

(377)

(327)

Dividends Paid on Preferred Shares

(2)

(6)

Purchase of Common Shares Under Employee Benefit Plan

(51)

(58)

Settlement of Decommissioning Liabilities

(53)

(36)

Principal Repayment of Leases

(90)

(83)

Acquisitions, Net of Cash Acquired

(10)

(100)

Proceeds From Divestitures

99

-

Excess Free Funds Flow

1,723

373

Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture

Gross Margin and Adjusted Gross Margin are non-GAAP financial measures that are used to evaluate the performance of our downstream operations. We define Gross Margin as revenues less purchased product and Adjusted Gross Margin as revenues less purchased product, excluding the impact of inventory holding gains or losses.

Inventory holding gains or losses reflects the difference between the cost of volumes produced at current-period costs, which is an indication of current market conditions, and the cost of volumes produced under the FIFO or weighted average cost basis as required by IFRS Accounting Standards, which generally reflects the market conditions at the time feedstock was purchased. The purchase and sale of inventories creates a timing difference that could be anywhere from several weeks to several months. This measure is an estimate of the impact of current-period costs to FIFO or weighted average cost, and assumes that all opening volumes are sold in the current period. Cenovus uses inventory holding gains or losses to analyze the performance of our assets and increase comparability with refining peers.

Adjusted Refining Margin and Adjusted Market Capture contain non-GAAP financial measures. Adjusted Refining Margin is used to evaluate our downstream operations after adjusting for inventory holding gains or losses. Adjusted Market Capture is used in our U.S. Refining segment to provide an indication of margin captured relative to what was available in the market based on widely-used benchmarks. These measures are useful to consistently measure the performance of our downstream operations.

We define Adjusted Refining Margin as Adjusted Gross Margin divided by total processed inputs and Adjusted Market Capture as Adjusted Refining Margin divided by the weighted average 3-2-1 market benchmark crack, net of RINs, expressed as a percentage. The weighted average crack spread, net of RINs, is calculated on Cenovus's operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.

Canadian Refining

($ millions, except where indicated)

Three Months Ended March 31, 2026 Lloydminster Upgrader and Lloydminster Refinery Total Other (1) Total Canadian Refining (2)

Revenues

1,327

80

1,407

Purchased Product

1,008

52

1,060

Gross Margin

319

28

347

Add (Deduct):

Inventory Holding (Gain) Loss

(47)

-

(47)

Adjusted Gross Margin

272

28

300

Total Processed Inputs (Mbbls/d)

124.5

Adjusted Refining Margin ($/bbl)

24.27

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

  2. Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

Three Months Ended March 31, 2025

($ millions, except where indicated)

Lloydminster Upgrader and Lloydminster Refinery

Total

Other (1)

Total Canadian Refining (2)

Revenues

1,221

61

1,282

Purchased Product

1,037

39

1,076

Gross Margin

184

22

206

Add (Deduct):

Inventory Holding (Gain) Loss

3

-

3

Adjusted Gross Margin

187

22

209

Total Processed Inputs (Mbbls/d)

119.5

Adjusted Refining Margin ($/bbl)

17.33

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

  2. Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.

U.S. Refining

Three Months Ended March 31,

($ millions, except where indicated) 2026 2025

Revenues (1)

Purchased Product (1)

Gross Margin

Add (Deduct):

Inventory Holding (Gain) Loss

Adjusted Gross Margin

Total Processed Inputs (Mbbls/d) Adjusted Refining Margin ($/bbl) Operable Capacity (Mbbls/d)

Operable Capacity by Regional Benchmark (percent) Chicago 3-2-1 Crack Spread Weighting

Group 3 3-2-1 Crack Spread Weighting

Benchmark Prices and Exchange Rate Chicago 3-2-1 Crack Spread (US$/bbl) Group 3 3-2-1 Crack Spread (US$/bbl) RINs (US$/bbl)

US$ per C$1 - Average

Weighted Average Crack Spread, Net of RINs ($/bbl)

Adjusted Market Capture (percent)

4,220

6,423

3,318

6,006

902

417

(457)

23

445

440

359.9

581.0

13.74

8.41

364.8

612.3

88

81

12

19

17.55

13.68

17.16

16.48

8.71

4.76

0.729

0.697

12.06

13.58

114

62

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

Netback Reconciliations and Realized Sales Price

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. Our Netback calculation is substantially aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netback is defined as gross sales less royalties, transportation and blending, and operating expenses. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold and exclude risk management activities. Condensate or butane (diluent) is blended with crude oil to transport it to market. Netback per barrel of oil equivalent contains a non-GAAP measure. Netbacks per barrel of oil equivalent reflect our margin on a per-barrel of oil equivalent basis. Per-unit measures are divided by sales volumes.

Netback calculations reflect our proportionate share of revenues and expenses for joint ventures that are accounted for using the equity method of accounting. Offshore and Asia Pacific Netbacks include HCML, and the Conventional Netback includes Duvernay, resulting in non-GAAP measures when line items are presented independently and containing non-GAAP measures when presented on a per-unit basis.

Realized Sales Price contains a non-GAAP measure. It includes our gross sales, purchased diluent costs and profit from optimization activities, such as cogeneration, third-party processing and trading.

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

Oil Sands

Basis of Netback Calculation

Three Months Ended March 31, 2026 ($ millions)

Foster Creek

Christina Lake

Sunrise

Lloydminster (1)

Total Oil Sands (2)

Gross Sales

1,756

2,440

434

864

5,494

Royalties

(333)

(519)

(11)

(71)

(934)

Revenues

1,423

1,921

423

793

4,560

Expenses

Purchased Product

-

-

-

-

-

Transportation and Blending

251

253

72

34

610

Operating

210

290

94

226

820

Netback

962

1,378

257

533

3,130

Realized (Gain) Loss on Risk Management

23

Operating Margin

3,107

Basis of Netback

Calculation

Adjustments

Three Months Ended March 31, 2026 ($ millions)

Total Oil Sands (2)

Condensate

Third-party Sourced

Other (3)

Total Oil Sands (4)

5,494

2,629

547

114

8,784

(934)

-

-

(6)

(940)

4,560

2,629

547

108

7,844

-

-

547

70

617

610

2,629

-

44

3,283

820

-

-

6

826

3,130

-

-

(12)

3,118

23

-

-

-

23

3,107

-

-

(12)

3,095

Gross Sales Royalties

Revenues Expenses

Purchased Product Transportation and Blending Operating

Netback

Realized (Gain) Loss on Risk Management

Operating Margin

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

  2. Includes bitumen and heavy oil.

  3. Other includes reclassification of costs primarily related to third-party cogeneration and transportation and blending.

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

Basis of Netback Calculation

Three Months Ended March 31, 2025 ($ millions)

Foster Creek

Christina Lake

Sunrise

Lloydminster (1)

Total Oil Sands (2)

Gross Sales

1,717

1,619

389

910

4,635

Royalties

(342)

(398)

(20)

(99)

(859)

Revenues

Expenses

1,375

1,221

369

811

3,776

Purchased Product

-

-

-

-

-

Transportation and Blending

312

132

80

39

563

Operating

193

189

78

213

673

Netback

870

900

211

559

2,540

Realized (Gain) Loss on Risk Management

(8)

Operating Margin 2,548

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

  2. Includes bitumen and heavy oil.

Three Months Ended March 31, 2025 ($ millions)

Basis of Netback

Calculation

Total Oil Sands (1)

Condensate

Adjustments

Third-party Sourced

Other (2)

Total Oil Sands (3)

Gross Sales

4,635

2,575

553

94

7,857

Royalties

(859)

-

-

(2)

(861)

Revenues

3,776

2,575

553

92

6,996

Expenses

Purchased Product

-

-

553

79

632

Transportation and Blending

563

2,575

-

13

3,151

Operating

673

-

-

4

677

Netback

2,540

-

-

(4)

2,536

Realized (Gain) Loss on Risk Management

(8)

-

-

-

(8)

Operating Margin

2,548

-

-

(4)

2,544

(1) Includes bitumen and heavy oil.

  1. Other includes construction, transportation and blending.

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

Conventional

Basis of Netback

Calculation Adjustments

Three Months Ended March 31, 2026 ($ millions) Conventional (1) Third-party Sourced Other (1) (2) Conventional (3)

374

(19)

623 40

- 1

623 41

623 -

- 39

- 6

- (4)

- -

- (4)

1,037

(18)

355

- 46

104

1,019

623

85

110

205

(10)

201

(10)

215

211

Gross Sales Royalties

Revenues Expenses

Purchased Product Transportation and Blending Operating

Netback

Realized (Gain) Loss on Risk Management

Operating Margin

  1. Includes revenues and expenses related to the Duvernay joint venture.

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

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

Basis of Netback

Calculation

Adjustments

Three Months Ended March 31, 2025 ($ millions)

Conventional (1)

Third-party Sourced

Other (1) (2)

Conventional (3)

Gross Sales

379

534

31

944

Royalties

(20)

-

-

(20)

Revenues

Expenses

359

534

31

924

Purchased Product

-

534

1

535

Transportation and Blending

61

-

29

90

Operating

122

-

5

127

Netback

176

-

(4)

172

Realized (Gain) Loss on Risk Management

(1)

-

-

(1)

Operating Margin

177

-

(4)

173

  1. Includes revenues and expenses related to the Duvernay joint venture.

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

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

Offshore

Basis of Netback Calculation Adjustments

Three Months Ended March 31, 2026 ($ millions) Atlantic China Indonesia (1)

Total Asia Pacific

Total Offshore

Equity

Adjustment (1) Other (2) Total Offshore (3)

Gross Sales

243

297

82

379

622

(82)

9

549

Royalties

(2)

(23)

(20)

(43)

(45)

20

-

(25)

Revenues

Expenses

241

274

62

336

577

(62)

9

524

Purchased Product

-

-

-

-

-

-

4

4

Transportation and Blending

7

-

-

-

7

-

-

7

Operating

82

28

13

41

123

(11)

(1)

111

295

447

- 447

(51)

- (51)

6

- 6

402

- 402

Netback 152 246 49

Realized (Gain) Loss on Risk Management

Operating Margin

  1. Revenues and expenses related to the HCML joint venture.

  2. Includes other activities not attributable to the production of crude oil and natural gas.

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

Basis of Netback Calculation Adjustments

Three Months Ended March 31, 2025 ($ millions)

Atlantic

China

Indonesia (1)

Total Asia Pacific

Total Offshore

Equity Adjustment (1)

Other (2)

Total Offshore (3)

Gross Sales

146

305

89

394

540

(89)

-

451

Royalties

(2)

(23)

(27)

(50)

(52)

27

-

(25)

Revenues

Expenses

144

282

62

344

488

(62)

-

426

Purchased Product

-

-

-

-

-

-

-

-

Transportation and Blending

6

-

-

-

6

-

-

6

Operating

64

23

15

38

102

(13)

-

89

Netback

Realized (Gain) Loss on Risk Management

74

259

47

306

380

-

(49)

-

-

-

331

-

Operating Margin

380

(49)

-

331

  1. Revenues and expenses related to the HCML joint venture.

  2. Includes other activities not attributable to the production of crude oil and natural gas.

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

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Cenovus Energy Inc. published this content on May 06, 2026, and is solely responsible for the information contained herein. Distributed via Public Technologies (PUBT), unedited and unaltered, on May 06, 2026 at 10:17 UTC.