Corporate Presentation

Corporate presentation

Q4 2019 Cenovus at a glance

TSX, NYSE | CVE Enterprise value $24 billion

Telephone Lake 2020F production

Oil Sands 400 Mbbls/d Narrows Lake Elmworth-Wapiti Deep Basin 84 MBOE/d Christina Lake Marten Hills

Foster Creek 2019 proved & probable 6.9 BBOE Bruderheim reserves Kaybob-Edson

Reserve life index 42 years Clearwater

Refining capacity 248 Mbbls/d net

Note: Values are approximate. Enterprise value as at December 31, 2019. Forecasted production based on the midpoint of December 9, 2019 guidance. 2019 proved & probable reserves as at December 31, 2019. Reserve life index based on 2019 proved plus probable reserves and 2019 production before royalties, which was impacted by mandatory curtailment. Refining capacity represents net capacity to Cenovus.

More Canadian barrels are in the world’s best interest Opportunity for high ESG-ranked Canadian barrels to displace lower ESG-ranked barrels Aggregated ESG scores and reserves of selected oil producing nations Aggregated ESG score Bbbls 100 400

75 300

50 200

25 100

0 0

ESG score Total proved reserves at Dec 31, 2018

Note: * Complete aggregated ESG data unavailable for Iraq. Sources: ESG Scores – aggregation using an equal weighting (1/3) for each of 2018 Yale Environmental Performance Index, 2018 Social Progress Index and 2018 World Bank Governance Index. Reserves - BP Statistical Review of World Energy 2019 based on government and published data.

1 Global energy demand growth is an opportunity Responsibly developed oil can be part of a low carbon energy future World primary energy demand by fuel Million tonnes of oil equivalent 5,000

4,000

3,000

2,000

1,000

0 2000 2018 2000 2018 2000 2018 2000 2018 2000 2018 2000 2018 2000 2018 2000 2018 2030F 2040F 2030F 2040F 2030F 2040F 2030F 2040F 2030F 2040F 2030F 2040F 2030F 2040F 2030F 2040F

Oil Natural gas Coal Other Modern Nuclear Solid biomass Hydro renewables bioenergy

Source: IEA (2019), "World Energy Outlook 2019”, World primary energy demand by fuel – Stated Policies scenario.

Why Cenovus

Best-in-class Sustainability Financial & Capital assets Discipline

• Top tier SAGD assets • Safe and reliable operations • Strong balance sheet • Track record of execution • Responsible development • Returns-focused capital allocation • Extensive economic resource • Strong stakeholder relations • Modest pace of production growth inventory • Leading ESG performance • Resilient and free funds flow • Integrated portfolio enhances • Culture of innovation and through the cycle margins and reduces volatility continuous improvement

Sustainably growing shareholder returns

Note: See Commodity Price Assumptions. See Advisory. See Glossary.

2 Highlights of our strategy and 5-year plan

Disciplined capital & production Growing cash flow & earnings Increasing returns on capital

Capital investment Total production Adjusted funds flow & net earnings Return on capital employed ($ billions) (MBOE/d) ($ billions) (%)

$2.5 750 $6 10

~2-3% production CAGR $5 $2.0 600 8

$4 $1.5 450 6

$1.0 300 4 $2

$0.5 150 2 $1

$0.0 0 $0 0 2020F 2021F 2022F 2023F 2024F 2020F 2021F 2022F 2023F 2024F 2020F 2021F 2022F 2023F 2024F Capital investment Production (Mbbsl/d) Adjusted funds flow Net earnings

Generating nearly $11 billion cumulative free funds flow over the next 5 years

Note: All information reflects Base Case commodity prices assumptions. See Commodity Price Assumptions. See Advisory. See Glossary.

2020 budget reflects capital discipline

Capital expenditures 2019 Key assumptions 2020F ($ millions) Actuals • Disciplined capital investment in 2020 drives free funds flow to support further deleveraging and returns to shareholders Oil sands 705 - 820 621 Technology & exploration1 160 – 190 85 • Capital allocation remains consistent with Investor Day Deep Basin 80 – 95 53 • Capital expenditures of $1.3 to $1.5 billion Refining & marketing2 285 – 330 280 • >70% of budget allocated to maintaining safe and reliable operations and sustaining production in oil sands Corporate 90 – 100 137 Total capital expenditures 1,300 – 1,500 1,176 • Approximately $330 - $400 million of budget to advance key opportunities to sanction ready status Earliest 2020F capital Key opportunities sanction ready • supports engineering, regulatory and commercial work ($ millions) date to de-risk opportunities Foster Creek phase H 15 - 25 H2 2020 • potential investment in Marten Hills dependent on success of 2019 drilling program Christina Lake phase H 85 - 95 H2 2020 • sanctioning of Foster Creek phase H and Christina Lake Marten Hills 100 – 120 H1 2020 phase H dependent on improvement in market access Refinery high-return opportunities 115 – 135 Various and balance sheet strength Diluent Recovery Unit 15 - 25 H2 2020

Total 330 – 400

Note: 1 - Technology & exploration includes Marten Hills, and other emerging plays. 2 - Refining capital and operating costs are reported in C$, but incurred in US$ and as such will be impacted by FX. See Advisory.

3 2020 budget maintains competitive cost structure

Key assumptions Production volumes 2020F 2019 actuals • Crude by rail positions us to benefit from Special Production Foster Creek (Mbbls/d) 165 – 175 160 Allowances and move volumes on an unconstrained basis Christina Lake (Mbbls/d) 225 – 235 195 • total production increasing 8% Deep Basin (MBOE/d) 82 – 86 97 bringing on all curtailed production • Total production (MBOE/d) 472 – 496 452 • ramping up Christina Lake phase G Oil sands sustaining capital 2020F 2019 actuals • Deep Basin production declining Total oil sands sustaining ($ millions) $625 – $675 $567

• Oil sands sustaining capital increase largely due to the 1 deferral of sustaining capital in 2019 as a result of Total oil sands sustaining ($/bbl) $3.90 – $4.20 $3.99 mandatory curtailment in Alberta Operating costs 2020F 2019 actuals Per unit oil sands operating costs decreasing by 7% • Total oil sands ($/bbl) $6.85 – $8.10 $8.15

• Per unit Deep Basin operating costs increasing by 20% Total Deep Basin ($/BOE) $9.50 – $10.25 $8.79 primarily due to production declines 2 • Per unit G&A decreasing by 24% General & administrative 2020F 2019 actuals Total ($ millions) $280 – $300 $336 • Total G&A increasing slightly year-over-year for information technology and data initiatives, and Per unit ($/BOE) $1.58 – $1.69 $2.03 enhanced industry advocacy

Note: 1 - Oil sands per barrel sustaining capital costs are based on expected year-end nameplate capacity. 2 - Forecasted G&A includes stock based compensation. See Advisory.

Managing the balance sheet for the bottom of the cycle

Net and gross debt reduction Manageable long-term maturities

Principal outstanding $ billions (US$ billions)

$10 $1.5 Redemption of US$800 million $8 Repurchase of US$604 million $1.0 $6 Cash tender of US$748 million Repayment of $4 US$500 million $0.5

$0 $0.0 Q4 2017 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Future

Net debt (C$ billions) Total debt (US$ billions) 2019 2022 2023 2027 2037 2039 2042 2043 2047

• Targeting net debt to adjusted EBITDA < 2.0x at $45 WTI • Reduced total debt by US$2.7 billion or 35% since Q3 2018 • Net debt to adjusted EBITDA of 1.6x at Q4 2019 • Partial redemption of 2019 bond in Q4 2018 • Priority to reach $5 billion net debt supports investment grade ratings • Repurchased notes in 2018 and 2019 • Net debt of $6.5 billion and $4.4 billion liquidity position at Q4 2019 • Completed cash tender of bonds in June 2019 • Weighted average cost of debt ~4.9% at Q4 2019 • US$513 million repaid and repurchased in Q4 2019

Note: All references to WTI mean approximate West Texas Intermediate price in USD per barrel. See Advisory.

4 Sustainable reductions to cost structure

Industry leading oil sands operating costs and sustaining capital

$/bbl Oil sands operating costs and sustaining capital

15 40% reduction 70% reduction 12 in operating in sustaining costs capital

0 2014 2015 2016 2017 2018 2019 2020-2024F

Operating costs Sustaining capital Average

Note: 2018 and 2019 operating costs and sustaining costs impacted by voluntary and mandated production curtailments. See Advisory.

Capacity to generate free funds flow through the cycle

Low cost structure drives sustainability and free funds flow generation at $45 WTI

$ billions Projected free funds flow and capital $7

$75 WTI $5

$4 Base case $3

$2 $45 WTI

$0 2020F 2021F 2022F 2023F 2024F Sustaining capital Growth capital Free funds flow @ $45 WTI Free funds flow @ base case Free funds flow @ $75 WTI

Note: All references to WTI mean approximate West Texas Intermediate price in USD per barrel. See Advisory.

5 Disciplined capital allocation priorities

Net debt >$5 Billion <$5 Billion Capital Allocation Principles Safe & reliable operations 1. Maintain strong balance Sustaining capital sheet $1.0 - $1.2 billion 2. Maintain a low cost Fund base dividend structure

capital $0.25/share

Committed 3. Free funds flow Sustainable dividend growth 5 – 10% annually generation across all commodity prices Debt COP share COP share repurchase reduction repurchase 4. Investments anchored to Growth capital the bottom of the cycle NCIB NCIB FC H | CL H DRU | WRB 5. Predictable and capital consistent shareholder Growth capital Debt reduction Discretionary FC H | CL H | DRU | WRB returns

Note: See Glossary. See Advisory.

Returns focused capital allocation

Evaluation of opportunities across the portfolio includes share buybacks

Incremental opportunities for capital investment IRR (%) 100% $75 WTI $60 WTI

75% $45 WTI

50%

25%

0% Oil sands Marten Hills FC H CL H Christina Deep Basin DRU WRB capital Share sustaining Lake future projects repurchase expansions

Oil Sands & Exploration Deep Basin Midstream & Enterprise downstream Included in 5 year plan Excluded from 5 year plan

Note: IRRs represent P50 development cases using flat price assumptions of $45 WTI and $12.50 WTI-WCS differential, $60 WTI and $14.50 WTI-WCS differential, and $75 WTI and $18 WTI-WCS differential. All references to WTI mean approximate West Texas Intermediate price in US$/bbl. See Glossary. See Advisory.

6 Sustainably increasing shareholder returns

• Current free funds flow capability at $45 WTI supports Q4 dividend increase • Modest investment in the business positions us for sustainable dividend growth over the next five years and beyond • Opportunistic share repurchases complement our business plan and are attractive today • Disciplined timing of investment in modest growth allows for near-term focus on deleveraging, shareholder returns and market access

Dividend increase in Sustainable dividend Opportunistic Q4 2019 growth potential share repurchases 25% 5 – 10% Near-term focus on per year COP owned shares

Note: All references to WTI mean approximate West Texas Intermediate price in US$/bbl. See Advisory.

Sustainability focus areas

2030 TARGETS

Reduce emissions Achieve a Reclaim Achieve a fresh minimum of intensity by 30% 1,500 water intensity of maximum and hold absolute $1.5 billion decommissioned well emissions flat of additional sites 0.1 spending with barrel AMBITION Indigenous Complete $40 million per barrel of oil businesses of caribou habitat equivalent Reach net zero GHG restoration work emissions by 2050

Note: GHG emissions targets and ambition include scope 1 and 2 emissions (see Definitions) from operated facilities and use a 2019 baseline. Indigenous engagement target covers 2020 – 2030. Reclamation target covers 2020 – 2030; caribou habitat restoration program covers 2016 – 2030. Water stewardship target set for December 31, 2030. See Advisory.

7 Well positioned on GHG emissions Oil sands and Cenovus are competitive with global integrated companies

Large cap and integrated Canadian E&P Global integrated E&P 0.15 Emissions Intensity Oil Weighting

(tonnes CO2e/BOE) (%) 0.15 100%

0.12

e/BOE) Syncrude 0.12 80% 2

0.09 0.09 60%

Suncor ENI 0.06 40% CNRL Petronas 0.06 Husky Imperial Chevron BP Sinopec Conoco 0.03 20% Shell Repsol Exxon 0.03 Cenovus Emissions Intensity(tonnes CO Total Petrobras 0.00 0% CNOOC

2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 0.00 Syncrude CNQ SU HSE IMO CVE 0 20 40 60 80 100 120 140 160 180

Emissions Intensity Oil Weighting Emissions (MT CO2e)

Source: Peters & Co. Ltd. September 2019

Multiple levers to improve GHG emissions performance

Driving towards our 2050 net zero emissions ambition

GHG emissions intensity Net GHG emissions

kg CO2/BOE annual tonnes CO2e

~30% reduction by 2030

Net zero GHG emissions in 2050

2019F Technology Portfolio Offsets 2030F 2019F Growth Technology Portfolio Offsets 2050F

Note: 1 GHG emissions intensity reduction target includes scope 1 and scope 2 emissions from operated facilities; assumes credit granted for cogeneration and offsets. 2019 GHG emissions intensity impacted by mandatory production curtailment. See Advisory.

8 Best-in-class oil sands assets

Building on our core strength

• Modest pace of development maintains cost structure and aligns with market access • Free funds flow through the cycle supports sustainable growth in shareholder returns • Industry leading SOR and track record of responsible development

Leveraging our assets, operating expertise and cost structure

440 Mbbls/d 6.4 billion bbls Industry 200 MW installed productive 2P reserves leading SORS cogeneration capacity

Note: Values are approximate. Installed productive capacity includes Christina Lake phase G. 2P reserves as of December 31, 2019. Cogeneration output varies with temperature. See Advisory.

We are the leader in SAGD

Largest producer Lowest SOR Most experienced

Mbbls/d SOR Cumulative operating years

400 4.0 5,000

300 3.0 3,750

200 2.0 2,500

100 1.0 1,250

0 0.0 0 CVE CVE CVE

Note: Average daily production and portfolio-weighted steam oil ratio based on full year 2018. Cumulative operating years calculated as the sum of all operating well onstream durations. Peers include CNOOC, CNQ, COP, DVN, IMO, MEG, SU. See Glossary. See Advisory.

9 Advances in subsurface design and operating strategy Conformance refers to the consistency of steam across the reservoir, which drives bitumen recovery efficiency

Lower SOR New design and Higher oil production Better conformance Lower operating and operating strategy Lower supply cost sustaining costs

Old design and operating techniques New design and operating techniques

Steam injector well

Producer well

Note: See Glossary. See Advisory.

Operating strategy and execution delivers longer wells

Pacesetter in SAGD horizontal drilling

Average length (meters)

• No degradation in well CN Tower 553 performance Oil Sands Peer Average 878 • Fewer wells required to develop resource 2016 1,017

2017 1,027 • Reduced overall surface footprint 2018 1,184

• Lower sustaining costs 2019 1,440

CVE average well length by year

Note: See Advisory.

10 Innovation and experience generate results

Reductions anchored in operational improvements and design changes

Oil sands operating costs ($/bbl) Oil sands sustaining capital costs ($/bbl)

$13.50 $14.25

$8.15 $7 - $8

40% <$5 70% $4.00 reduction reduction

2014 2019 2020F - 2024F 2014 2019 2020F- 2024F Average Average

Note: 2019 operating costs and sustaining costs impacted by mandated production curtailments. 2020F – 2024F estimates are presented in accordance with IFRS 16. See Advisory.

Oil sands sustaining capital projects

Sustaining projects are some of the highest return projects in our portfolio • Consistent approach to sustaining production at Foster Creek and Christina Lake • Current and future programs implement step changes in design and operating strategies Average oil sands sustaining project Average well pairs per pad 9 - 12 Capital efficiency $5,000 – $7,000/bbl/d Finding & development cost $2 – $3/bbl Supply cost US$20 – $30/bbl After-tax IRR > 50%

Opportunity Alternatives Definition FID Execution Operation

Note: Supply cost calculated using a 9% discount. After-tax IRR represents P50 development case using flat price assumption of $60 WTI and $14.50 WTI-WCS differential. All references to WTI mean approximate West Texas Intermediate price in US$/bbl. See Glossary. See Advisory.

11 Foster Creek phase H opportunity to optimize asset Leveraging brownfield expansion opportunity Benefiting from phases F and G pre-build • Capital profile ($ millions) • Expected to be FID-ready in H2 2020, subject $300 to market access $200 • Potential first steam in 2023 $100 Foster Creek phase H $0 2019 '20 '21 '22 '23 '24 '25 '26 Estimated production ~40 Mbbls/d Production profile (Mbbls/d) Estimated remaining capital $600 – $650 million 75 Go-forward capital efficiency $15,000 – $16,000/bbl/d 50 Full-cycle capital efficiency $23,000 – $24,000/bbl/d 25 Supply cost < US$40/bbl WTI 0 After-tax IRR > 30% 2019 '20 '21 '22 '23 '24 '25 '26

Opportunity Alternatives Definition FID Execution Operation

Christina Lake phase H / Narrows Lake tieback opportunity Extending industry leading cost structure • Utilizing Christina Lake infrastructure to access ~1 billion barrels of Narrows Lake 2P reserves Capital profile ($ millions) $400 • Expected to be FID ready in H2 2020, subject $300 to market access $200 $100 • Potential first steam in 2025 $0 Christina Lake phase H & Narrows Lake tieback 2019 '20 '21 22 '23 '24 '25 '26

Estimated production ~65,000 bbl/d Production profile (Mbbls/d) Estimated remaining capital $1.2 - $1.3 billion 75 Go-forward $18,000 - $20,000/bbl/d 50

Full-cycle capital efficiency $29,000 – $31,000/bbl/d 25

Supply cost < US$30/bbl WTI 0 2019 '20 21 '22 '23 '24 '25 '26 After-tax IRR > 30%

Opportunity Alternatives Definition FID Execution Operation

Note: Full-cycle capital efficiency includes capital investment to date at Narrows Lake. Supply cost calculated using a 9% discount. After-tax IRR represents P50 development case using flat price assumption of $60 WTI and $14.50 WTI-WCS differential. All references to WTI mean approximate West Texas Intermediate price in US$/bbl. See Glossary. See Advisory.

12 Deep Basin overview

• Over 2.8 million net acres and 1.2 Bcf/d of net processing capacity • Low decline allows for moderated pace of development • Disciplined capital investment within cash flows at strip pricing • Drill to fill key facilities in core areas • Repositioning the business to operate at the bottom of the cycle • $45 WTI, $1.50/GJ AECO • Plan maximizes free funds flow in current price environment

Note: Values are approximate. Capacity of 1.2 BCF/d is net natural gas processing capacity in the Deep Basin. Note: All references to WTI mean approximate West Texas Intermediate price in US$/bbl. All references to AECO mean the AECO spot price for natural gas in $/Mcf. See Advisory.

Deep Basin has low decline, liquids rich production Focused on preserving value over production volumes

2020F production 2020F percent oil & liquids 2020F decline rate

MBOE/d % %

75% 45% 300

200 50% 30%

100 25% 15%

0 0% 0% TOU VII ARX CVE PEY PEY TOU ARX CVE VII CVE PEY ARX TOU VII

• Modest drilling program in 2020 • Oil & liquids content drive economics • 13% decline rate is a competitive advantage • Maintaining safe & reliable operations • 35-40% of liquids production is crude oil and • Reduces sustaining capital requirements • Drill to fill key facilities in core areas condensate

Source: Peters & Co. E&P Overview Tables report dated February 3, 2020. See Advisory.

13 Well positioned in the Marten Hills area

High margin resource in the Clearwater • Over 200 sections of prime oil sands leases • 15-25˚API gravity crude with up to 30m of pay • Primary production potential up to 25 Mbbls/d • WCS pricing without the need for condensate • Expecting high netbacks and strong risk adjusted returns • Assuming primary recovery factor <6% • Completed 17 well drilling program, results will inform next steps in development

Note: See Glossary. See Advisory.

Marten Hills development and exploration potential

Modest growth with a returns focus aligned with shareholder value proposition

Oil production Capital investment and operating margin (Mbbls/d) ($ Millions) 30 450

20 300

10 150

0 0 2019 2020F 2021F 2022F 2023F 2024F 2019 2020F 2021F 2022F 2023F 2024F Development capital investment Exploration capital investment Development production Exploration production Development operating margin Exploration operating margin

Opportunity Alternatives Definition FID Execution Operation

Note: See Advisory.

14 Refining and market access portfolio provides optionality

Portfolio of assets will change over time • Pipelines are the preferred mode of transportation • Rail bridges the gap until pipelines are constructed • Refining provides counter-cyclical cash flows during periods of congestion

>550 Mbbls/d of blended oil sands production Refining

~133 Mbbls/d 100 Mbbls/d ~320 Mbbls/d ~138 Mbbls/d ex-Alberta pipeline committed rail to sold in Alberta heavy crude refinery commitments tidewater Market capacity

Note: Values are approximate. See Advisory.

Improving margins through strategic integration

Reducing exposure to WCS in Alberta Refining capacity and ex-Alberta transportation commitments (Mbbls/d) • Marketing in excess of 550 Mbbls/d of blended heavy oil 800 up to 100% • Currently mitigating ~65% of our exposure to wide differentials 600 ~40% ~65% • Commitments on future expansion provide further insulation 400 • Other integration options to further increase exposure to USGC: 200 • support Enbridge Mainline conversion to contract carrier • add incremental rail agreements 0 YE 2017 2020F 2024+ • exploring potential for a Diluent Recovery Unit (DRU) Refining Pipelines Rail Other Alberta sales

Note: Refining refers to net heavy processing capacity at Wood River and Borger. Percentages represent portion of blended heavy oil production capacity covered by refining assets and ex- Alberta transportation commitments and other integration options. See Advisory.

15 Pipelines are the preferred mode of transportation

Current pipeline commitments provide diversification and flexibility • Increased commitments to USGC by 22,500 bbls/d in 2019 • Meaningful commitments on TMX and KXL pipeline projects Canada • Support Enbridge Mainline conversion Current ex-AB commitments

PADD II PADD III West Coast PADD II Express – Platte Enbridge USGC Trans Mountain pipelines pipelines Pipeline PADD IV PADD V PADD I 24,000 bbls/d 97,500 bbls/d 11,500 bbls/d

Future ex-AB commitments PADD III PADD II PADD III West Coast Enbridge Keystone Trans Mountain Mainline XL Pipeline Expansion

TBD 150,000 bbls/d 125,000 bbls/d

Note: See Advisory.

Rail bridges the gap until pipelines are built

Rail provides access to markets not directly connected by pipeline • Rail cost improvements through ratable operation and reduction in cycle times • Bruderheim asset provides strategic advantage, with capacity to grow Canada

Current committed capacity and shipping destinations

Bruderheim Hardisty PADD II ~65,000 ~35,000 PADD IV PADD I bbls/d bbls/d PADD V

US$17.50 – $20.00/bbl all-in delivered cost PADD III 17 – 20 days average cycle time from Alberta to USGC

Note: Values are approximate and transportation cost estimate is on a per unit of dilbit basis. See Advisory.

16 Rail program enables unconstrained production in 2020

Well positioned for crude by rail above curtailment Crude by rail volumes to • Fully ramped up crude by rail program in U.S. destinations (Mbbls/d) 2019, exceeding target in December 120

• Positioned for unconstrained production in 100 2020 through rail program and Alberta government’s SPA program 80

• Improvements in cycle times enables rail 60 capacity to exceed 100,000 bbls/d • Strategically optimizing the value of our 40 portfolio will determine crude by rail 20 volumes in 2020

0 Q4 Q1 Q2 Q3 Q4 2019 Future 2018 2019 2019 2019 2019 exit Total rail volumes loaded to U.S. destinations CVE rail sales at U.S. destinations Note: See Glossary. See Advisory.

Investigating the merit of a Diluent Recovery Unit

Neat bitumen netbacks could be competitive to pipelines

Illustrative DRU value drivers Illustrative DRU economics Realized price (US$/bbl) Feedstock (dilbit) 180,000 bbls/d Product (neatbit) 120,000 bbls/d Estimated capital $0.8 – $1.0 billion Estimated operating costs $1.50 – $2.50/bbl Potential neatbit price relative > dilbit to dilbit After-tax IRR Base case > 20%

Dilbit Incremental Opex & Condensate Required Neatbit Pipeline congested market > 40% via pipeline rail cost capital cost supply chain Neatbit via rail recovery reduction price uplift (no pipeline congestion)

Note: “Base case” price assumptions are US$60/bbl WTI and US$15/bbl WTI-WCS differential. “Pipeline congested market” price assumptions are US$60/bbl WTI and US$22/bbl WTI-WCS differential. See Advisory.

17 Refineries provide counter cyclical cash flow

Strategically located downstream assets provide heavy crude advantage Wood River Wood River Illustrative operating margin WTI-WCS differential (percent of total) (US$/bbl) • Crude capacity 346 Mbbls/d (67% heavy) 100% $30

• Nelson complexity factor 11.0 $25 80% • Accesses multiple pipelines – Keystone, Express-Platte, Mustang, Ozark $20 60% Borger refinery $15 Borger Crude capacity 149 Mbbls/d (23% heavy) 40% • $10

• Nelson complexity factor 11.6 20% $5 • Access to Canadian heavy, West Texas Sour and growing Permian supply 0% $0 Normalized market Congested market Generated more than $4 billion of operating margin conditions conditions in excess of capital investment since 2009 Downstream Upstream Differential

Note: See Glossary. See Advisory.

In situ technology development leader

• Continued improvement in capital and operating cost structure • Unlocking the potential of our vast resource base • Improving netbacks and driving free cash flow • Continued reduction in GHG emissions intensity

Cost structure Margin improvement GHG emissions

18 Moving towards a long-term vision of zero steam

Low concentration solvent pilot (SAP) High concentration solvent pilot • Solvent injection started in Q1 2018 ISOR • Propane concentration of 3-10wt% 6 • Instantaneous SOR has fallen >20%

High concentration solvent pilot (SDP) 4 • Solvent injection started in Q4 2017 • Propane concentration of 50-95wt%

• Instantaneous SOR has fallen >80% 2 • Potential for ~30% reduction of diluent ISOR~ 0.4-0.7 • Early stage of development 0 High temperature zero steam June 2017Propane June 2018 June 2019 injection • Future pilot being evaluated at Foster Creek started Current iSOR range iSOR SAGD baseline SOR

Note: See Glossary. See Advisory.

Supplemental

19 Demonstrated track record of ESG

2020 2012 2016 2016 Set sustainability Co-founder Initiated a voluntary 2018 2003 100 MW of targets 2050F 10-year Caribou Published carbon First 100 MW of cogeneration Net zero GHG Habitat Restoration disclosure report to cogeneration installed at emissions ambition Project align with TCFD installed at Foster Christina Lake 2019 Creek Member of

Examples of innovation and collaboration with academic institutions, entrepreneurs and peers

2016 2017 2019 2005 Co-founder Partnered with Established 2021F Christina Lake Butane 2030F 2015 with peers Demonstration solvent pilots began Reach 2030 Sponsor of solvents at sustainability Foster Creek targets

Note: See Advisory.

History of GHG emissions intensity reduction

Climate & GHG emissions 2018 direct oil sands GHG emissions

Oil sands GHG emissions intensity1 intensity 45 percent below oil sands (kg CO / BOE) 2 industry average 100 Technology and innovation reduces cost and 80 carbon intensity:

60 • Well design and operating strategy improvements 40 ~30% reduction • Well length optimization 20 since 2004 • Improved boiler efficiency 0 2004 2018 • Cogeneration Demonstrating leadership in GHG emissions intensity reduction

Source: Cenovus 2018 ESG Report. Note: 1 - Includes only emissions from exploration, drilling and development, production and extraction, separation and surface processing; does not include emissions from transport, upgrading, refining, or end-use combustion. See Advisory.

20 History of strong Indigenous relationships

Indigenous engagement Committed to strong relationships with Cumulative Indigenous business spending since 20091 Indigenous communities: ($ billions) • 9 long-term benefit agreements with $3 Indigenous communities • Scholarships to Indigenous students $2 • Support for non-profit organizations that address local community needs $1 • Investment in Indigenous communities near our operations with a multi-year $0 2014 2015 2016 2017 2018 housing initiative $2.8 billion spent with Indigenous businesses since 2009

Source: Cenovus 2018 ESG Report. Note: 1 - Includes goods and services provided by Indigenous-owned companies (51 percent or more ownership) and Indigenous joint ventures. See Advisory.

History of reducing impact to land & wildlife

Land & wildlife Managing critical habitat for species at risk: Cumulative well site reclamation certificates received since 20141 • Received over 1,600 reclamation 1,000 certificates since 2009 to return land back to how it looked before development projects began

500 • As part of the Caribou Habitat Restoration Project: • treatment of over 800 km of linear forest disturbances (seismic lines, 0 2014 2015 2016 2017 2018 access roads, etc.) • planted over 1 million trees in Track record of proactive abandonment operating areas since 2013 and reclamation

Source: Cenovus 2018 ESG Report. Note: 1 - Data prior to 2018 does not include Deep Basin assets. Reclamation certificate receipts increased in 2018 due to a large number of certificates received for our non-core assets in Saskatchewan. See Advisory.

21 History of minimal fresh water use

Water stewardship Fresh water use intensity1 Using water efficiently and responsibly: (bbls fresh water / BOE) • > 85% of water used to generate steam at 0.5 In situ average (AER) Company-wide Cenovus’s oil sands sites is recycled CVE oil sands 0.4 • remainder met through saline sources 0.3 • Technology development expected to

0.2 increase water use efficiency

0.1

0.0 2014 2015 2016 2017 2018

Efficient operations minimize fresh water use and lower costs

Source: Cenovus 2018 ESG Report. Note: 1 - Company-wide non-saline water use intensity has decreased in recent years mainly due to lower drilling activity and the divestment of our legacy conventional assets in 2017 and 2018. Oil sands non-saline water use intensity has increased in recent years due to phase expansion start-up and mandatory oil production curtailment in 2019. See Advisory.

Foster Creek overview

Foster Creek production history Key facts and reservoir characteristics

Current productive capacity phases A-G (bbls/d) 180,000 Mbbls/d 175 Regulatory approved capacity (bbls/d) 295,000 Phase G Reservoir depth ~450 meters 150 Phase F Net pay 25 – 30 meters 125 High permeability 5 – 10 darcies Phase 100 D,E High oil saturation ~80% Phase 75 C API bitumen 9° – 11° Phase 50 Cogeneration capacity (MW) 98 Phase B A CSOR 2.5 25 2019 average production per well (bbls/d) 560 0 2P reserves (Bbbls) ~2.7 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

2020F 2020F production (bbls/d) ~170,000

Successfully executed 7 SAGD expansions

22 Christina Lake overview

Christina Lake production history Key facts and reservoir characteristics

Current productive capacity phases A-G (bbls/d) 260,000 Mbbls/d Phase Regulatory approved capacity (bbls/d) 310,000 225 G Reservoir depth ~375 meters 200 Phase Optimization F Net pay ~40 meters 175 CDE 150 High permeability 5 – 10 darcies Phase 125 E High oil saturation ~80%

100 Phase API bitumen 7.5° – 9.5° D 75 Cogeneration capacity (MW) 100 Phase 50 Phase C CSOR 1.9 Phase B 25 A 2019 average production per well (bbls/d) 720 0 2P reserves (Bbbls) ~2.7 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

2020F 2020F production (bbls/d) ~230,000

Successfully executed 8 SAGD expansions and optimizations

Note: Production is shown before royalties on a gross basis. CSOR and average production per well were impacted by mandated production curtailments in 2019. 2020F production based on the midpoint of December 9, 2019 guidance. Phase G achieved first steam in January 2019 but full utilization of incremental production capacity was impacted by mandatory curtailment and is expected to ramp up through 2020. CSOR and 2P reserves as of December 31, 2019. See Advisory.

Deep Basin targeted development opportunity

Generating free cash flow from focused investments

Deep Basin 5-year forecast Future • Reduced capital investment given $ Millions potential Production (MBOE/d) challenging price environment $400 110 • Low base decline ~13% • Drill to fill key facilities in core areas $300 100

• Managing business to run at the $200 90 bottom of the cycle • 2020 – 2024 plan is returns focused $100 80

• Over $500 million of operating margin $0 70 in excess of capital through 2024 2020F 2021F 2022F 2023F 2024F Capital investment Operating margin Total production

Opportunity Alternatives Definition FID Execution Operation

Note: See Advisory.

23 Refining operating margin sensitivities

2020F refining operating margin, net, LIFO basis (US$ million)

WCS Operating margin sensitivity differential $1,250 Benchmark Sensitivity US$25/bbl $1,000 US$1 change in crack spread ~US$70 million US$20/bbl US$1 change in WCS differential ~US$35 million $750 US$15/bbl US$1 change in WTS differential ~US$20 million

$500 US$10/bbl US$1 change in WTI ~US$8 million

$250 US$0.10 cpg change in RINs ~US$25 million

-$250

-$500 $10 $12 $14 $16 $18 $20 Chicago crack spread - US$/bbl

Note: Operating margin sensitivities calculated on a full year basis using pricing as per December 9, 2019 guidance document and assumes no unplanned downtime or external disruptions. RINs assumed at US$0.40 cpg.

5 year plan price assumptions – base case

US$/bbl unless otherwise stated 2019F 2020F 2021F 2022F 2023F 2024F

Brent 64.02 60.00 62.00 65.00 65.00 65.00

WTI 57.19 55.00 57.00 60.00 60.00 60.00

WTI-WCS differential 12.08 15.00 15.00 15.00 15.00 15.00

WCS 45.11 40.00 42.00 45.00 45.00 45.00

WCS (C$/bbl) 59.93 53.33 56.00 60.00 60.00 60.00

AECO (C$/Mcf) 1.60 1.75 1.75 1.75 2.00 2.00

Chicago 3-2-1 crack spread 16.23 16.00 16.00 16.00 16.00 16.00

FX (US$/C$) 0.753 0.750 0.750 0.750 0.750 0.750

Note: 2019F reflects strip pricing at September 18. See Glossary. See Advisory.

24 5 year plan price assumptions – US$45/bbl WTI

US$/bbl unless otherwise stated 2019F 2020F 2021F 2022F 2023F 2024F

Brent 64.02 47.00 47.00 47.00 47.00 47.00

WTI 57.19 45.00 45.00 45.00 45.00 45.00

WTI-WCS differential 12.08 12.50 12.50 12.50 12.50 12.50

WCS 45.11 32.50 32.50 32.50 32.50 32.50

WCS (C$/bbl) 59.93 43.92 43.92 43.92 43.92 43.92

AECO (C$/Mcf) 1.60 1.62 1.62 1.62 1.62 1.62

Chicago 3-2-1 crack spread 16.23 12.00 12.00 12.00 12.00 12.00

FX (US$/C$) 0.753 0.740 0.740 0.740 0.740 0.740

Note: 2019F reflects strip pricing at September 18. See Glossary. See Advisory.

5 year plan price assumptions – US$75/bbl WTI

US$/bbl unless otherwise stated 2019F 2020F 2021F 2022F 2023F 2024F

Brent 64.02 81.00 81.00 81.00 81.00 81.00

WTI 57.19 75.00 75.00 75.00 75.00 75.00

WTI-WCS differential 12.08 18.00 18.00 18.00 18.00 18.00

WCS 45.11 57.00 57.00 57.00 57.00 57.00

WCS (C$/bbl) 59.93 69.51 69.51 69.51 69.51 69.51

AECO (C$/Mcf) 1.60 3.23 3.23 3.23 3.23 3.23

Chicago 3-2-1 crack spread 16.23 18.00 18.00 18.00 18.00 18.00

FX (US$/C$) 0.753 0.820 0.820 0.820 0.820 0.820

Note: 2019F reflects strip pricing at September 18. See Glossary. See Advisory.

25 Glossary of Terms

AFF adjusted funds flow API American Petroleum Institute CAGR compound annual growth rate CBR crude-by-rail CL Christina Lake CL H Christina Lake phase H CSOR cumulative steam-oil ratio – measures the average volume of steam (over the life of the operation) required to produce one barrel of bitumen ERA Emissions Reduction Alberta FC Foster Creek FC H Foster Creek phase H FFF free funds flow FID final investment decision GHG greenhouse gas IMO International Maritime Organization IRR internal rate of return ISOR instantaneous steam-oil ratio – measures the current or instantaneous volume of steam required to produce one barrel of bitumen NCIB normal course issuer bid NL Narrows Lake SAP solvent aided process – injection of low concentration (3-10wt%) of solvent SDP solvent driven process – injection of higher concentration (50-80wt%) of solvent SPA Special Production Allowance – program introduced by the Alberta government to allow crude by rail production above curtailment, effective December 1, 2019 WTI West Texas Intermediate

26 R1W5 R20W4 R15W4 R10W4 R5W4 R1W4

0 T

0 1

1 0

T 0

Birch

T T

9 5 Wabiskaw/ Grosmont McMurray Telephone Lake

Dover

0 Steepbank

T T

9 0

East McMurray Fort McMurray^

North T

BOREALIS REGION 8 5

& S a

South s k a a

House t t r c e h b e l w A a n

8 0 CHRISTINA LAKE REGION

Marten Leismer Hills Portage Hardy Narrows Lake Conklin 5 ^

7 T

7 5 West Kirby Winefred Lake Christina Lake Proper

T T

7 0 Foster Creek Proper

6 T

Fort 6 McMurray 5 ! FOSTER CREEK REGION Cenovus PNG Land Clearwater Deposit Edmonton Grosmont Deposit Wabiskaw/McMurray ! Deposit Cold Lake Calgary 0 10 20 30 40 50 ! Clearwater ^ 4

0 Kilometers 4 K 1

- 1:1,550,000 2

8 Cenovus oil sands land at February 7, 2020 7 1

0 -

6 E

V R1W5 R25W4 R20W4 R15W4 R10W4 R5W4 R1W4 R25W3 C 2020 Corporate Guidance - C$, before royalties December 9, 2019 UPSTREAM OIL SANDS Production Capital expenditures Operating costs Effective royalty Steam to oil (Mbbls/d) ($ millions) ($/bbl) rates (%) ratio Foster Creek 165 - 175 360 - 410 Fuel 1.75 - 2.25 15 - 20 2.6 - 3.0 Non-fuel 6.25 -7.00 Total 8.00 - 9.25 Christina Lake 225 - 235 310 - 360 Fuel 1.50 - 2.00 15 - 20 1.8 - 2.2 Non-fuel 4.50 -5.25 Total 6.00 - 7.25 Narrows Lake -- 35-50 ------Technology & Exploration (1) - - 160 - 190 ------Oil Sands total 390 - 410 865 - 1,010 DEEP BASIN Production (Mbbls/d) Light/Medium oil 3-5 Capital expenditures Operating costs Effective royalty NGLs 17 - 19 ($ millions) ($/bbl) rates (%)

(MMcf/d) 80 - 95 9.50 - 10.25 5 - 8 Natural gas 370 - 380 Deep Basin total 82 - 86 TOTAL Production Capital expenditures (Mbbls/d, MMcf/d, MBOE/d) ($ millions) Total liquids 410 - 433 Total natural gas 370 - 380 Total upstream 472 - 496 945 - 1,105 REFINING & MARKETING Capital expenditures Operating costs ($ millions) ($/bbl) Refining (2) 250 - 280 9.25 - 10.25 Marketing & transportation 35 - 50 CORPORATE

Corporate & other expenditures ($ millions) 90 - 100 Upstream DD&A ($ billions) 2.0 - 2.2 Total capital expenditures ($ billions) 1.3 - 1.5 Other DD&A ($ millions) (4) 350 - 450 General & administrative expenses ($ millions) (3) 280 - 300 Cash tax (recovery) ($ millions) 0 - 50 Effective tax rate (%) (5) 23 - 28 PRICE ASSUMPTIONS & ADJUSTED FUNDS FLOW SENSITIVITIES (6) Brent (US$/bbl) $60.00 Independent base case sensitivities Increase Decrease WTI (US$/bbl) $55.00 (for the full year 2020) ($ millions) ($ millions) Western Canada Select (US$/bbl)$37.50 Crude oil (WTI) - US$1.00 change 130 (130) Differential WTI-WCS (US$/bbl)$17.50 Light-heavy differential (WTI-WCS) - US$1.00 change (90) 90 AECO ($/Mcf)$1.80 Chicago 3-2-1 crack spread - US$1.00 change 100 (100) Chicago 3-2-1 Crack Spread (US$/bbl)$16.00 Natural gas (AECO) - C$1.00 change 40 (45) Exchange Rate (US$/C$)$0.76 Exchange rate (US$/C$) - $0.01 change (55) 55

(1) Technology & Exploration includes Marten Hills, and other emerging plays. (2) Refining capital and operating costs are reported in C$, but incurred in US$ and as such will be impacted by FX. (3) Forecasted G&A includes stock based compensation. (4) Includes DD&A related to Refining, Marketing and Corporate and Eliminations. (5) Statutory rates of 25% in Canada and 25% in the US are applied separately to pre-tax operating earnings streams for each country. Excludes the effect of divestiture and mark-to-market gains and losses. (6) Sensitivities include current hedge positions applicable for the full year of 2020. Refining results embedded in the sensitivities are based on unlagged margin changes and do not include the effect of changes in inventory valuation for first-in, first-out/lower of cost or net realizable value.

Oil and Gas Information

The estimates of reserves and resources data and related information were prepared effective December 31, 2018 by independent qualified reserves evaluators (“IQREs”), based on the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

Barrels of Oil Equivalent

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

Definitions and Industry Terminology

"Decline rate" is defined as the rate at which production declines year-over-year.

"IRR" is defined as the interest rate at which the net present value of all future cash flows from a well equal zero. IRR does not have any standard meaning prescribed by IFRS or the COGE Handbook and therefore may not be comparable with the calculation of similar measures for other entities. We believe that the presentation of IRR is relevant and useful to investors because it shows illustrative well-level economics in respect of wells that may be comparable to those we anticipate drilling in respect of the Deep Basin Assets.

"Scope 1 emissions" are direct emissions from owned or operated facilities. Cenovus accounts for emissions on a gross operatorship basis. This includes fuel combustion, venting, flaring and fugitive emissions. It does not include emissions from the 50% non-operated ownership in the company’s refineries or emissions from non-operated Deep Basin assets.

"Scope 2 emissions" are indirect emissions from the generation of purchased energy for the company’s operated facilities. For Cenovus, this is limited to electricity imports.

Presentation Basis

Cenovus presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated.

Cenovus adopted IFRS 16, “Leases” (“IFRS 16”), effective January 1, 2019, using the modified retrospective approach; therefore, comparative information has not been restated. Further information about changes to our accounting policies resulting from the adoption of IFRS 16 can be found in Note 4 to the December 31, 2019 Consolidated Financial Statements.

Non-GAAP Measures and Additional Subtotal

The following measures do not have a standardized meaning as prescribed by IFRS and therefore are considered non-GAAP measures. You should not consider these measures in isolation or as a substitute for analysis of our results as reported under IFRS. These measures are defined differently by different companies in our industry. These measures may not be comparable to similar measures presented by other issuers.

"Adjusted Funds Flow" is 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. Adjusted Funds Flow is defined as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale.

"Free Funds Flow" is defined as Adjusted Funds Flow less capital investment.

"Operating earnings (Loss)" is to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.

"Debt to capitalization", "net debt to capitalization", "debt to adjusted EBITDA" and "adjusted EBITDA" are ratios that management uses to steward the company’s overall debt position as measures of the company’s overall financial strength. "Debt" is defined as short-term borrowings and long-term debt, including the current portion. "Net debt" is defined as debt net of cash and cash equivalents. "Capitalization" is defined as debt plus shareholders’ equity. "Net debt to capitalization" is defined as net debt divided by net debt plus shareholders' equity. "Adjusted EBITDA" is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, goodwill and asset impairments, unrealized gains or losses on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income and loss, calculated on a trailing 12-month basis.

"Operating Margin" is an additional subtotal found in Notes 1 and 11 of the December 31, 2019 Consolidated Financial Statements 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. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes 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.

"Netback” is used in the oil and gas industry to assist in measuring operating performance on a per-unit basis, and is defined in the COGE Handbook. Netbacks reflect margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market.

Forward-looking Information

This presentation contains certain forward-looking statements and forward-looking information (collectively referred to as “forward- looking information”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward-looking information in this presentation is identified by words such as “ambition”, “capacity”, “commitment”, “committed”, “continue”, “could”, “delivers”, “drive”, “estimate", “expect”, “focus”, “forecast”, “go-forward”, “future”, “next steps”, “on track”, “opportunity”, “option”, “plan”, “position”, “potential”, “priority”, “shift”, “strategy”, “target”, “upside”, “vision”, “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: strategy and related milestones; schedules and plans, including expected timing for oil sands expansion phases and associated expected production capacities; sustainable growth in shareholder returns; including dividend growth of five to 10 percent annually; willingness to consider share repurchases; desire to realize the best margins for our products; plans to maintain and demonstrate financial discipline while balancing growth and shareholder return; continuing to advance our operational performance and upholding our trusted reputation; projections for 2020 and future years and our plans and strategies to realize such projections; forecast exchange rates and trends; future opportunities for oil and natural gas development; forecast operating and financial results, including forecast sales prices, costs and cash flows; our commitment to continue reducing debt, including our long-term target Net Debt to Adjusted EBITDA ratio; our ability to satisfy payment obligations as they become due; priorities for and approach to capital investment decisions or capital allocation; planned capital expenditures, including the amount, timing and financing thereof; all statements with respect to our 2020 guidance estimates; expected future production, including the accuracy, timing, stability or growth thereof; the impact of the Government of Alberta’s mandatory production curtailment; our ability to take steps to partially mitigate against wider WTI and WCS price differentials; expected reserves; capacities including for projects, transportation and refining; our ability to transport crude by rail in amounts above mandatory curtailment; all statements related to government royalty regimes applicable to Cenovus, which regimes are subject to change; our ability to preserve our financial resilience and various plans and strategies with respect thereto; forecast cost savings and sustainability thereof; our priorities; future impact of regulatory measures; forecast commodity prices, differentials and trends and expected impact; potential impacts of various risks, including those related to commodity prices and climate change; the potential effectiveness of our risk management strategies; opportunities to improve reservoir performance; potential for development of emerging assets; our ability to re-establish, maintain and strengthen investment grade credit ratings; availability and repayment of the existing credit facilities; expected impacts of the contingent payment; Cenovus’s 2030 climate change and GHG related targets and further ambitions, including our ability to lower GHG emissions on both an absolute basis and in terms of intensity in our operations and in respect of Cenovus's target of reducing GHG emissions intensity by 30% and holding absolute emissions flat by 2030, and its ambition of reaching net zero emissions by 2050 (which is inherently less certain due to the longer time frame and certain factors outside of our control as outlined in more detail below); Cenovus’s ability to achieve its targets and ambitions while maintaining a low cost structure, free funds flow growth, shareholder returns and balance sheet strength and its options and opportunities to achieve such targets and ambitions; Cenovus's plans with respect to continued Indigenous engagement, including its target to achieve a minimum of $1.5 billion of additional spending with Indigenous owned or operated businesses over the next 10 years and the expected benefits to neighbouring communities; a multi-year housing initiative investment in Indigenous communities near our operations; Cenovus’s plans with respect to land restoration, including its target to reclaim 1,500 decommissioned well sites over the next 10 years; references to Cenovus's 2030 ESG targets and further ambitions, including the areas of focus which Cenovus will take to achieve such targets and ambitions and the impacts of working towards such targets and ambitions; future use and development of technology and associated future outcomes; next steps and potential outcomes related to solvent commercialization; our ability to access and implement all technology necessary to efficiently and effectively operate our assets and achieve expected future results; and projected growth and projected shareholder return. Readers are cautioned not to place undue reliance on forward- looking information as our 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 Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but not limited to: forecast oil and natural gas prices and other assumptions inherent in Cenovus’s 2020 guidance, available at cenovus.com; bottom of the cycle commodity prices of about US$45/bbl WTI and C$44/bbl WCS; projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; the 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 our share price and market capitalization over the long term; future narrowing of crude oil differentials; lower production as a result of the Government of Alberta’s mandatory production curtailment; realization of expected impacts of the company's storage capacity within its oil sands reservoirs; the Government of Alberta’s mandatory production curtailment will continue to maintain a relatively narrow differential between WTI and WCS crude oil prices thereby positively impacting cash flows for Cenovus; the ability of Cenovus’s refining capacity, dynamic storage, existing pipeline commitments, financial hedge transactions and plans to ramp up crude-by-rail loading capacity to partially mitigate a portion of Cenovus’s WCS crude oil volumes against wider differentials; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgments; future use and development of technology and associated expected future results; Cenovus’s ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; Cenovus’s ability to generate sufficient cash flow to meet current and future obligations; including projected annual dividend growth of five to 10 percent; certain levels of future energy use and consumption of oil and gas; Cenovus’s carbon price outlook; the performance of assets and equipment; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the accuracy of third party data upon which we rely; opportunities to repurchase shares for cancellation at prices acceptable to us; Cenovus’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the availability of Indigenous owned or operated businesses; Cenovus’s ability to access sufficient capital to pursue development plans; forecast inflation and other assumptions inherent in Cenovus’s current guidance set out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the contingent payment to ConocoPhillips; Cenovus’s ability to access and implement all technology necessary to achieve expected future results; Cenovus’s ability to implement capital projects or stages thereof in a successful and timely manner; and other risks and uncertainties described from time to time in the filings Cenovus makes with securities regulatory authorities.

2020 guidance, issued on December 9, 2019, assumes: Brent prices of US$60.00/bbl, WTI prices of US$55.00/bbl; WCS prices of US$37.50/bbl; AECO natural gas prices of $1.80/Mcf; Chicago 3-2-1 crack spread of US$16.00/bbl; and an exchange rate of $0.76 US$/C$.

Unless otherwise specifically stated or the context dictates otherwise, the financial outlook and forward-looking metrics in this presentation, in addition to the generally applicable assumptions described above, do not include or account for the effects or impacts of asset sales.

In respect of our 2030 GHG targets, we have assumed: Cenovus's ability to successfully pursue NPV-positive capital investment opportunities and other operational measures, including the successful application to Cenovus's current and future operations of existing technology and new technology that is expected to be commercial in the near term; the successful implementation of our proposed or potential strategies and plans to reduce emissions; projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; and Cenovus's ability to otherwise access and implement all technology necessary to achieve our 2030 GHG targets, the development and performance of technology and technological innovations and the future use and development of technology and associated expected future results.

In respect of our 2050 net zero GHG ambition, we have assumed the same factors as in respect of our 2030 GHG targets applied over a longer term and will also rely on certain other factors and events coming to fruition, which are, to a large extent, outside of our control and thus less certain than those assumptions and factors that relate solely to our 2030 GHG targets, which includes continued development of commercially feasible carbon capture, utilization and storage (CCUS) technology and its future economic viability in Alberta; additional infrastructure to be built by industry or government sources to support CCUS and other technologies; and collaboration with partners to fund R&D into cost improvements and novel approaches to carbon capture.

The risk factors and uncertainties that could cause our actual results to differ materially, include, but not limited to: Cenovus’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; failure of the Government of Alberta’s mandatory production curtailment to cause the differential between the WTI and the WCS crude oil prices to narrow or to narrow sufficiently to positively impact cash flows; the effectiveness of Cenovus’s risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; accuracy of Cenovus’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in Cenovus’s marketing operations, including credit risks, exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; Cenovus’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; Cenovus’s ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; Cenovus’s ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to Cenovus or any of our securities; changes to Cenovus’s dividend plans or strategy; accuracy of our reserves, future production and future net revenue estimates, including production estimates associated with exploration opportunities currently in development, which opportunities are inherently riskier; resource quantities, current expectations and evaluations thereof and associated production and development plans, are subject to all of the risks associated with our business and cannot be guaranteed; accuracy of Cenovus’s accounting estimates and judgments; Cenovus’s ability to replace and expand oil and gas reserves; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of our assets or goodwill from time to time; Cenovus’s ability to maintain relationships with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, including labour, materials, natural gas and other energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and its application to Cenovus’s business; risks associated with climate change and our assumptions relating thereto; the timing and the costs of well and pipeline construction; Cenovus’s ability 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; availability of, and our ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost efficient manner; changes in labour relationships; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, 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; changes in general economic, market and business conditions; the political and economic conditions in the countries in which we operate or supply; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against Cenovus.

Additional risk factors and uncertainties that could be impediments to Cenovus meeting its 2030 climate and GHG emissions targets and further ambitions, include, but are not limited to: the effects of the implementation of cogeneration and potential increases in our steam-to-oil ratio on our overall emissions; Cenovus's ability to develop, access or implement some or all of the technology necessary to efficiently and effectively operate assets and achieve expected future results, including in respect of climate and GHG emissions targets and ambitions, the commercial viability and scalability of emission reduction strategies and related technology and products; the development and execution of implementing strategies to meet climate and GHG emissions targets and ambitions, including uncertainty over solvent supply and transportation, reservoir performance and capital spending estimates; uncertainty regarding the status of offsets, including due to cogeneration and renewable energy generation, recognition under future government policies and by ESG rating organizations and the measurability of offsets to count as emissions reductions; uncertainty in respect of CCUS regarding the eligibility of the credit generating pathways and the volatility of the price-signal in the credit market and the durability of the related policy through government changes. Additional risk factors and uncertainties that could be impediments in respect of Cenovus meeting its targets, ambitions, strategy and related milestones and schedules as they relate to our four ESG focus areas, include, but are not limited to: increasing stakeholder consideration of ESG factors and risks, including among credit rating agencies, lenders and investors, which may impact Cenovus's ability to access capital required to finance growth and sustaining capital expenditures; the inability to receive necessary regulatory approvals in a timely manner; reputational risk, including among stakeholders and government; maintenance of key relationships with government and other regulatory bodies; potential failure of products to achieve or maintain market acceptance; and risks associated with fossil fuel industry reputation and litigation related thereto.

In addition, there are risks that the effect of actions taken by us in implementing targets and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.

Statements relating to “reserves” are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future.

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 Cenovus's material risk factors, see “Risk Management and Risk Factors” in our Management's Discussion and Analysis for the period ended December 31, 2019, available on SEDAR at sedar.com, on EDGAR at sec.gov and on Cenovus's website at cenovus.com.

TM denotes a trademark of Cenovus Energy Inc.

Investor relations contacts

Sherry Wendt Director, Investor Relations [email protected] 403.766.5489

Mark Austin Senior Advisor, Investor Relations [email protected] 403.766.3926

Michelle Cheyne Senior Analyst, Investor Relations [email protected] 403.766.2584

Cenovus Energy Inc. 225 - 6 Ave SW PO Box 766 Calgary, Alberta T2P 0M5 Telephone: 403.766.2000 Toll free in Canada: 1.877.766.2066 Fax: 403.766.7600 cenovus.com