Achieving our potential - Cenovus Energy

1 Achieving our potential11 About Cenovus British ColumbiaAlbertaSaskatchewanEdmontonCalga ryReginaFort St. JohnFort McMurraySaskatoonHorn RiverElmworth-WapitiKaybob-EdsonClearwat erNarrows LakeChristina LakeFoster CreekTelephone LakeNote: Values are approximate. 2018F production based on the midpoint of December 13, 2017 guidance. 1 2018F total natural gas includes production from the Deep basin and Cenovus s Athabasca natural gas asset. See advisory. TSX, NYSE | CVEE nterprise valueC$ 24 billionShares outstanding1,229 million2018F productionOil sands373 Mbbls/dDeep BasinOil & liquids32 Mbbls/dNatural gas540 MMcf/dTotal liquids405 Mbbls/dTotal natural gas1550 MMcf/dTotal production497 MBOE/d2017 proved + probable BBOER efining capacity230 Mbbls/d net2 Majority of 2018 capital sustains base production at Cenovus s oil sands operations Targeting < net debt to adjusted EBITDA Remaining capital: Christina Lake phase G expansion targeted drilling program in the Deep BasinDisciplined capital allocation drives shareholder valueSustain current assets and dividendReturn to shareholders: Increased dividend Share repurchasesHigh-return growth projects: Christina Lake phase GManage balance sheet to investment grade statusTargeting consistent growth in total shareholder returnsFocused on capital discipline23 Demonstrated track record of asset salesNote.

2 See non-core assetsTrack record on divestitures since 2010 Continuing to evaluate portfolio for non-core divestitures Deep basin non-core Clearwater assets currently being marketed, ~15,000 BOE/d01,0002,0003,0004,0005,0006,0007,00 08,0009,000 Historical asset sale proceeds($ millions)Executed ~$ billion in divestituresPelican LakePalliserWeyburnSuffield2010 - 20152017 2018 FAlbertaEdmontonCalgaryFort St. JohnElmworth-WapitiKaybob-EdsonClearwate r (15,000 BOE/d)Christina LakeFoster CreekBritish ColumbiaIdentified divestiture targetDeep BasinCenovus landsExecuted ~$ billion in divestitures4~$ billionLiquidity position supports resilienceNote: Liquidity positions as at December 31, 2017. See position Near-term debt reduction ~$ billion reduction in net debt position Targeting net debt to adjusted EBITDA < ~$5 billion liquidity position supports investment grade ratings Retired the $ billion asset-sale bridge facilityNet debt($ billions)Manageable long-term maturities Weighted average cost of debt ~ Expect to manage US$ billion 2019 debt maturity through refinancing activity and use of free funds flowPrincipal outstanding(US$ billions)$0$4$8$12$16Q2 2017Q3 2017YE 2017 Credit ratingsS&PMoody sDBRSF itchBBBBa2 BBBBBB-Negative outlookStable outlookNegative outlookStable outlook$ billion cash on hand$ billion available oncredit facility $ $ $ $ $ $1 billion of cumulative cost reductionsNote: General & administrative includes indirect costs.

3 See efficiencies Supply chain benefits driven by increased size and scale Re-designed well pads Longer-reach horizontal wells Multi-well pad development in Deep basin Technology deployment Christina Lake phase G cost reductionsOperating cost reductions Increased activity in the Deep basin Cogeneration Optimized maintenance scheduling Big data analytics Consistent field operations model Portfolio optimization effortsGeneral & administrative savings Leverage increased size and scale Optimizing workforce FCCL partnership costs Discretionary spending Digital driven efficiencies Subleasing strategy~$500 million~$125 million~$375 million6 Cost reductions improve sustainabilityNote: See sands sustaining capitalOil sands operating costsGeneral & administrative costs$ $ $ $ $ $ $/bbl > 50% reduction to G&A Improved efficiencies, workforce optimization, and reduced discretionary spending > 40% reduction to oil sands opex Non-fuel costs decreasing Natural gas prices and turnarounds fluctuateyear-to-year > 50% reduction in oil sands sustaining capital costs Savings are expected to be sustainable$ $ $ $ $ $ $/bbl$ $ $ $ $ $/BOE47 Sustainability drives free funds flowNote: Implied WTI breakeven required to cover sustaining capital and rates as per Peters & Co.

4 Limited. Free funds flow as per Peters & Co. as of February 12, 2018 strip pricing. Free funds flow yield is calculated as unhedged cash flow less Peters & Co. estimate of required capital spending to maintain flat production volume YoY, expressed as a percentage of market capitalization. Peers include: APA, CNQ, CPG, DVN, ECA, EOG, HSE, IMO, SU, TOU, VII. See corporate decline ratesImproved sustainabilityFree funds flow yield0%10%20%30%40%50%CVEI mplied WTI breakeven(US$/bbl)2018F corporate decline rate(percent)$30$40$50$60$70201420152016 20172018F~15% corporate decline rateLow WTI breakevenIncreasing free funds flow-6%-3%0%3%6%9%2019F free funds flow yield(percent)CVEI mprovement drives sustainable reductionsRedesigned well padsLower F&DTargeting $8 $10/bbl Improved modular & scalable design Scope reduction reduces costs Reduced well pad footprintImproved well design Quicker start-up Better conformance and faster recovery Fewer wells requiredImproved conformance Better conformance along the full horizontal well length Lower SOR Higher oil rates per wellLonger horizontal wells Capture a larger drainage area Fewer wells to recover the same resource Fewer surface facilities85 Superior start-up and steam circulation methods Advanced sub-surface equipment and design High pressure ramp up9201194D, or time-lapse seismic, can be acquired to determine changes in reservoir over an extended period.

5 Lower conformance (left) can be identified for opportunities to improve well productivity. Consistent and continuous conformance (right) is ideal for best well improvementsOld well design: ~75% conformanceNew well design: ~90-95% conformanceResults inNew design improves well conformance Better conformance along the full horizontal well length Lower SOR Higher oil rates per well pair90%5%10%15%20%25%30%03691215182124 Months on productionE20 PAD (2008)E15 PAD (2009)W02 PAD (2011)E08 PAD (2013)W08 PAD (2015)W07 PAD (2016)W10 PAD (2016)W05 PAD (2016)W18 PAD (2016)W23 PAD (2016)W15 PAD (2016)Improved start-up procedures on new padsImproved performanceFoster Creek well performance improvingRecovery factor Longer reach horizontal well pairs Drilling improvements Inflow/outflow control devices Improved start-up techniques Quicker start-up Better conformance and faster recovery Fewer Wedge Wells requiredTechnology driven field improvementsResults in10605001,0001,5002,0002,5003,0003,5001 316191 121 151 181 211 241 271 301 331 361 391 421 DayAverage 1,400m wellAverage 965m wellChristina Lake H09 pad 6 well pairs at 1,600mH-09 p Improved conformance allows us to drill longer wells and capture a larger drainage area fewer wells and surface facilities (~25% reduction) reduces environmental footprintLonger horizontal wells drive efficienciesWell results from 1,400m wellsbbls/d per well11 Improved conformance allows longer horizontal wellsNote.

6 Well results show average of two 1,400m wells compared to two 965m well pads drive cost improvementsImprovements provide sustainable reduction in F&DTransaction is fully financedRedesigned well pad at Christina Lake Improved modular and scalable design for well pairs and pads Materially reduces costs while maintaining safety, compliance, and production Scope reduction drives 35% 50% cost savings 40% 60% material reduction 15% 20% well pad surface footprint reduction Reduces engineering and construction time 30% reduction in field construction time 70% reduction in field executed scope 65% reduction in man hours12713 Foster Creek estimated capital savings of $500 millionAfter: 8 pads 66 wells ~$600 million 220 MMbbl recoverableBefore: 18 pads 120 wells ~$ billion 200 MMbbl recoverableImproved conformance, longer horizontal wells and redesigned well pads result in substantial cost savings14 Christina Lake estimated capital savings of $800 millionBefore: 19 pads 213 wells ~$ billion 310 MMbbl recoverableAfter: 13 pads 105 wells ~$800 million 310 MMbbl recoverableImproved conformance, longer horizontal wells and redesigned well pads result in substantial cost productionPortfolio-weighted SOR15 SOR reflects resource quality and executionNote: Production data and steam-oil ratio based on AER data as of December 2017.

7 Portfolio-weighted SOR calculated based on project operator and is a measure of current project efficiency. Peers include ATH, COP, CNQ, CNOOC, DVN, HSE, IMO, MEG, PGF and SU. Reinforcing our position as a leader in SAGDP roduction(Mbbls/d)Portfolio-weighted SORC enovusOur competitive advantage Low SOR means lower capital cost lower Energy usage lower operating cost smaller surface footprint lower emissions less water usage$ $ $ $ $ $ $ $ top quartile oil sands operating costsQ3 2017 oil sands operating costs per barrelOperating costs($/bbl)16 Source: Company reports. Peers include ATH, CNQ, HSE, MEG and SU. CVEC hristina LakeCVEF oster Creek90255075100125150175200225200220032 0042005200620072008200920102011201220132 0142015201620172018 FMbbls/d 17 Christina Lake overviewNote: Production is shown before royalties on a gross basis. 2018F production based on midpoint of December 13, 2017 Lake production historyKey facts and reservoir characteristicsSuccessfully executed 7 SAGD expansions and optimizationsCurrent productive capacity phases A-F (bbls/d)210,000 Regulatory approved capacity (bbls/d)310,000 Reservoir depth~375 metersNet pay~40 metersHigh permeability 5 10 darciesHigh oil saturation~80%API Cogeneration capacity (MW) production per well (bbls/d)1,1402P reserves (MMbbls)2,8202018F production (bbls/d)~207,000 Phase G builds on Christina Lake successNote: After-tax IRR based on go-forward spending and flat US$55/bbl WTI.

8 See Lake phase G project profile010203040506020172018F2019F2020F2 021F2022F25%40%30%5%00$0$100$200$300$400 $50020172018F2019F2020F2021F2022 FChristina Lake phase G capital profile($ millions)Christina Lake phase G production profile(Mbbls/d)Forecasted key statisticsUnitsStatisticProject oil capacity Mbbls/d50 Steam-oil spent to date$ millions$250 Capital remaining to completion $ millions$650 $700 Construction resumeddateH2 2017 First oil date from resuming constructionmonths24 30Go-forward capital efficiency$k/bbl/d$13 $14 After-tax IRR%> 30%Best-in-class oil sands project Industry-leading steam-oil ratio of Expected go-forward capital efficiency of $13,000 - $14,000/bbl/d (was $16,000 - $18,000/bbl/d) Construction is on track for first oil in H2 2019 50% reduction in capital efficiency from phase F1810 Current productive capacity phases A-G (bbls/d)180,000 Regulatory approved capacity (bbls/d)295,000 Reservoir depth~450 metersNet pay25 30 metersHigh permeability 5 10 darciesHigh oil saturation~80%API bitumen9 11 Cogeneration capacity (MW) production per well (bbls/d)5442P reserves (MMbbls)2,6602018F production (bbls/d)~166,000025507510012515017519981 9992000200120022003200420052006200720082 009201020112012201320142015201620172018 FMbbls/d 19 Foster Creek overviewNote: Production is shown before royalties on a gross basis.

9 2018F production based on the midpoint of December 13, 2017 D,EPhaseFPhaseGPhaseAPhaseBFoster Creek production historySuccessfully executed 7 SAGD expansions and optimizationsKey facts and reservoir characteristicsSolvents expected to create value and reduce emissions intensity Decreases SOR by ~30% - 35% Increases individual well production rates up to 10% Increases growth capital 15 - 20% Decreases sustaining capital by 10 - 30% Reduces non-fuel operating costs by up to 20% Solvents have the potential to achieve up to 80% of our targeted 33% GHG reductionCSAPP otential benefits of solventsSAGD201121 Deep basin provides second growth platformNote: Deep basin summary statistics excludes any potential divestitures. See of Deep basin One of the largest Deep basin land positions Three core operating areas: Elmworth-Wapiti, Kaybob-Edson, and Clearwater Low decline production base coupled with significant liquids-rich development upside Deep inventory of short-cycle, high IRR potential drilling opportunities in areas that attract capital from offsetting operators Assets were previously capital constrained BCF/d of net natural gas processing capacity; majority owned and operated Deep basin summary statistics 2018F production: 122,000 BOE/d(26% liquids.)

10 17% decline rate) Total net acres: ~ million Proved + probable + future drilling opportunities: ~ 1,500 2P reserves: 660 MMBOE (62% proved)Deep basin 2017-2018 development programInitial results in-line or better than anticipatedSand Creek Notikewin and Falher drilling performance2205001,0001,5002,0002,5003,0 003,5004,0004,5005,000024681012 DaysPeer 2 100/13-7-45-8W5 FLHRPeer 1 102/15-9-45-9W5 FLHRPeer 1 100/14-9-45-9W5 NTKNPeer 1 100/03-32-044-09W5 FLHRPeer 1 102/14-17-045-09W5 FLHRCVE 102/03-06-046-9W5 NTKNCVE 102/04-33-045-9W5 FLHRCVE 103/03-33-045-9W5 FLHRCVE 102/13-18-045-09W5 NTKND epth (mMD) Demonstrating high-quality resource and inventory across core areas Evaluating development plans to inform future infrastructure decisions 2017-2018 winter drilling showing strong initial results top decile initial production rates in Edson and Clearwater competitive drilling performance from a cold start based on limited activity since 2015 marked improvement from first wells in August 2017 to most recent wells in February 2018 Increasing completions intensity in several programs and continuing to drill longer lateral lengths where feasible Utilizing existing infrastructure to drive lower operating costs operating costs per BOE down 11% from Q3 20171223 Deep basin results exceeding expectationsElmworth / Wapiti 11 wells drilled and expected on-stream by end of Q1 2018 3 more wells to rig release in Q1 2018 Pipestone Montney Stacking / Spacing pilot and Lower Montney TestKaybob / Edson 14 wells drilled, 3 more wells left to rig release.