report to shareholders for the period ended september 30, 2021

ReporttoShareholdersfortheperiodendedSeptember30,2021(AllfinancialfiguresareexpressedinCanadiandollars($orC$)andallreferencestobarrelsareperbarrelofbitumen,unlessotherwisenoted)

MEGEnergyCorp.reportedthirdquarter2021operationalandfinancialresultsonNovember8,2021.

MEGcontinuestoproactivelyrespondtothesafetychallengesassociatedwiththeCOVID-19pandemicandremainscommittedtoensuringthehealthandsafetyofallofitspersonnelandthesafeandreliableoperationoftheChristinaLakefacility.

“The thirdquarterwas another strongoperational quarter forMEGasproduction levels benefited fromour team’scontinuedfocusonplantreliability,steamutilizationandongoingwelloptimization.”saidDerekEvans,PresidentandChief ExecutiveOfficer. “Givenwhatwe are seeing operationallywehave upwardly revised our annual productionguidanceandlookforwardtoastrongfinishto2021.”

Thirdquarterfinancialandoperatinghighlightsinclude:

• Adjusted funds flow of $239 million ($0.77 per share), impacted by a realized commodity price riskmanagementlossinthequarterof$66million($0.21pershare);

• Quarterlyproductionvolumesof91,506barrelsperday(bbls/d)atasteam-oilratio(SOR)of2.56.Basedonstrongoperationalperformance,annualaverageproductionguidancehasbeenupwardlyrevisedfrom91,000–93,000bbls/dto92,500–93,500bbls/d;

• Net operating costs of $7.17 per barrel, including non-energy operating costs of $4.46 per barrel. Powerrevenue offset energy operating costs by 43%, resulting in a net impact of $2.71 per barrel. Year to date,powerrevenuehasoffsetapproximately60%ofMEG’senergyoperatingcosts;

• Total capital investment of $84 million in the quarter with the majority directed towards sustaining andmaintenanceactivities,resultingin$155millionoffreecashflowinthequarter;and

• DuringthequarterMEGredeemedUS$100million(approximately$125million)ofMEG's6.5%seniorsecuredsecondliennotesdueJanuary2025.

BlendSalesPricing

MEGrealizedanaverageAWBblendsalespriceofUS$59.15perbarrelduringthethirdquarterof2021comparedtoUS$56.41perbarrelinthesecondquarterof2021.TheincreaseinaverageAWBblendsalespricequarteroverquarterwasprimarilyaresultoftheaverageWTIpriceincreasingbyUS$4.49perbarrel.MEGsold38%ofitssalesvolumesatthepremium-pricedU.S.GulfCoast(“USGC”) inthethirdquarterof2021comparedto45%inthesecondquarterof2021duetohigherapportionmentlevelsontheEnbridgemainlinesystemduringthethirdquarterof2021.

The reduction in sales volumes sold at the USGC quarter over quarter was consistent with the reduction intransportationandstoragecostswhichaveragedUS$5.75perbarrelofAWBblendsales inthethirdquarterof2021comparedtoUS$6.17perbarrelofAWBblendsalesinthesecondquarterof2021.

1

OperationalPerformance

Bitumenproductionaveraged91,506bbls/dinthethirdquarterof2021,consistentwithaveragebitumenproductionof91,803bbls/dinthesecondquarterof2021.

Non-energyoperatingcostsaveraged$4.46perbarrelofbitumensalesinthethirdquarterof2021comparedto$3.84perbarrelinthesecondquarterof2021primarilyduetoplannedmaintenanceactivities.Energyoperatingcosts,netofpower revenue, averaged$2.71perbarrel in the thirdquarterof2021 compared to$1.70perbarrel in the secondquarterof2021.This increasequarteroverquarter resulted fromstrongernaturalgaspricesand lowerpowersalesfromitscogenerationfacilities.Powerrevenueoffsetenergyoperatingcostsby43%duringthethirdquarterof2021compared to60%during thesecondquarterof2021.Year todate,power revenuehasoffsetapproximately60%ofMEG’senergyoperatingcosts.

General&administrativeexpense(“G&A”)wasrelativelyconsistentquarteroverquarterwith$14million,or$1.72perbarrelofproduction, in thethirdquarterof2021comparedto$13million,or$1.56perbarrelofproduction, in thesecondquarterof2021.

AdjustedFundsFlowandNetEarnings(Loss)

TheCorporation’scashoperatingnetbackaveraged$37.31perbarrelinthethirdquarterof2021comparedto$31.30perbarrelinthesecondquarterof2021.ThisincreaseincashoperatingnetbackwasprimarilydrivenbytheincreaseinaveragebitumenrealizationduetothehigherWTIprice,aswellasalowerrealizedcommoditypriceriskmanagementloss quarter over quarter. The increased cash operating netback was the main driver for the increase in theCorporation’sadjustedfundsflowfrom$166millioninthesecondquarterof2021to$239millioninthethirdquarterof2021.

TheCorporationrecognizednetearningsof$54millioninthethirdquarterof2021comparedtonetearningsof$68millioninthesecondquarterof2021.Thisdecreaseinnetearningswasprimarilytheresultofanunrealizedforeignexchangelossinthethirdquarterof2021comparedtoanunrealizedforeignexchangegaininthesecondquarterof2021.Thisdecreasewaspartiallyoffsetbyincreasedcashoperatingnetbackquarteroverquarterandbyanunrealizedgain on riskmanagement in the third quarter of 2021 compared to an unrealized loss on riskmanagement in thesecondquarterof2021.

CapitalExpenditures

MEGinvested$84millioninthethirdquarterof2021comparedto$70millioninthesecondquarterof2021.Capitalinvestedinthequarterwasdirectedtowardssustainingandmaintenanceactivitiesaswellasincrementalwellcapitalnecessary toallow theCorporation to fullyutilize theChristinaLakecentralplant facility'soilprocessingcapacityofapproximately 100,000 bbls/d, prior to any impact from scheduled maintenance activity or outages. As previouslydisclosed in the Corporation's second quarter 2021 release, the total investment for this optimization initiative isapproximately $125 million with $75 million included in the 2021 capital investment budget and the remainderexpectedtobeinvestedinthefirsthalfof2022.

COVID-19GlobalPandemic

MEGcontinuestoproactively respondtothesafetychallengesassociatedwithCOVID-19andremainscommittedtoensuringthatthehealthandsafetyofallitspersonnelandbusinesspartnersandthesafeandreliableoperationoftheChristinaLakefacilityremainatoppriority.MEGcontinuestoapplyscreeningprocedures,includingantigenscreeningandotherprotocols,ensuringthehealthandsafetyofitspeople.

DebtRepayment

Aspreviouslyannounced,duringthethirdquarterof2021theCorporationcontinuedtoprioritizedebtrepaymentwiththeredemptionofUS$100millionoftheCorporation's6.50%seniorsecuredsecondliennotesdueJanuary2025ataredemptionpriceof103.25%,plusaccruedandunpaidinterestto,butnotincluding,theredemptiondateofAugust23,2021.

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Since the beginning of 2018 the Corporation has repaid US$1.6 billion of outstanding indebtedness and remainscommitted to continueddebt reductionasa key componentof its capital allocation strategy.All available free cashflowgeneratedinthesecondhalfof2021willbedirectedtofurtherdebtrepayment.

Outlook

BasedonbetterthanexpectedproductionperformanceMEGisrevisingitsfullyear2021averageproductionto92,500–93,500bbls/d.

Summaryof2021GuidanceRevisedGuidance(November8,2021)

RevisedGuidance(July22,2021)

RevisedGuidance(May3,2021)

OriginalGuidance(December7,2020)

Bitumenproduction-annualaverage 92,500-93,500bbls/d 91,000-93,000bbls/d 88,000-90,000bbls/d 86,000-90,000bbls/d

Non-energyoperatingcosts $4.40-$4.50perbbl $4.40-$4.60perbbl $4.60-$5.00perbbl $4.60-$5.00perbbl

G&Aexpense $1.65-$1.75perbbl $1.65-$1.75perbbl $1.70-$1.80perbbl $1.70-$1.80perbbl

Capitalexpenditures $335million $335million $260million $260million

MEG'sestimateof fullyear2021total transportationcostsrangefromUS$6.00toUS$6.50perbarrelofAWBblendsales.

MEGplanstoreleaseits2022capitalandoperatingbudgetonoraboutNovember29,2021.

2021CommodityPriceRiskManagement

During the second half of 2020, MEG entered into enhanced WTI fixed price hedges with sold put options forapproximately30%offorecastbitumenproductionforthefourthquarterof2021atanaveragepriceofUS$46.18perbarrel. Additionally, MEG has hedged approximately 30% of its expected condensate requirements at a landed-at-Edmonton price equivalent to 98%ofWTI, approximately 30%of expected natural gas requirements at an averageAECOpriceofC$2.61perGJandfixedthesalespriceonapproximately30%ofexpectedpoweravailableforsaleatanaveragepriceofC$62.75perMWh,eachforthefourthquarterof2021.ThetablebelowreflectsMEG'soutstandingfourthquarterof2021hedgepositions.

MEGhasnotenteredintoanyWTIorWTI:WCSdifferentialhedgesfor2022.

ForecastPeriodQ42021

WTIHedgesEnhancedWTIFixedPriceHedgeswithSoldPutOptions(1)

Volume(bbls/d) 29,000

WeightedaveragefixedWTIprice(US$/bbl)/Putoptionstrikeprice(US$/bbl) $46.18/$38.79

CondensateHedges

Volume(2)(bbls/d) 14,028

Weightedaverage%ofWTIpricelandedinEdmonton(%)(3) 98%

NaturalGasHedges

Volume(4)(GJ/d) 42,500

WeightedaveragefixedAECOprice(C$/GJ) $ 2.61

PowerHedges

Quantity(5)(MW) 35

Weightedaveragefixedprice(C$/MWh) $ 62.75

(1) If in any month the averageWTI settlement price is US$38.79 per barrel (the sold put option) or better, MEG will receiveUS$46.18perbarrel (thefixedpriceswap)oneachbarrelhedged inthatmonth. If inanymonththeaverageWTIsettlement

3

priceislessthanUS$38.79perbarrel,MEGwillreceivethemonthaverageWTIsettlementpriceinthatmonthplusUS$7.39perbarrel(theswapspread)oneachbarrelhedgedinthatmonth.

(2) Includesapproximately3,000bbls/dofphysicalforwardcondensatepurchasesforthefourthquarterof2021atafixeddiscounttoWTI.

(3) Theaverage%ofWTIlandedinEdmontonincludesestimatednettransportationcoststoEdmonton.(4) Includes5,000GJ/dofphysicalforwardnaturalgaspurchasesforthefourthquarterof2021atafixedAECOprice.(5) Representsphysicalforwardpowersalesatafixedpowerprice.

ADVISORY

Forward-LookingInformation

This quarterly report contains forward-looking information and should be read in conjunction with the "Forward-LookingInformation"containedwithintheAdvisorysectionofthisquarter'sManagementDiscussionandAnalysisandPressRelease.

Non-GAAPMeasures

Certainfinancialmeasuresinthisreporttoshareholdersincludingfreecashflowandcashoperatingnetbackarenon-GAAPmeasures. These terms are not defined by IFRS and, therefore,may not be comparable to similarmeasuresprovided by other companies. These non-GAAP financial measures should not be considered in isolation or as analternativeformeasuresofperformancepreparedinaccordancewithIFRS.

FreeCashFlow

Free cash flow is presented to assistmanagement and investors in analyzing performance by the Corporation as ameasureoffinancial liquidityandthecapacityofthebusinesstorepaydebt.Freecashflowiscalculatedasadjustedfundsflowlesscapitalexpenditures.

ThreemonthsendedSeptember30

NinemonthsendedSeptember30

($millions) 2021 2020 2021 2020

Netcashprovidedby(usedin)operatingactivities $ 257 $ (31)$ 449 $ 186

Netchangeinnon-cashoperatingworkingcapitalitems (45) 50 44 (28)

Fundsflowfromoperations 212 19 493 158

Adjustments:

Settlementexpense(1) 21 — 21 —

Paymentsononerouscontracts 6 — 18 —

Contractcancellation — 7 — 33

Adjustedfundsflow $ 239 $ 26 $ 532 $ 191

Capitalexpenditures (84) (36) (224) (109)

Freecashflow $ 155 $ (10)$ 308 $ 82

(1) During the third quarter of 2021, the Corporation reached an agreement to settle the litigationmatter commenced in 2014relating to legacy issues involving a unit train transloading facility in Alberta. Under the agreement, the Corporation paid(subsequenttothequarter)thesumof$21millioninfullandfinalsettlementoftheclaimandtheclaimhasbeendiscontinued.

CashOperatingNetback

Cashoperatingnetbackisanon-GAAPmeasurewidelyusedintheoilandgasindustryasasupplementalmeasureofacompany’sefficiencyand its ability to fund future capital expenditures. TheCorporation’s cashoperatingnetback iscalculated by deducting the related cost of diluent, blend purchases, transportation and storage, third-partycurtailmentcredits,operatingexpenses,royaltiesandrealizedcommodityriskmanagementgainsorlossesfromblendsalesandpowerrevenue.Theperbarrelcalculationofcashoperatingnetbackisbasedonbitumensalesvolume.

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ThisManagement'sDiscussionandAnalysis("MD&A")ofthefinancialconditionandperformanceofMEGEnergyCorp.("MEG" or the "Corporation") for the three and nine months ended September 30, 2021 was approved by theCorporation'sAuditCommitteeonNovember8,2021.ThisMD&AshouldbereadinconjunctionwiththeCorporation'sunauditedinterimconsolidatedfinancialstatementsandnotestheretoforthethreeandninemonthsendedSeptember30, 2021, the audited annual consolidated financial statements and notes thereto for the year endedDecember 31,2020,the2020annualMD&AandtheCorporation'smostrecentlyfiledAnnual InformationForm(“AIF”).ThisMD&Aand the unaudited interim consolidated financial statements and comparative information have been prepared inaccordance with International Financial Reporting Standards (“IFRS”) as issued by the International AccountingStandardsBoard(“IASB”)andarepresentedinmillionsofCanadiandollars,exceptwhereotherwiseindicated.

Unlessotherwiseindicated,allperbarrelfiguresarebasedonbitumensalesvolumes.

MD&A-TableofContents

1. BUSINESSDESCRIPTION ................................................................................................................................. 6

2. OPERATIONALANDFINANCIALHIGHLIGHTS ................................................................................................. 6

3. SUSTAINABILITY ............................................................................................................................................. 7

4. NETEARNINGS(LOSS) .................................................................................................................................... 8

5. RESULTSOFOPERATIONS .............................................................................................................................. 8

6. OUTLOOK ....................................................................................................................................................... 19

7. BUSINESSENVIRONMENT .............................................................................................................................. 20

8. OTHEROPERATINGRESULTS ......................................................................................................................... 21

9. LIQUIDITYANDCAPITALRESOURCES ............................................................................................................ 27

10. RISKMANAGEMENT ....................................................................................................................................... 28

11. SHARESOUTSTANDING .................................................................................................................................. 30

12. CONTRACTUALOBLIGATIONS,COMMITMENTSANDCONTINGENCIES ........................................................ 31

13. NON-GAAPMEASURES .................................................................................................................................. 31

14. CRITICALACCOUNTINGPOLICIESANDESTIMATES ....................................................................................... 32

15. RISKFACTORS ................................................................................................................................................. 32

16. DISCLOSURECONTROLSANDPROCEDURES .................................................................................................. 32

17. INTERNALCONTROLSOVERFINANCIALREPORTING .................................................................................... 32

18. ABBREVIATIONS ............................................................................................................................................. 33

19. ADVISORY ....................................................................................................................................................... 33

20. ADDITIONALINFORMATION .......................................................................................................................... 35

21. QUARTERLYSUMMARIES ............................................................................................................................... 36

22. ANNUALSUMMARIES .................................................................................................................................... 38

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1. BUSINESSDESCRIPTION

MEG is anenergy company focusedon sustainable in situ thermal oil production in the southernAthabascaoilregionofAlberta,Canada.MEGisactivelydevelopinginnovativeenhancedoilrecoveryprojectsthatutilizesteam-assistedgravitydrainage("SAGD")extractionmethodstoimprovetheresponsibleeconomicrecoveryofoilaswellas lowercarbonemissions.MEGtransportsandsells thermaloil (knownasAccessWesternBlendor"AWB") tocustomersthroughoutNorthAmericaandinternationally.

MEGownsa100%workinginterestinover400squaremilesofmineralleases.IntheGLJPetroleumConsultantsLtd. ("GLJ") report,which is datedeffectiveDecember31, 2020,GLJ estimated that the leases it hadevaluatedcontainedapproximately2.0billionbarrelsofgrossprovedplusprobable("2P")bitumenreservesattheChristinaLakeProject.ForinformationregardingMEG'sestimatedreservescontainedinthereportpreparedbyGLJ,pleaserefer to the Corporation’s most recently filed AIF, which is available on the Corporation’s website atwww.megenergy.comandisalsoavailableontheSEDARwebsiteatwww.sedar.com.

2. OPERATIONALANDFINANCIALHIGHLIGHTS

Duringthethirdquarterof2021,aspreviouslyannounced,theCorporationcontinuedtoprioritizedebtrepaymentwith theAugust 23, 2021 redemptionofUS$100million of the Corporation's 6.50% senior secured second liennotes due January 2025 at a redemption price of 103.25%, plus accrued and unpaid interest. Since 2018 theCorporation has repaid US$1.6 billion of outstanding indebtedness and remains committed to continued debtreductionasakeycomponentofitscapitalallocationstrategy.

The Corporation generated adjusted funds flow of $239million in the third quarter of 2021 compared to $26millioninthethirdquarterof2020.Theincreaseisconsistentwiththemacroenvironmentwherethesignificantincrease in crudeoil priceswas supportedby global energydemand recovery. TheCorporation's realizedblendsales price averaged $74.54 per barrel in the third quarter of 2021 compared to $45.44 per barrel in the thirdquarterof2020resultingprimarilyfroma72%increaseintheWTIbenchmarkprice.ThiswaspartiallyoffsetbytheCorporation'slossesoncommoditypriceriskmanagementcontractswhichwereputinplaceinthesecondhalfof2020toprotecttheinternalfundingoftheCorporation's2021capitalprogram.

Productionvolumesaveraged91,506barrelsperdayinthethirdquarterof2021comparedto71,516barrelsperdayduringthethirdquarterof2020.Increasedsteamutilization,improvedfieldreliability,completedandongoingwelloptimizationandrecompletionworkallcontributedtostrongfield-wideproductionperformancetodate in2021. Average bitumen production in the third quarter of 2020 was impacted by major planned turnaroundactivitiesattheCorporation'sPhase1and2facilities.

TheCorporationinvested$84millioninthethirdquarterof2021comparedto$36millionduringthethirdquarterof2020.Themajorityofthe$84millioninvestedinthequarterwasdirectedtowardssustainingandmaintenanceactivitiesaswellas incrementalwellcapitalnecessarytoallowtheCorporationtofullyutilizetheChristinaLakecentralplantfacility'soilprocessingcapacityofapproximately100,000bbls/d,priortoanyimpactfromscheduledmaintenance activity or outages. As previously disclosed in the Corporation's second quarter 2021 release, thetotalinvestmentforthisoptimizationinitiativeisapproximately$125millionwith$75millionincludedinthe2021capitalinvestmentbudgetandtheremainderexpectedtobeinvestedinthefirsthalfof2022.

TheCorporationrecognizednetearningsof$54millioninthethirdquarterof2021comparedtoanetlossof$9millioninthethirdquarterof2020.Increasedearningsweremainlyduetostrongerglobalcrudeoilprices.

COVID-19Response

TheCorporationcontinuestoproactivelyrespondtothesafetychallengesassociatedwithCOVID-19andremainscommittedtoensuringthehealthandsafetyofall itspersonnelandbusinesspartnersandthesafeandreliableoperations at the Christina Lake facility. The Corporation continues to apply screening procedures, includingantigenscreeningandotherprotocols,toensurethehealthandsafetyofitspeople.

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http://www.megenergy.com

http://www.sedar.com

ThefollowingtablesummarizesselectedoperationalandfinancialinformationoftheCorporationfortheperiodsnoted.AlldollaramountsarestatedinCanadiandollars($orC$)unlessotherwisenotedandallperbarrelfiguresarebasedonbitumensalesvolumes:

Ninemonthsended

September30 2021 2020 2019

($millions,exceptasindicated) 2021 2020 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4

Bitumenproduction-bbls/d 91,386 79,557 91,506 91,803 90,842 91,030 71,516 75,687 91,557 94,566

Steam-oilratio 2.44 2.33 2.56 2.39 2.37 2.31 2.36 2.32 2.31 2.27

Bitumensales-bbls/d 89,861 78,354 92,251 89,980 87,298 95,731 67,569 70,397 97,214 94,347

Bitumenrealization-$/bbl 59.28 22.54 64.91 60.09 52.34 38.64 39.68 10.18 19.45 46.86

Netoperatingcosts-$/bbl(1) 6.00 5.85 7.17 5.54 5.25 6.98 6.05 6.14 5.51 5.87

Non-energyoperatingcosts-$/bbl 4.12 4.25 4.46 3.84 4.05 4.70 3.96 4.09 4.57 4.49

Cashoperatingnetback-$/bbl(2) 31.71 19.45 37.31 31.30 26.03 18.66 16.58 25.84 16.83 28.33

General&administrativeexpense$/bbl(3) 1.68 1.61 1.72 1.56 1.77 1.65 1.50 1.29 1.96 2.25

Adjustedfundsflow(4) 532 191 239 166 127 84 26 89 76 155

Pershare,diluted 1.71 0.62 0.77 0.53 0.41 0.27 0.09 0.29 0.25 0.51

Revenue 3,014 1,505 1,091 1,009 914 786 533 307 665 992

Netearnings(loss) 105 (373) 54 68 (17) 16 (9) (80) (284) 26

Pershare,diluted 0.34 (1.24) 0.17 0.22 (0.06) 0.05 (0.03) (0.26) (0.95) 0.09

Capitalexpenditures 224 109 84 70 70 40 36 20 54 72

Cashandcashequivalents 210 49 210 159 54 114 49 120 62 206

Long-termdebt-C$ 2,769 3,030 2,769 2,820 2,852 2,912 3,030 3,096 3,212 3,123

Long-termdebt-US$ 2,172 2,274 2,172 2,273 2,268 2,283 2,274 2,274 2,275 2,409

(1) Netoperatingcostsincludeenergyandnon-energyoperatingcosts,reducedbypowerrevenue.(2) Cash operating netback is a non-GAAP measure and does not have a standardized meaning prescribed by IFRS and

therefore maynot be comparable to similarmeasures usedby other companies. Refer to the “NON-GAAPMEASURES”sectionofthisMD&A.

(3) Generalandadministrativeexpense("G&A")perbarrelisbasedonbitumenproductionvolumes.(4) RefertoNote19oftheinterimconsolidatedfinancialstatementsforfurtherdetails.

3. SUSTAINABILITY

TheCorporation’sapproachtoenvironmental,socialandgovernance("ESG")mattersandsustainabilityreflectsitsunderstandingofthechallengesandopportunitiespresentedbyclimatechangeandtheenergytransitionanditscommitment to taking appropriate actions. The Corporation’s business strategy recognizes the importance andmomentumbehindthelowcarbonenergytransition,recognizestheincreasingdemandforresponsiblydevelopedlowcarbonenergyandaddressestherisksarisingoutofclimatechangeconcerns.Althoughthetimingandimpactof the energy transition is highly indeterminate, the Corporation is focused on enhancing its position as asustainablelow-costproducerandachievingnetzerocarbonemissions.

In2020,theCorporationsetalong-termgoalofreachingnetzeroScope1andScope2GHGemissionsby2050.Inthethirdquarterof2021,theCorporationadoptedamid-termtargetofreachinga30%reductioninbitumenGHGemissions intensity (Scope 1 and Scope 2) from2013 levels by 2030. In addition, the Corporation continued to

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advance its ESG activities and strategies with the development and implementation of an Indigenous PeoplesPolicy,includingIndigenousAwarenessTraining,aswellasanInclusionandDiversityPolicyandaWaterPolicy.

Alsoduringthethirdquarterof2021,theCorporationpublisheditssecondESGreportonAugust11,2021.

TheCorporation,alongwith fiveotheroil sandsoperators that collectively representabout95%ofCanada’soilsandsproduction,ispartoftheOilsandsPathwaystoNetZero("Pathways")Allianceworkingcollectivelywiththefederal and Alberta governments to achieve net zero GHG emissions from oil sands operations by 2050. ThePathwaysallianceproposestoreduceoilsandsproductionemissionsinthreephases:Phase1(2021-2030),Phase2 (2031-2040)andPhase3 (2041-2050). InPhase1, thePathways initiativewill focusonbuildingoutacarboncapturenetworkintheoilsandsproducingregionofnorthernAlberta.AkeyaspectofthisnetworkisaproposedcarbontransportationlinetogatherCO2frommorethan20oilsandsfacilitiesandmoveittoaproposedhubintheColdLakeareaofAlbertaforstorage.Thecarbontransportationlinewouldalsobeavailabletootherindustriesin the region interested in capturing and storing CO2. The Pathways alliance is currently developing detailedprojectplans forPhase1, including conducting feasibility studies for the transportation lineand storagehubaswellaspre-engineeringworkforcapturingcarbonatmultipleoilsandsfacilities.

ForfurtherdetailsontheCorporation’sapproachtoESGmatters,pleaserefertothe2020annualMD&AandmostrecentlyfiledAIFonwww.sedar.com.

4. NETEARNINGS(LOSS)

ThreemonthsendedSeptember30 NinemonthsendedSeptember30

($millions,exceptpershareamounts) 2021 2020 2021 2020

Netearnings(loss) $ 54 $ (9)$ 105 $ (373)

Pershare,diluted $ 0.17 $ (0.03)$ 0.34 $ (1.24)

TheCorporation recognizednet earningsof $54million and$105million for the three andninemonths endedSeptember30,2021,respectively,comparedtoanetlossof$9millionand$373millionduringthesameperiodsof2020,respectively.IncreasednetearningsduringthethreemonthsendedSeptember30,2021wasprimarilydueto stronger global crude oil prices and a reduction in hedged volumes, partially offset by an unrealized foreignexchangelossastheCanadiandollarweakenedrelativetotheU.S.dollarduringthequarter,asettlementexpenseandhigher depletion anddepreciation expensedue to increasedproduction. Increasednet earnings during theninemonthsendedSeptember30,2021wasprimarilyduetostrongerglobalcrudeoilpricespartiallyoffsetbyacommoditypriceriskmanagementlossasaresultofstrongerforwardcommodityprices.ThenetlossduringtheninemonthsendedSeptember30,2020wasimpactedbytherecognitionofa$366millionexplorationexpense.

5. RESULTSOFOPERATIONS

BitumenProductionandSteam-OilRatio


2021 2020 2021 2020

Bitumenproduction–bbls/d 91,506 71,516 91,386 79,557

Steam-oilratio(SOR) 2.56 2.36 2.44 2.33

BitumenProduction

Bitumenproduction increased28%during the threemonthsendedSeptember30,2021compared to the sameperiodof2020.TargetedmaintenanceactivitieswerecompletedduringthethreemonthsendedSeptember30,2021 with minimal impact to production. The Corporation was successful in shifting a large component ofpreviouslyplanned2021activitiesintothe75-daymajorplannedturnaroundin2020.Asaresultofthisshift,theCorporation saw reduced bitumen production during the threemonths ended September 30, 2020 due to themajor planned turnaround at the Phase 1 and 2 facilities, which began in June 2020 andwas completedmid-August2020.

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https://www.megenergy.com/sites/default/files/MEG%20Energy%20ESG%20Report%202021.pdf

www.sedar.com

Bitumen production increased 15% during the ninemonths ended September 30, 2021 compared to the sameperiodof 2020. Increased steamutilization, improved field reliability, completed andongoingwell optimizationandrecompletionworkallcontributedtostrongfield-wideproductionperformancetodatein2021.Thiscomparestoreducedbitumenproductionin2020duetothemajorplannedturnaroundatthePhase1and2facilities,whichbegan in June 2020 and was completed mid-August 2020, as well as voluntary price-related productioncurtailmentsinAprilandMay2020.

Steam-OilRatio

The Corporation uses SAGD technology to recover bitumen. In SAGD operations, steam is injected into the oilreservoirtomobilizebitumen,whichisthenpumpedtothesurface.AnimportantmetricforthermaloilprojectsisSteam-Oil Ratio ("SOR"), which is an efficiency indicator that measures the average amount of steam that isinjectedintothereservoirforeachbarrelofbitumenproduced.TheSORincreasedforthethreeandninemonthsendedSeptember30,2021,comparedtothesameperiodsof2020,duetothetimingofnewwellpairsandwellsbeingbroughtintosteamcirculationandproduction.

AdjustedFundsFlow

$millions

AdjustedFundsFlowVarianceThirdQuarter2020vs2021

$26

291

(77) (1)

$239

2020

Cashoperatingnetback,exclriskmgm

t

Realizedlossonriskmanagem

ent

Othercashco

sts

2021

0

50

100

150

200

250

300

350

$millions

AdjustedFundsFlowVarianceYear-to-Date2020vs2021

$191

915

(554) (20)

$5322020

Cashoperatingnetback,exclriskmgm

t

Realizedlossonriskmanagem

ent

Othercashco

sts

2021

200

400

600

800

1,000

1,200

During the three andninemonths ended September 30, 2021, adjusted funds flow increased compared to thesameperiodsof2020,drivenby theCorporation's increasedcashoperatingnetbackwhichwas impactedbyanincreaseinglobalcrudeoilpricespartiallyoffsetbyrealizedlossesoncommoditypriceriskmanagementcontracts.Thecommoditypriceriskmanagementcontractswereputinplaceinthesecondhalfof2020toprotectfundingoftheCorporation's2021capitalprogramwhichisexpectedtobefullyfundedwithinternallygeneratedcashflow.

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Thefollowingtablereconcilesnetcashprovidedbyoperatingactivitiestoadjustedfundsflow:



($millions) 2021 2020 2021 2020

Netcashprovidedby(usedin)operatingactivities $ 257 $ (31)$ 449 $ 186

Netchangeinnon-cashoperatingworkingcapitalitems (45) 50 44 (28)

Fundsflowfromoperations 212 19 493 158

Adjustments:

Settlementexpense(1) 21 — 21 —

Paymentsononerouscontracts 6 — 18 —

Contractcancellation — 7 — 33


(1) Duringthethirdquarterof2021,theCorporationreachedanagreementtosettlethelitigationmattercommencedin2014relatingtolegacyissuesinvolvingaunittraintransloadingfacilityinAlberta.Undertheagreement,theCorporationpaid(subsequent to the quarter) the sum of $21 million in full and final settlement of the claim and the claim has beendiscontinued.

NetcashprovidedbyoperatingactivitiesisanIFRSmeasureintheCorporation'sconsolidatedstatementofcashflow.Adjusted funds flow is calculatedasnet cashprovidedbyoperating activities excluding thenet change innon-cash operating working capital and items not considered part of ordinary continuing operating results.Adjusted funds flow isusedbymanagement toanalyze theCorporation'soperatingperformanceandcash flowgeneratingability.Byexcludingchanges innon-cashworkingcapitalandotheradjustmentsfromcashflows,theadjustedfundsflowmeasureprovidesameaningfulmetricformanagementbyestablishingaclear linkbetweentheCorporation'scashflowsandthecashoperatingnetback.

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CashOperatingNetback

The following table summarizes the Corporation's cash operating netback. Unless otherwise indicated, the perbarrelcalculationfortheperiodsindicatedbelowarebasedonbitumensalesvolume.


2021 2020 2021 2020

($millions,exceptasindicated) $/bbl $/bbl $/bbl $/bbl

Salesfromproduction $ 868 $ 385 $2,376 $1,035

Salesfrompurchasedproduct(1) 225 140 610 437

Petroleumrevenue 1,093 525 2,986 1,472

Purchasedproduct(1) (218) (134) (587) (416)

Blendsales(2) $ 875 $ 74.54 $ 391 $ 45.44 $2,399 $68.40 $1,056 $34.34

Costofdiluent (324) (9.63) (144) (5.76) (944) (9.12) (572) (11.80)

Bitumenrealization 551 64.91 247 39.68 1,455 59.28 484 22.54

Transportationandstorage(3) (85) (10.03) (115) (18.55) (264) (10.76) (267) (12.44)

Third-partycurtailmentcredits(4) — — — — — — 2 0.08

Royalties (23) (2.67) (2) (0.21) (44) (1.77) (8) (0.34)

NNetoperatingcosts (60) (7.17) (38) (6.05) (147) (6.00) (126) (5.85)

Cashoperatingnetback-excludingrealizedcommodityriskmanagement 383 45.04 92 14.87 1,000 40.75 85 3.99

Realizedgain(loss)oncommodityriskmanagement (66) (7.73) 11 1.71 (222) (9.04) 332 15.46

Cashoperatingnetback(5) $ 317 $ 37.31 $ 103 $ 16.58 $ 778 $31.71 $ 417 $19.45

Bitumensalesvolumes-bbls/d 92,251 67,569 89,861 78,354

(1) Salesandpurchasesofoilproductsrelatedtomarketingassetoptimizationactivities.(2) Blendsalesperbarrelarebasedonblendsalesvolumes.(3) Transportationand storage includes costsassociatedwithmovingand storingblendedbarrels tooptimize the timingof

delivery,netofthird-partyrecoveriesondiluenttransportationarrangements.(4) During 2020, the Corporation had the ability to purchase or sell production curtailment credits to either increase its

production,orsellexcessproductioncapacity,comparedtoitsprovincially-mandatedcurtailmentlevel.(5) Anon-GAAPmeasureasdefinedinthe“NON-GAAPMEASURES”sectionofthisMD&A.

Blend sales includes net revenue related to marketing asset optimization activities undertaken in the period.Marketing asset optimization is focused on the recovery of fixed costs related to transportation and storagecontractsduringperiodsofunderutilizationof theseassets,withthegoal tostrengthencashoperatingnetback.Marketingassetoptimizationactivitiesconsistofthepurchaseandsaleofthird-partyproducts.TheCorporationdoes not engage in speculative trading. The purchase and sale of third-party products to facilitate assetoptimization activities requires the elimination of price risk pursuant to policies approved by the Corporation'sBoard of Directors which can be achieved either through the counterparty or through financial price riskmanagement.

11

$millions

CashOperatingNetbackVarianceThirdQuarter2020vs2021

$103

342

142

(180)

(77)

30

(21)(22)

$317

2020

Blend

salespr

ice

Blend

salesvo

lumes

Costof

diluen

t

Realize

driskm

anagem

ent

Transp

ortatio

n&sto

rage

Royalti

es

Netop

erating

costs 202

1

100

200

300

400

500

600

$millions

CashOperatingNetbackVarianceYear-to-Date2020vs2021

$417

1,195

148

(372)

(554)

3

(36) (23)

$778

2020

Blend

salespr

ice

Blend

salesvo

lumes

Costof

diluen

t

Realize

driskm

anagem

ent

Transp

ortatio

n&sto

rage

Royalti

esOth

er202

1

400

600

800

1,000

1,200

1,400

1,600

1,800

BitumenRealization

BitumenrealizationrepresentstheCorporation'sblendsaleslessthecostofdiluent,expressedonaperbarrelofbitumensoldbasis.BlendsalesrepresentstheCorporation'srevenuefromitsoilblendknownasAWB,which iscomprised of bitumen produced at the Christina Lake Project blendedwith purchased diluent. Also included inblendsalesarenetprofitsfromthird-partypurchasesandsalesassociatedwithassetoptimizationactivities.Thecost of diluent is impacted by Canadian and U.S. benchmark pricing, the amount of diluent required which isimpactedby seasonalityandpipeline specifications, thecostof transportingdiluent to theproductionsite frombothEdmontonandU.S.GulfCoast ("USGC")markets, thetimingofdiluent inventorypurchasesandchanges inthevalueoftheCanadiandollarrelativetotheU.S.dollar.Thecostofdiluentpurchasedispartiallyoffsetbythesales of such diluent in blend volumes. Bitumen realization per barrel fluctuates primarily based on averagebenchmarkpricesandlight:heavyoildifferentials.


2021 2020 2021 2020


Salesfromproduction $ 868 $ 385 $ 2,376 $ 1,035

Salesfrompurchasedproduct(1) 225 140 610 437

Petroleumrevenue $ 1,093 $ 525 $ 2,986 $ 1,472

Purchasedproduct(1) (218) (134) (587) (416)

Blendsales(2) $ 875 $ 74.54 $ 391 $ 45.44 $ 2,399 $ 68.40 $ 1,056 $ 34.34

Costofdiluent (324) (9.63) (144) (5.76) (944) (9.12) (572) (11.80)

Bitumenrealization $ 551 $ 64.91 $ 247 $ 39.68 $ 1,455 $ 59.28 $ 484 $ 22.54

(1) Salesandpurchasesofoilproductsrelatedtomarketingassetoptimizationactivities.(2) Blendsalesperbarrelarebasedonblendsalesvolumes.

Blendsalesprice increasedby$29.10perbarreland$34.06perbarrelduringthethreeandninemonthsendedSeptember30,2021,respectively,comparedtothesameperiodsof2020.TheincreaseinblendsalespriceduringthethreeandninemonthsendedSeptember30,2021isprimarilyduetoahigherWTIprice.

12

DuringthethreemonthsendedSeptember30,2021,thecostofdiluentperbarrelincreased67%comparedtothesameperiodof2020primarilyduetowiderWTI:AWBdifferentials.Thecostofdiluentduring thethreemonthsended September 30, 2020 reflected narrowerWTI:AWBdifferentials and the use of lower priced diluent frominventoryresultinginahigherrecoveryofthecostofdiluentthroughblendsales.

DuringtheninemonthsendedSeptember30,2021,thecostofdiluentperbarreldecreased23%comparedtothesameperiodof2020.ThedecreasereflectsnarrowerWTI:AWBdifferentialsresulting inahigherrecoveryofthecost of diluent through blend sales. The cost of diluent during the nine months ended September 30, 2020reflected the use of higher priced diluent from inventory resulting in a lower recovery of the cost of diluentthroughblendsales.

Thetotalcostofdiluentwas$324millionand$944millionduringthethreeandninemonthsendedSeptember30,2021,respectively,comparedto$144millionand$572millionduringthesameperiodsof2020.ThistranslatestoacostperbarrelofdiluentduringthethreeandninemonthsendedSeptember30,2021of$99.69and$89.67,respectively,comparedto$60.48and$61.65forthesameperiodsof2020.Thecostperbarrelisimpactedbythebenchmarkcondensateprice,transportationcoststomovediluenttotheChristinaLakeproductionsiteandthetiming of use of inventory. The cost of diluent recognized is determined on aweighted-average cost basis anddiluentvolumesaretypicallyheldininventoryfor30to60days.Approximatelyhalfofthediluentissourcedfromeach of Edmonton andMont Belvieu, Texas. Refer to condensate priceswithin the "BUSINESS ENVIRONMENT"sectionofthisMD&Aforfurtherdetails.

TransportationandStorage

TheCorporation'smarketingstrategyfocusesonmaximizingitsrealizedAWBsalespriceaftertransportationandstoragecostsbyutilizingitsnetworkofpipelineandstoragefacilitiestooptimizemarketaccess.


2021 2020 2021 2020


Transportationandstorage $ (85)$ (10.03)$ (115)$ (18.55)$ (264)$ (10.76)$ (267)$ (12.44)

Bitumensalesvolumes-bbls/d 92,251 67,569 89,861 78,354

DuringthethreeandninemonthsendedSeptember30,2021, total transportationandstoragecostsdecreasedcompared to the sameperiods of 2020. Total transportation and storage costs during the threemonths endedSeptember30,2021werelowercomparedtothesameperiodof2020duetolowerblendsalesvolumessoldatthe USGC resulting from significantly increased apportionment levels on the Enbridge mainline system. Totaltransportation and storage costs during the nine months ended September 30, 2021 decreased due to theeliminationof rail transportation to theUSGC in2021partiallyoffsetbyhigherblend sales volumes soldat theUSGC,comparedtothesameperiodof2020.

Transportation and storage costs on a per barrel basis decreased during the three and nine months endedSeptember30,2021,comparedtothesameperiodof2020,concurrentwiththelowertotaltransportationcostsaswellastheimpactofspreadingthecostsoverhigherbitumensalesvolumes.

TheCorporationpartiallymitigatedthecostofunutilizedtransportationandstorageassetsthroughthepurchaseandsaleofnon-proprietaryproduct,orassetoptimizationactivities,added$7million,or$0.60perbarrel,toblendsalesduringthethreemonthsendedSeptember30,2021comparedto$6million,or$0.73perbarrel,duringthesameperiodof2020.Optimizationactivitiesadded$23million,or$0.64perbarrel,toblendsalesduringtheninemonthsendedSeptember30,2021comparedto$21million,or$0.68perbarrel,duringthesameperiodof2020.TheCorporationdoesnotengageinspeculativetrading.Thepurchaseandsaleofthird-partyproductstofacilitateasset optimization activities requires the elimination of price risk pursuant to policies approved by theCorporation'sBoardofDirectorswhichcanbeachievedeitherthroughthecounterpartyorthroughfinancialpricerisk management. To the extent that marketing asset capacity is underutilized, the Corporation has and willcontinuetolooktomitigatethesecoststhroughshortandmedium-termthird-partycontracts.

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Royalties

TheCorporation's royaltyexpense is calculatedbasedonprice-sensitive royalty rates setby theGovernmentofAlberta.TheroyaltyrateapplicabletotheCorporation'sChristinaLakeoperation,whichiscurrentlyinpre-payout,startsat1%ofbitumensalesandincreasesforeverydollarthattheWTIcrudeoilpriceinCanadiandollarsispricedabove $55 per barrel, to a maximum of 9% when the WTI crude oil price is $120 per barrel or higher. Theapplicableroyaltyrateisthenappliedtorevenueforroyaltypurposes.


2021 2020 2021 2020


Royalties $ (23)$ (2.67)$ (2)$ (0.21)$ (44)$ (1.77)$ (8)$ (0.34)

WTIbenchmarkprice(US$/bbl) $ 70.56 $ 40.93 $ 64.82 $ 38.32

TheincreaseinroyaltiesforthethreeandninemonthsendedSeptember30,2021,comparedtothesameperiodsof2020,isprimarilytheresultoftheincreaseintheWTIbenchmarkprice.

NetOperatingCosts

Netoperatingcostsarecomprisedofthesumofnon-energyoperatingcostsandenergyoperatingcosts,reducedby power revenue. Non-energy operating costs relate to production-related operating activities and energyoperating costs reflect the cost of natural gas used for fuel to generate steam and power at the Corporation’sfacilities.PowerrevenueisrecognizedfromthesaleofsurpluspowergeneratedbytheCorporation’scogenerationfacilitiesattheChristinaLakeProject.TheCorporationutilizesthermallyefficientcogenerationfacilitiestoprovideaportionof itssteamandelectricityrequirements.Anyexcesspowerthat issold intotheAlbertaelectricalgriddisplaces other power sources that have a higher carbon intensity, thereby reducing the Corporation's overallcarbonfootprint.


2021 2020 2021 2020


Non-energyoperatingcosts $ (38)$ (4.46)$ (25)$ (3.96)$ (101)$ (4.12)$ (91)$ (4.25)

Energyoperatingcosts (40) (4.77) (20) (3.17) (110) (4.46) (67) (3.11)

Powerrevenue 18 2.06 7 1.08 64 2.58 32 1.51

Netoperatingcosts $ (60)$ (7.17)$ (38)$ (6.05)$ (147)$ (6.00)$ (126)$ (5.85)

Bitumensalesvolumes-bbls/d 92,251 67,569 89,861 78,354Averagedeliverednaturalgas

price(C$/mcf) $ 4.17 $ 2.77 $ 3.78 $ 2.49Averagerealizedpowersales

price(C$/Mwh) $ 82.17 $ 39.03 $ 88.33 $ 48.41

Non-energyoperatingcostsincreasedforthethreeandninemonthsendedSeptember30,2021,comparedtothesame periods of 2020. In the second and third quarter of 2020, the Corporation benefited from variousgovernment led initiatives to assist the industry through unprecedented market volatility associated withCOVID-19,whichresulted inthecollapseofoilprices in2020. Inresponsetothiscollapse,theCorporationtookmeasurestoreducecoststhroughsalaryrollbacks,reductionsinstaffinglevelsandvendorconcessions.Alsoduringthis time in2020, amajorplanned turnaroundat thePhase1 and2 facilitieswasundertakenwhichdecreasedproduction-relatedactivitiesandcosts.Manyof thecost reductions thatoccurred in2020were temporary,andconsistentwith the improvedpriceenvironmentand increasedproduction-relatedactivities in2021, costshaverisen.

Energy operating costs increased predominantly due to the AECO natural gasmarket strengthening, aswell asincreased consumption as production increased. This was partially offset by the Alberta power marketstrengthening.Powerrevenue,whichincludestheimpactofphysicalriskmanagementcontractsonpowersales,

14

offset energy operating costs by 45% and 58% during the three and ninemonths ended September 30, 2021,respectively,comparedto35%and48%duringthesameperiodsof2020,respectively.

RealizedGainorLossonCommodityRiskManagement

TheCorporationenters intofinancialcommodityriskmanagementcontractsto increasethepredictabilityoftheCorporation'scashflowbymanagingcommoditypricevolatility.


2021 2020 2021 2020


Realizedgain(loss)oncommodityriskmanagement $ (66)$ (7.73)$ 11 $ 1.71 $ (222)$ (9.04)$ 332 $ 15.46

RealizedlossesrecognizedoncommodityriskmanagementcontractswererecognizedduringthethreeandninemonthsendedSeptember30,2021primarilyduetotheincreaseintheWTIpricestodatein2021comparedtotheWTI fixedpricecontracts inplace.Conversely, realizedgainswererecognizedduringthethreeandninemonthsendedSeptember30,2020due to thesignificantweakening in theWTIpricescompared to theWTI fixedpricecontracts in place at that time. Refer to the commodity risk management discussion within the “OTHEROPERATINGRESULTS”sectionofthisMD&Aforfurtherdetails.

15

MarketingActivity

ThefollowingtablessummarizetheCorporation’sblendsales,netof transportationandstorageatEdmontonbysalesmarket for the periods noted to assist in understanding the Corporation's marketing portfolio. All per barrel figurespresentedinthissectionoftheMD&AarebasedonUS$perbarrelofblendsalesvolumesunlessotherwiseindicated:

Blendsalesdistributionbysalesmarket ThreemonthsendedSeptember30,2021Edmonton(US$/bbl) USGC(US$/bbl)

TOTAL(US$/bbl)Pipeline Pipeline(3)(US$perbarrelofblendsales,unlessotherwiseindicated)

WTI-benchmark $ 70.56 $ 70.56 $ 70.56Differential-WTI:AWBatsalespoint (15.88) (5.33) (11.89)Assetoptimization — 1.26 0.48Blendsalesprice 54.68 66.49 59.15

Transportationandstorage(1) (2.17) (11.64) (5.75)

TransportationandstoragefromChristinaLaketoEdmonton(2) 2.17 2.17 2.17

Blendsalesprice,netoftransportation&storageatEdmonton $ 54.68 $ 57.02 $ 55.57

Totalblendsales-bbls/d 79,281 48,265 127,546%oftotalsales 62% 38% 100%

Edmonton(US$/bbl) USGC(US$/bbl)

USGCpremium(US$/bbl)

Averageblendsalespricebylocation $ 54.68 $ 66.49 $ 11.81Transportationandstorage(1) (2.17) (11.64) (9.47)TransportationandstoragefromChristinaLaketoEdmonton(2) 2.17 2.17 —Blendsalesprice,netoftransportation&storageatEdmonton $ 54.68 $ 57.02 $ 2.34

Blendsalesdistributionbysalesmarket ThreemonthsendedSeptember30,2020Edmonton(US$/bbl) USGC(US$/bbl)

TOTAL(US$/bbl)Pipeline Rail Pipeline(3)(US$perbarrelofblendsales,unlessotherwiseindicated)

WTI-benchmark $ 40.93 $ 40.93 $ 40.93 $ 40.93Differential-WTI:AWBatsalespoint (10.73) (20.52) (3.05) (7.35)Assetoptimization — — 0.88 0.55Blendsalesprice 30.20 20.41 38.76 34.13Transportationandstorage(1) (2.36) (6.32) (13.88) (10.07)TransportationandstoragefromChristinaLaketoEdmonton(2) 2.36 2.36 2.36 2.36Blendsalesprice,netoftransportation&storageatEdmonton $ 30.20 $ 16.45 $ 27.24 $ 26.42Totalblendsales-bbls/d 22,275 13,189 58,015 93,479%oftotalsales 24% 14% 62% 100%



Averageblendsalespricebylocation $ 26.56 $ 38.76 $ 12.20Transportationandstorage(1) (3.84) (13.88) (10.04)TransportationandstoragefromChristinaLaketoEdmonton(2) 2.36 2.36 —Blendsalesprice,netoftransportation&storageatEdmonton $ 25.08 $ 27.24 $ 2.16

(1) Definedastransportationandstorageexpenseslesstransportationrevenue,perbarrelofblendsalesvolumes.Forreference,totaltransportationandstoragecostsperbarrel,basedonbitumensalesvolumes,wereC$10.03perbarrelforthethreemonthsendedSeptember30,2021comparedtoC$18.55perbarrelforthethreemonthsendedSeptember30,2020.

(2) IncludesalltransportationandstoragecostsassociatedwithmovingbarrelsofblendfromChristinaLaketoEdmontonsalespoint.(3) Salesfrommarketingassetoptimizationactivitiesarerecognizedintheblendsalespriceandnotasarecoveryoftransportation

and storage costs for consistency with the financial statements. During the three months ended September 30, 2021 theseactivitiescontributedUS$1.26perbarreltotheblendsalespriceattheUSGC(pipeline)comparedtoUS$0.88perbarrelduringthesameperiodof2020.Ifpresentedasatransportationandstoragecostrecovery,transportationandstoragecostsperbarrelattheUSGC (pipeline) during the threemonths ended September 30, 2021would beUS$10.38 per barrel compared toUS$11.64 perbarrel. If presented as a transportation and storage cost recovery, transportation and storage costs per barrel at the USGC(pipeline)duringthethreemonthsendedSeptember30,2020wouldbeUS$13.00perbarrelcomparedtoUS$13.88perbarrel.

(4) Resultsaretranslatedattheaverageforeignexchangerateof1.2602forthethreemonthsendedSeptember30,2021and1.3316forthethreemonthsendedSeptember30,2020.

16

Blendsalesdistributionbysalesmarket NinemonthsendedSeptember30,2021


TOTAL(US$/bbl)Pipeline Pipeline(3)(US$perbarrelofblendsales,unlessotherwiseindicated)

WTI-benchmark $ 64.82 $ 64.82 $ 64.82

Differential-WTI:AWBatsalespoint (15.14) (4.01) (10.67)

Assetoptimization — 1.27 0.51Blendsalesprice 49.68 62.08 54.66


TransportationandstoragefromChristinaLaketoEdmonton(2) 2.11 2.11 2.11


Totalblendsales-bbls/d 76,892 51,524 128,416%oftotalsales 60% 40% 100%



Averageblendsalespricebylocation $ 49.68 $ 62.08 $ 12.40


TransportationandstoragefromChristinaLaketoEdmonton(2) 2.11 2.11 —


Blendsalesdistributionbysalesmarket NinemonthsendedSeptember30,2020


TOTAL(US$/bbl)Pipeline Rail Pipeline(3)(4)(US$perbarrelofblendsales,unlessotherwiseindicated)

WTI-benchmark $ 38.32 $ 38.32 $ 38.32 $ 38.32

Differential-WTI:AWBatsalespoint (19.34) (17.32) (4.22) (13.46)

Assetoptimization — — 1.34 0.50

Blendsalesprice 18.98 21.00 35.44 25.36

Transportationandstorage(1) (2.05) (5.31) (12.64) (6.42)

TransportationandstoragefromChristinaLaketoEdmonton(2) 2.05 2.05 2.05 2.05

Blendsalesprice,netoftransportation&storageatEdmonton $ 18.98 $ 17.74 $ 24.85 $ 20.99

Totalblendsales-bbls/d 55,404 15,142 41,665 112,211

%oftotalsales 49% 14% 37% 100%



Averageblendsalespricebylocation $ 19.41 $ 35.44 $ 16.03


TransportationandstoragefromChristinaLaketoEdmonton(2) 2.05 2.05 —


(1) Definedastransportationandstorageexpenseslesstransportationrevenue,perbarrelofblendsalesvolumes.Forreference,totaltransportationandstoragecostsperbarrel,basedonbitumensalesvolumes,wereC$10.76perbarrelfortheninemonthsendedSeptember30,2021comparedtoC$12.44perbarrelfortheninemonthsendedSeptember30,2020.

(2) IncludesalltransportationandstoragecostsassociatedwithmovingbarrelsofblendfromChristinaLaketoEdmontonsalespoint.(3) Salesfrommarketingassetoptimizationactivitiesarerecognizedintheblendsalespriceandnotasarecoveryoftransportation

andstoragecostsforconsistencywiththefinancialstatements.DuringtheninemonthsendedSeptember30,2021theseactivitiescontributedUS$1.27perbarrel totheblendsalespriceattheUSGC(pipeline)comparedtoUS$1.34perbarrelduringthesameperiodof2020.Ifpresentedasatransportationandstoragecostrecovery,transportationandstoragecostsperbarrelattheUSGC(pipeline)duringtheninemonthsendedSeptember30,2021wouldbeUS$10.56perbarrelcomparedtoUS$11.83perbarrel. Ifpresentedasatransportationandstoragecostrecovery,transportationandstoragecostsperbarrelattheUSGC(pipeline)duringtheninemonthsendedSeptember30,2020wouldbeUS$11.30perbarrelcomparedtoUS$12.64perbarrel.

(4) Includes759bbls/dofblendsalestransportedtotheUSGCviarail.USGCrailwassuspendedduringthefirstquarterof2020.(5) Resultsaretranslatedattheaverageforeignexchangerateof1.2515fortheninemonthsendedSeptember30,2021and1.3541

fortheninemonthsendedSeptember30,2020.

17

Ona transportationadjustedbasis, theCorporation'sUSGCblendsales receivedapremiumover theEdmontonblend sales ofUS$2.34per barrel andUS$2.68per barrel for the three andninemonths ended September 30,2021. This compares to premiumsofUS$2.16 per barrel andUS$6.14 per barrel at theUSGC compared to theEdmonton market during the same periods of 2020. The higher premium during the three months endedSeptember30,2021,comparedtothesameperiodof2020,isprimarilytheresultofwiderrealizeddifferentialsatEdmontoncomparedto theUSGCand lower transportationcosts,both resulting fromhigherapportionmentontheEnbridgemainlinesystem.ThelowerpremiumduringtheninemonthsendedSeptember30,2021,comparedtothesameperiodof2020,isprimarilytheresultofnarrowerrealizeddifferentialsatEdmontonduetoimprovedpipelineegresscapacityandincreasedstoragecapacityinAlberta,partiallyoffsetbyreducedtransportationcostsin2021withthesuspensionofrailactivity.

Revenue

Revenuerepresents thetotalofpetroleumrevenue, includingsalesof third-partyproductsrelatedtomarketingassetoptimizationactivity,netofroyalties,andotherrevenue.


($millions) 2021 2020 2021 2020

Salesfrom:

Production $ 868 $ 385 $ 2,376 $ 1,035

Purchasedproduct(1) 225 140 610 437


Royalties (23) (2) (44) (8)

Petroleumrevenue,netofroyalties $ 1,070 $ 523 $ 2,942 $ 1,464

Powerrevenue $ 18 $ 6 $ 64 $ 32

Transportationrevenue 3 4 8 9

Otherrevenue $ 21 $ 10 $ 72 $ 41

Totalrevenues $ 1,091 $ 533 $ 3,014 $ 1,505

(1) The associated third-party purchases are included in the consolidated statement of earnings (loss) and comprehensiveincome(loss)underthecaption"Purchasedproduct".

During the three andninemonths ended September 30, 2021, total revenues approximately doubled from thesameperiodsof2020primarilyasaresultoftheincreaseintheaverageblendsalespricewhichwasmostlydrivenbytheincreaseinWTIprices.Theincreaseintotalrevenueswasalsoimpactedbya36%and14%increaseinblendsalesvolumes,respectively.

18

CapitalExpenditures



($millions) 2021 2020(1) 2021 2020(1)

Sustainingandmaintenance $ 79 $ 21 $ 203 $ 70

Phase2Bbrownfieldexpansion 3 — 14 14

Fieldinfrastructure,corporateandother 2 — 7 —

Turnaround — 15 — 25

eMVAPEX — 2 — 8

$ 84 $ 38 $ 224 $ 117

eMVAPEXgovernmentgrant — (2) — (8)

$ 84 $ 36 $ 224 $ 109

(1) Certain prior year costs have been reclassified for consistencywith the Corporation's Phase 2B brownfield developmentplan.

TheincreaseincapitalspendingforthethreeandninemonthsendedSeptember30,2021,comparedtothesameperiodsof2020,reflectstheCorporation'sdecisiontoreducecapitalspendingin2020duetotheunprecedentednegativeoilpriceenvironmentexperiencedinthefirsthalfof2020whenreductionsintheCorporation'splannedcapitalprogramwereannounced.Approximately80%ofthereductionsweredeferredtotheCorporation's2021capitalbudget.

TheCorporationinvested$84millionduringthethreemonthsendedSeptember30,2021comparedto$36millionduring the same period of 2020. Themajority of the $84million invested in the quarterwas directed towardssustainingandmaintenanceactivitiesaswellasincrementalwellcapitalnecessarytoallowtheCorporationtofullyutilize theChristinaLakecentralplant facility'soilprocessingcapacityofapproximately100,000bbls/d,prior toany impactfromscheduledmaintenanceactivityoroutages.Aspreviouslydisclosed intheCorporation'ssecondquarter2021release,thetotal investmentforthisoptimization initiative isapproximately$125millionwith$75millionincludedinthe2021capitalinvestmentbudgetandtheremainderexpectedtobeinvestedinthefirsthalfof2022.

TheCorporation'seMVAPEXpilothasachievedmostof itspreliminarygoalsand is in theprocessof recoveringpreviouslyinjectedsolvent.TheCorporationcontinuestoevaluatetheprocess.

The Phase 2B brownfield expansion is completed and the total cost of the expansionwas approximately $260million.

6. OUTLOOK

BasedonbetterthanexpectedproductionperformanceMEGisrevising its fullyear2021averageproductionto92,500–93,500bbls/d.

Summaryof2021GuidanceRevisedGuidance(November8,2021)

RevisedGuidance(July22,2021)

RevisedGuidance(May3,2021)

OriginalGuidance(December7,2020)

Bitumenproduction-annualaverage 92,500-93,500bbls/d 91,000-93,000bbls/d 88,000-90,000bbls/d 86,000-90,000bbls/d

Non-energyoperatingcosts $4.40-$4.50perbbl $4.40-$4.60perbbl $4.60-$5.00perbbl $4.60-$5.00perbbl

G&Aexpense $1.65-$1.75perbbl $1.65-$1.75perbbl $1.70-$1.80perbbl $1.70-$1.80perbbl

Capitalexpenditures $335million $335million $260million $260million

TheCorporation'sestimateoffullyear2021totaltransportationcostsrangefromUS$6.00toUS$6.50perbarrelofAWBblendsales.

19

7. BUSINESSENVIRONMENT

The following table shows industry commodity pricing information and foreign exchange rates for the periodsnotedtoassistinunderstandingtheirimpactontheCorporation’sfinancialresults:

Ninemonthsended

September30 2021 2020 2019

2021 2020 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4

AverageBenchmarkCommodityPrices

Crudeoilprices

Brent(US$/bbl) 67.73 42.55 73.15 68.98 61.06 45.25 43.39 33.30 50.95 62.50

WTI(US$/bbl) 64.82 38.32 70.56 66.07 57.84 42.66 40.93 27.85 46.17 56.96

Differential–WTI:WCS–Edmonton(US$/bbl) (12.51) (13.69) (13.58) (11.49) (12.47) (9.30) (9.09) (11.47) (20.53) (15.83)

Differential–WTI:AWB–Edmonton(US$/bbl) (14.15) (15.56) (15.13) (13.11) (14.22) (10.56) (10.48) (13.44) (22.78) (18.44)

AWB–Edmonton(US$/bbl) 50.67 22.76 55.43 52.96 43.62 32.10 30.45 14.41 23.39 38.52

Differential–WTI:AWB–U.S.GulfCoast(US$/bbl) (4.00) (5.41) (5.57) (3.92) (2.52) (2.83) (3.20) (7.29) (5.74) (5.25)

AWB–U.S.GulfCoast(US$/bbl) 60.82 32.91 64.99 62.15 55.32 39.83 37.73 20.56 40.43 51.71

Condensateprices

CondensateatEdmonton(C$/bbl) 80.79 47.51 87.30 81.55 73.51 55.39 50.03 30.72 61.76 70.01

CondensateatEdmontonas%ofWTI 99.6% 91.6% 98.2% 100.5% 100.4% 99.6% 91.8% 79.6% 99.5% 93.1%

CondensateatMontBelvieu,Texas(US$/bbl) 61.79 30.07 68.19 61.18 56.00 38.52 33.52 17.43 39.27 50.08

CondensateatMontBelvieu,Texasas%ofWTI 95.3% 78.5% 96.6% 92.6% 96.8% 90.3% 81.9% 62.6% 85.1% 87.9%

Naturalgasprices

AECO(C$/mcf) 3.58 2.32 3.92 3.37 3.43 2.88 2.48 2.21 2.26 2.70

Electricpowerprices

Albertapowerpool(C$/MWh) 100.75 46.69 100.27 104.73 97.25 46.05 43.75 29.94 66.38 47.07

Foreignexchangerates

C$equivalentof1US$–average 1.2515 1.3541 1.2602 1.2280 1.2663 1.3031 1.3316 1.3860 1.3445 1.3201

C$equivalentof1US$–periodend 1.2750 1.3324 1.2750 1.2405 1.2572 1.2755 1.3324 1.3616 1.4120 1.2965

ThesignificantdeclineinglobalcrudeoildemandduetotheeffectsoftheCOVID-19pandemicimpactedcrudeoilprices in 2020. Commodity prices have improved in 2021 in line with increased demand, optimism relating tovaccinerolloutsandOPEC+supplymanagement.

CrudeOilPrices

Brentcrudeistheprimaryworldpricebenchmarkforgloballightsweetcrudeoil.ThepriceofWTIisthecurrentbenchmark for mid-continent North American crude oil prices, at Cushing Oklahoma, and its Canadian dollarequivalentisthebasisfordeterminingtheroyaltyrateontheCorporation'sbitumensales.

WCS is a blend of heavy oils, consisting of heavy conventional crude oils and bitumen, blended with sweetsynthetic,lightcrudeoilorcondensate.WCStypicallytradesatadifferentialbelowtheWTIbenchmarkprice.TheWCSbenchmarkatEdmontonreflectsheavyoilpricesatHardisty,Alberta.

TheCorporation sells AWB, an oil similar toWCS, but generally priced at a discount to theWCSbenchmark atEdmonton,withthediscountdependentonthequalitydifferencebetweenAWBandWCSandthesupply/demandfundamentalsforoilinWesternCanada.AWBisalsosoldattheUSGCandissoldatadiscountorpremiumtoWTIdependentonthesupply/demandfundamentalsforoilintheUSGCregion.

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CondensatePrices

Inordertofacilitatepipelinetransportationofbitumen,theCorporationusescondensateasdiluentforblendingwith the Corporation’s bitumen. The price of condensate generally correlates with the price of WTI. TheCorporationsourcesitscondensatefromboththeEdmontonareaandtheUSGC,wherepricingisgenerallylower.TheCorporationhascommitteddiluentpurchasesof20,000bbls/dat theUSGCreferencebenchmarkpricingatMont Belvieu, Texas. Condensate pricing was impacted by market conditions precipitated by COVID-19 whencondensatepricingfellsharplyinthesecondquarterof2020whichwasinlinewithreducedthermaloilproductionand lowerdemand fordiluent.During the secondhalf of 2020, condensatepricing steadily increasedaspricingcame back in line with WTI. Condensate pricing has subsequently strengthened beyond levels seen prior toCOVID-19 as supply has not responded as quickly as demand in both the Edmonton area and USGC. Refer tobitumenrealizationwithinthe"CASHOPERATINGNETBACK"sectionofthisMD&Aforfurtherdetails.

NaturalGasPrices

Natural gas is a primary energy input cost for theCorporation, used as fuel to generate steam for the thermalproductionprocessandtocreatesteamandelectricity fromtheCorporation'scogeneration facilities.TheAECOnaturalgaspriceincreasedduringthethreeandninemonthsendedSeptember30,2021comparedtothesameperiods of 2020 due to market uncertainty surrounding possible gas supply constraints in 2021, coupled withextremeweatherconditionsinthefirstquarterof2021.

ElectricPowerPrices

Electric power prices impact the price that the Corporation receives on the sale of surplus power from theCorporation’s cogeneration facilities. TheAlbertapowerpoolprice increasedduring the threeandninemonthsended September 30, 2021 compared to the same periods of 2020 primarily as a result of extreme weatherconditionsinFebruaryandJune2021aswellasinresponsetohighernaturalgasinputcosts.

8. OTHEROPERATINGRESULTS

GeneralandAdministrative



($millions,exceptasindicated) 2021 2020 2021 2020

Generalandadministrativeexpense $ 14$ 10$ 41$ 35

Generalandadministrativeexpenseperbarrelofproduction $ 1.72$ 1.50$ 1.68$ 1.61


G&Aexpenseincreased47%and20%duringthethreeandninemonthsendedSeptember30,2021comparedtothe same periods of 2020. In the second and third quarter of 2020, the Corporation benefited from variousgovernment led initiatives to assist the industry through unprecedented market volatility associated withCOVID-19,whichresulted inthecollapseofoilprices in2020. Inresponsetothiscollapse,theCorporationtookmeasurestoreducecoststhroughsalaryrollbacks,reductionsinstaffinglevelsandvendorconcessions.Manyofthecostreductionsthatoccurred in2020weretemporary,andconsistentwiththe improvedpriceenvironmentandincreasedproduction-relatedactivitiesin2021,costshaverisen.

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DepletionandDepreciation



($millions,exceptasindicated) 2021 2020 2021 2020

Depletionanddepreciationexpense $ 108$ 87$ 324$ 304

Depletionanddepreciationexpenseperbarrelofproduction $ 12.78$ 13.33$ 12.97$ 13.97


TotaldepletionanddepreciationexpenseincreasedduringthethreeandninemonthsendedSeptember30,2021,comparedtothesameperiodsin2020,primarilyduetotheincreaseinproduction.Thedepletionanddepreciationexpense per barrel decreased during the same periods as the depreciation expense of assets determined on astraight-linebasisisspreadoveragreaternumberofbarrelsofproduction.

ExplorationExpense



($millions) 2021 2020 2021 2020

Explorationexpense $ —$ —$ —$ 366

Exploration expense is recognizedwhen facts and circumstances suggest that the carrying amount exceeds therecoverable amount and theCorporationdecides todiscontinueexplorationandevaluationactivitieswhicharependingthedeterminationofprovedorprobablereserves.DuringthethreeandninemonthsendedSeptember30, 2021 there was no exploration expense recognized. During the first quarter of 2020, the Corporationdiscontinued exploration and evaluation activities in certain non-core growth properties as it narrowed thedevelopmentfocustocoreassetsatChristinaLake.Theassociatedlandleaseandevaluationcoststotaling$366millionwerechargedtoexplorationexpense.

CommodityRiskManagementGain(Loss)

TheCorporationenters intofinancialcommodityriskmanagementcontractsto increasethepredictabilityoftheCorporation's cash flowbymanaging commodity price volatility. The Corporation has not designated any of itscommodity risk management contracts as hedges for accounting purposes. All financial commodity riskmanagement contracts have been recorded at fair value,with all changes in fair value recognized through netearnings (loss). Realized gains or losses on financial commodity risk management contracts are the result ofcontract settlements during the period. Unrealized gains or losses on financial commodity risk managementcontracts represent the change in the mark-to-market position of the unsettled commodity risk managementcontractsduringtheperiod.

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($millions) 2021 2020 2021 2020

Realized:

Crudeoilcontracts(1) $ (79)$ 15 $ (254)$ 350

Condensatecontracts(2) 10 (4) 27 (18)

Naturalgascontracts(3) 3 — 5 —

Realizedcommodityriskmanagementgain(loss) $ (66)$ 11 $ (222)$ 332

Unrealized:

Crudeoilcontracts(1) $ 65 $ (36)$ (42)$ 81

Condensatecontracts(2) (1) 19 (20) 63

Naturalgascontracts(3) 4 — 15 —

Unrealizedcommodityriskmanagementgain(loss) $ 68 $ (17)$ (47)$ 144

Commodityriskmanagementgain(loss) $ 2 $ (6)$ (269)$ 476

(1) IncludesWTIfixedpricecontracts,WTIenhancedfixedpricecontractswithsoldputoptionsandWTI:WCSfixeddifferentialcontracts.

(2) RelatestocondensatepurchasecontractsthateffectivelyfixcondensatepricesatMontBelvieu,TexasrelativetoWTI.(3) RelatestocontractswhichfixtheAECOpriceonnaturalgaspurchases.

For the three months ended September 30, 2021, the Corporation recognized a $2 million net gain fromcommodityriskmanagementprimarilyduetothegainsoncondensateandnaturalgascontracts,asthemarketpricesofthesecommoditiesforcurrentandfutureperiodsincreasedduringthequarter,largelyoffsetbylossesonWTIfixedpricecontracts(includingenhancedfixedpricecontractswithsoldputoptions)asmarketWTIpricesalsoincreased.

For the nine months ended September 30, 2021, the Corporation recognized a $269 million net loss fromcommodityriskmanagementprimarilyduetolossesonWTIfixedpricecontracts(includingenhancedfixedpricecontractswithsoldputoptions)asmarketWTIpricesfor2021increasedovertheninemonthperiod.Theselosseswerepartiallyoffsetbygainsonnaturalgasandcondensatecontracts,asthemarketpricesofthesecommoditiesforcurrentandfutureperiodsincreased.

During the three months ended September 30, 2020, the Corporation recognized a $6 million net loss fromcommodity riskmanagement primarily reflecting amodest recovery inWTI prices through the third quarter of2020.DuringtheninemonthsendedSeptember30,2020,theCorporationrecognizeda$476millioncommodityriskmanagement gainwhich reflected the significant decline inWTI prices due to thedemand shockon globalmarketsdrivenbyCOVID-19.

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The realized commodity risk management gain (loss) represents actual contract settlements over the periodspresented.The following tableprovides furtherdetails regarding the realizedcommodity riskmanagementgain(loss):



(US$/bbl) 2021 2020 2021 2020

WTIfixedpricecontracts(1)(2):

Averagefixedprice $ 46.18 $ 44.51 $ 46.77 $ 53.47

Averagesettlementprice 70.55 40.93 62.98 38.32

Gain(loss)onWTIfixedpricecontracts $ (24.37)$ 3.58 $ (16.21)$ 15.15

WTI:WCSfixeddifferentialcontracts:

Averagefixeddifferential $ (11.05)$ (20.72)$ (12.13)$ (20.10)

Averagesettlementdifferential (13.46) (9.09) (11.88) (13.70)

Gain(loss)onWTI:WCSfixeddifferentialcontracts $ 2.41 $ (11.63)$ (0.25)$ (6.40)

Condensatepurchasecontracts:

Averagefixeddifferential(3) $ (10.37)$ (5.15)$ (10.14)$ (5.44)

Averagesettlementdifferential (2.40) (7.41) (3.18) (8.26)

Gain(loss)oncondensatepurchasecontracts $ 7.97 $ (2.26)$ 6.96 $ (2.82)

Naturalgaspurchasecontracts:

Averagefixedprice $ 2.60 $ — $ 2.60 $ —

Averagesettlementprice 3.41 — 3.09 —

Gain(loss)onnaturalgaspurchasecontracts $ 0.81 $ — $ 0.49 $ —

(1) Includesenhancedfixedpricewithsoldputoptioncontracts.(2) IncrementaltotheseWTIfixedpricecontracts,theCorporationoccasionallyentersintocontractstofixthespreadbetween

WTIpricesforconsecutivemonths,thegainsandlossesonwhicharenotreflectedinthistable.(3) CondensatepurchasecontractseitherfixtheWTI:condensatedifferentialatMontBelvieu,TexasrelativetoWTIorfixthe

condensatepriceasa%ofWTI.

Stock-basedCompensation



($millions) 2021 2020 2021 2020

Cash-settledexpense(recovery) $ 13 $ (1)$ 48 $ (10)

Equity-settledexpense 4 2 12 9

Equitypriceriskmanagement(gain)loss(1) (7) 9 (44) (11)

Stock-basedcompensation $ 10 $ 10 $ 16 $ (12)

(1) Relates to financial derivatives entered into tomanage theCorporation's exposure to cash-settled restricted shareunits("RSUs") and performance share units ("PSUs") vesting in 2021, 2022 and 2023 granted under the Corporation's stock-basedcompensationplans.Amountsareunrealizeduntilvestingoftherelatedunitsoccurs.SeeRiskManagementsectionofthisMD&Aforfurtherdetails.

Thecash-settledexpenserecognizedduringthethreeandninemonthsendedSeptember30,2021wasduetotheincreaseintheCorporation'sshareprice.TheCorporation'scommonsharepriceincreasedto$9.89pershareasatSeptember30,2021fromitsvalueof$8.97pershareasatJune30,2021and$4.45pershareasatDecember31,2020.

Thecash-settledrecoveryduringthethreeandninemonthsendedSeptember30,2020wasduetothedecreaseintheCorporation'ssharepriceto$2.77pershareasatSeptember30,2020fromitsvalueof$3.77pershareasatJune30,2020and$7.39pershareasatDecember31,2019.

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Equity-settledstockbasedcompensationexpenseincreasedforthethreeandninemonthsendedSeptember30,2021,comparedtothesameperiodsof2020,primarilyduetoanincreaseinthevalueofawardsgrantedwhichweretemporarilyreducedin2020inresponsetothechallenginglowoilpriceenvironment.

The equity price riskmanagement (gain) loss is driven by the change in the Corporation's common share pricerelativetothenotionalvalueofthe instruments.ForthethreeandninemonthsendedSeptember30,2021,anequitypriceriskmanagementgainof$7millionand$44million,respectively,wasrecognizedonthe increase insharepriceduringtheperiods.

ForeignExchangeGain(Loss),Net



($millions) 2021 2020 2021 2020

Unrealizedforeignexchangegain(loss)on:

Long-termdebt $ (77)$ 67 $ 9 $ (95)

US$denominatedcashandcashequivalents (1) 3 (3) 12

Unrealizednetgain(loss)onforeignexchange (78) 70 6 (83)

Realizedgain(loss)onforeignexchange 1 — 1 (1)

Foreignexchangegain(loss),net $ (77)$ 70 $ 7 $ (84)

C$equivalentof1US$

Beginningofperiod 1.2405 1.3616 1.2755 1.2965

Endofperiod 1.2750 1.3324 1.2750 1.3324

The Corporation's foreign exchange gain (loss) is driven by fluctuations in the U.S. dollar to Canadian dollarexchangerate.TheprimarydriveroftheCorporation'sforeignexchangegain(loss)istheCorporation'slong-termdebtwhichisdenominatedinU.S.dollars.

DuringthethreemonthsendedSeptember30,2021,theCanadiandollarweakenedrelativetotheU.S.dollarby3%resultinginanunrealizedforeignexchangelossof$78million.DuringtheninemonthsendedSeptember30,2021, the Canadian dollar strengthened slightly relative to the U.S. dollar resulting in an unrealized foreignexchangegainof$6million.

During the threemonths ended September 30, 2020, the Canadian dollar strengthened by 2%, resulting in anunrealizedforeignexchangegainof$70million.DuringtheninemonthsendedSeptember30,2020,theCanadiandollarweakenedrelativetotheU.S.dollarby3%,resultinginanunrealizedforeignexchangelossof$83million.

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NetFinanceExpense



($millions) 2021 2020 2021 2020

Interestexpenseonlong-termdebt $ 55 $ 59 $ 166 $ 183

Interestexpenseonleaseliabilities 6 6 19 19

Interestincome (1) — (1) (2)

Netinterestexpense 60 65 184 200

Accretiononprovisions 2 2 6 6

Debtextinguishmentexpense — — 5 —

Netfinanceexpense $ 62 $ 67 $ 195 $ 206

Averageeffectiveinterestrate 6.7% 7.0% 6.7% 6.9%

Interest expense on long-term debt decreased during the three and nine months ended September 30, 2021compared to the same periods of 2020 primarily as a result of the strengthening Canadian dollar as all of theCorporation'slong-termdebtisdenominatedinUSdollars.AlsocontributingtothedecreasewastherefinancingofUS$600millionofseniorunsecurednotesonFebruary2,2021atarateof5.875%comparedtothepreviousrateof7.0%.

FortheninemonthsendedSeptember30,2021,debtextinguishmentexpensewasrecognizedinassociationwiththe August 23, 2021 debt redemption and included a cumulative debt redemption premium of $4million andassociated unamortized deferred debt issue costs of $1 million. Refer to Note 6 of the interim consolidatedfinancialstatementsforfurtherdetails.

IncomeTax



($millions) 2021 2020 2021 2020

Currentincometaxexpense(recovery) $ — $ — $ (2) $ (1)

Deferredincometaxexpense(recovery) 39 (20) 37 (83)

Incometaxexpense(recovery) $ 39 $ (20) $ 35 $ (84)

Effectivetaxrate 42% 78% 25% 19%

ForthethreeandninemonthsendedSeptember30,2021,anincometaxexpensewasrecognizedcomparedtoanincome tax recovery in the same periods of 2020 due to increased earnings before income taxes and foreignexchangegainsandlossesonlong-termdebt.Also,theCorporationrecognizeda$12milliondeferredtaxexpenseduringthesecondquarterof2021associatedwiththetaxtreatmentofaprioryearinvestmentinpipelineaccess.TheCorporationdisputesCanadaRevenueAgency'sassessmentandcontinuestoconsideritsalternatives.

As at September 30, 2021, the Corporation had approximately $7.3 billion of available Canadian tax pools andrecognized a deferred income tax asset of $345 million. Estimated future taxable income is expected to besufficienttorealizethedeferredincometaxasset.

Theeffective tax ratesdiffer from theCanadian statutory rateof23%primarilydue to the taxeffectof foreignexchangegainsandlossesontheCorporation'slong-termdebtwhichisdenominatedinU.S.dollars.

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9. LIQUIDITYANDCAPITALRESOURCES

($millions) September30,2021 December31,2020

SecondLien:

6.5%seniorsecuredsecondliennotes(Sept30,2021-US$396million;due2025;December31,2020-US$496million) $ 505 $ 633

Unsecured:

7.125%seniorunsecurednotes(Sept30,2021-US$1.2billion;due2027;December31,2020-US$1.2billion) 1,530 1,531

5.875%seniorunsecurednotes(Sept30,2021-US$600million;due2029;December31,2020-US$nil) 765 —

7.0%seniorunsecurednotes(Sept30,2021-US$nil;December31,2020-US$600million;due2024) — 765

Debtredemptionpremium — 9

Unamortizeddeferreddebtdiscountanddebtissuecosts (31) (26)

Long-termdebt 2,769 2,912

Cashandcashequivalents (210) (114)

Netdebt(1) $ 2,559 $ 2,798

(1) Net debt is reconciled to long-term debt in accordance with IFRS in Note 19 of the interim consolidated financialstatements.

OnAugust23,2021,theCorporationredeemedUS$100million(approximatelyC$125million)oftheCorporation's6.5%seniorsecuredsecondliennotesdueJanuary2025ataredemptionpriceof103.25%plusaccruedandunpaidinterest.

OnFebruary2,2021,theCorporationsuccessfullyclosedaprivateofferingofUS$600millioninaggregateprincipalamount of 5.875% senior unsecurednotes due February 2029. Thenet proceeds of the offering, togetherwithcash-on-hand, were used to fully redeem US$600 million in aggregate principal amount of its 7.0% seniorunsecurednotesdueMarch2024ataredemptionpriceof101.167%andtopayfeesandexpensesrelatedtotheoffering.

TheCorporation'scashandcashequivalentsbalancewas$210millionasatSeptember30,2021comparedto$114millionasatDecember31,2020.Refertothe"CashFlowSummary"sectionforfurtherdetails.

TheCorporationhastotalavailablecreditundertwofacilitiesof$1.3billion,comprisedof$800millionundertherevolvingcreditfacilityand$500millionunderaletterofcreditfacilityguaranteedbyExportDevelopmentCanada("EDCFacility").LettersofcreditundertheEDCFacilitydonotconsumecapacityoftherevolvingcreditfacility.TherevolvingcreditfacilityandtheEDCFacilityhaveamaturitydateofJuly30,2024.Therevolvingcreditfacility,EDCFacilityandseniorsecuredsecondliennotesaresecuredbysubstantiallyalltheassetsoftheCorporation.

Meeting current and future obligations while navigating the uncertainty associated with commodity marketvolatility continues to be supported by the Corporation's financial framework, including a commodity riskmanagement program securing cash flow through 2021, and credit riskmanagement policiesminimizing creditexposure on sales to primarily investment grade customers in the energy industry. The Corporation's earliestmaturing long-termdebt ismorethanthreeyearsout, representedbyUS$396millionofseniorsecuredsecondliennotesdueJanuary2025.NoneoftheCorporation’soutstandinglong-termdebtcontainfinancialmaintenancecovenants. Additionally, the Corporation's modified covenant-lite $800 million revolving credit facility has nofinancialmaintenance covenant unless drawn in excess of $400million. If drawn in excess of $400million, theCorporationisrequiredtomaintainaquarterlyfirstliennetleverageratio(firstliennetdebttolasttwelve-monthEBITDA)of3.5or less.Under theCorporation's credit facility, first liennetdebt is calculatedasdebtunder thecreditfacilityplusotherdebtthatissecuredonaparipassubasiswiththecreditfacility,lesscash-on-hand.None

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oftheCorporation'soutstandinglong-termdebtcontainfinancialmaintenancecovenantsandnonearesecuredonaparipassubasiswiththecreditfacility.

AsatSeptember30,2021,theCorporationhad$788millionofunutilizedcapacityunderthe$800millionrevolvingcredit facility and the Corporation had $85million of unutilized capacity under the $500million EDC Facility. Aletterofcreditof$15millionwasissuedundertherevolvingcreditfacilityduringthethreemonthsendedMarch31, 2020 and $12 million remains outstanding as at September 30, 2021. Letters of credit issued under therevolvingcreditfacilityarenotincludedinfirstliennetdebtforpurposesofcalculatingthefirstliennetleverageratio.

Managementbelieves itscurrentcapitalresourcesanditsabilitytomanagecashflowandworkingcapital levelswill allow the Corporation tomeet its current and future obligations, tomake scheduled principal and interestpayments,andtofundtheotherneedsofthebusinessforatleastthenext12months.However,noassurancecanbegiventhatthiswillbethecaseorthatfuturesourcesofcapitalwillnotbenecessary.TheCorporation'scashflowandthedevelopmentofprojectsaredependentonfactorsdiscussed inthe"RISKFACTORS"sectionofthisMD&A.

CashFlowSummary



($millions) 2021 2020 2021 2020

Netcashprovidedby(usedin):

Operatingactivities $ 257 $ (31)$ 449 $ 186

Investingactivities (69) (36) (191) (145)

Financingactivities (136) (6) (158) (209)

Effectofexchangeratechangesoncashandcashequivalentsheldinforeigncurrency (1) 2 (4) 11

Changeincashandcashequivalents $ 51 $ (71)$ 96 $ (157)

CashFlow–OperatingActivities

Net cash provided by operating activities for the three and ninemonths ended September 30, 2021 increasedcomparedtothesameperiodsof2020,primarilyduetohigherbenchmarkcrudeoilprices.

CashFlow–InvestingActivities

Net cash used in investing activities increased during the three and nine months ended September 30, 2021comparedtothesameperiodsof2020reflectingincreasedcapitalspendingovertheseperiods.

CashFlow–FinancingActivities

NetcashusedinfinancingactivitiesforthethreemonthsendedSeptember30,2021increasedcomparedtothesameperiodof2020,primarilyduetothedebtredemptionduringthethreemonthsendedSeptember30,2021.

NetcashusedinfinancingactivitiesfortheninemonthsendedSeptember30,2021decreasedcomparedtothesame period of 2020, primarily due to larger debt repayment and associated higher debt redemption andrefinancingcostsincurredduringtheninemonthsendedSeptember30,2020.

10. RISKMANAGEMENT

CommodityPriceRiskManagement

Tomitigate theCorporation’s exposure to fluctuations in commodityprices, theCorporationperiodically entersintofinancialcommodityriskmanagementcontractstopartiallymanageitsexposureonblendsales,condensate

28

purchases,naturalgaspurchasesandpowersales.TheCorporationalsoperiodicallyentersintophysicaldeliverycontractswhicharenotconsideredfinancialinstrumentsandthereforenoassetorliabilityhasbeenrecognizedintheConsolidatedBalanceSheetrelatedtothesecontracts.Theimpactofrealizedphysicaldeliverycontractpricesis included in the Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) and in cashoperatingnetback.

The Corporation had the following financial commodity risk management contracts relating to crude oil sales,condensatepurchasesandnaturalgaspurchasesoutstandingasatSeptember30,2021:

AsatSeptember30,2021

CrudeOilSalesContracts(1)Volumes(bbls/d)(2) Term

AveragePrice(US$/bbl)(2)

EnhancedFixedPricewithSoldPutOption

WTIFixedPrice/SoldPutOptionStrikePrice 29,000 Oct1,2021-Dec31,2021 $46.18/$38.79

CondensatePurchaseContracts

WTI:MontBelvieuFixedDifferential 10,950 Oct1,2021-Dec31,2021 $(10.37)

WTI:MontBelvieuFixedDifferential 200 Jan1,2022-Dec31,2022 $(11.30)

NaturalGasPurchaseContractsVolumes(GJ/d)(2) Term

AveragePrice(C$/GJ)(2)

AECOFixedPrice 37,500 Oct1,2021-Dec31,2021 $2.60

AECOFixedPrice 5,000 Jan1,2022-Dec31,2023 $2.50

(1) Incrementaltothesecrudeoilsalescontracts,theCorporationoccasionallyentersintocontractstofixthespreadbetweenWTIprices forconsecutivemonths to supportcertainmarketingassetoptimizationactivities.AsatSeptember30,2021,therewereapproximately9,900bbls/dand3,300bbls/doftheseWTIhedgesoutstanding,whichwerescheduledtosettleduringOctoberandNovember2021,respectively.Unrealizedlossesonthesetotaledapproximately$3.4million.

(2) Thevolumesandprices in theabove table representaverages forvariouscontractswithdiffering termsandprices.Theaverageprices for theportfoliomaynothavethesamepaymentprofileas the individualcontractsandareprovided forindicativepurposes.

TheCorporationdidnotenterintofinancialcommodityriskmanagementcontractsbetweenSeptember30,2021andNovember8,2021.

Thefollowingtablesummarizesthesensitivityofcashoperatingnetback,adjustedfundsflowandearnings(loss)before income tax of fluctuating commodity prices on the Corporation’s open financial commodity riskmanagementpositionsinplaceasatSeptember30,2021:

Commodity SensitivityRange Increase Decrease

Crudeoilcommodityprice ±US$5.00perbblappliedtoWTIcontracts $ (17) $ 17

Condensatepurchaseprice ±5%incondensatepriceasapercentageofWTI $ 5 $ 5

Naturalgaspurchaseprice ±C$0.50perGJappliedtonaturalgascontracts $ 4 $ (4)

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The Corporation had the following physical commodity risk management contracts relating to crude oil sales,condensatepurchases,naturalgaspurchasesandpowersalesoutstandingasatSeptember30,2021:

CondensatePurchaseContractsVolumes(bbls/d)(1) Term

AveragePrice(US$/bbl)(1)

WTI:CondensateFixedDifferential 3,078 Oct1,2021-Dec31,2021 $(1.80)

NaturalGasPurchaseContractsVolumes(GJ/d)(1) Term

AveragePrice(C$/GJ)(1)


PowerSalesContractsQuantity(MW)(1) Term

AveragePrice(C$/MWh)(1)

FixedPrice 35 Oct1,2021-Dec31,2021 $62.75

(1) Thevolumesandprices in theabove table representaverages forvariouscontractswithdiffering termsandprices.Theaverage price for the portfoliomay not have the same payment profile as the individual contracts and is provided forindicativepurposes.

EquityPriceRiskManagement

TheCorporationentersintofinancialequitypriceriskmanagementcontractstoincreasethepredictabilityoftheCorporation's cash flow by managing share price volatility. Equity price risk is the risk that changes in theCorporation’sownshareprice impactearningsandcashflows.Earningsandfundsflowfromoperatingactivitiesare impacted when outstanding cash-settled RSUs and PSUs, issued under the Corporation's stock-basedcompensation plans, are revalued each period based on the Corporation’s share price and the revaluation isrecognizedinstock-basedcompensationexpense.Netcashprovidedby(usedin)operatingactivitiesisimpactedwhen these stock-based compensation units are ultimately settled. The Corporation entered into these equitypriceriskmanagementcontractstomanageitsexposureoncash-settledRSUsandPSUsvestingbetween2021and2023.



($millions) 2021 2020 2021 2020

Unrealizedequitypriceriskmanagement(gain)loss $ (7)$ 9 $ (36)$ (11)

Realizedequitypriceriskmanagement(gain)loss — — (8) —

Equitypriceriskmanagement(gain)loss $ (7)$ 9 $ (44)$ (11)

11. SHARESOUTSTANDING

AsatSeptember30,2021,theCorporationhadthefollowingsharecapitalinstrumentsoutstandingorexercisable:

(millions) Units

Commonshares 306.8

Convertiblesecurities

Stockoptions(1) 2.6

Equity-settledRSUsandPSUs 6.6

(1) 2.4millionstockoptionswereexercisableasatSeptember30,2021.

As at November 5, 2021, the Corporation had 306.8million common shares, 2.5million stock options and 6.6millionequity-settledRSUsandequity-settledPSUsoutstanding,and2.3millionstockoptionsexercisable.

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12. CONTRACTUALOBLIGATIONS,COMMITMENTSANDCONTINGENCIES

ContractualObligationsandCommitments

Theinformationpresentedinthetablebelowreflectsmanagement’sestimateofthecontractualmaturitiesoftheCorporation’s obligations as at September 30, 2021. These maturities may differ significantly from the actualmaturities of these obligations. In particular, debt under the senior secured credit facilities, the senior securedsecond lien notes, and the senior unsecured notes may be retired earlier due to mandatory or discretionaryrepaymentsorredemptions.

($millions) 2021(1) 2022 2023 2024 2025 Thereafter TotalCommitments:Transportationandstorage(2) $ 100 $ 405 $ 441 $ 441 $ 416 $ 5,677 $ 7,480Diluentpurchases 121 28 17 — — — 166Otheroperatingcommitments 6 16 16 13 12 37 100Variableofficeleasecosts 1 4 4 4 4 27 44Capitalcommitments 37 — — — — — 37

TotalCommitments 265 453 478 458 432 5,741 7,827OtherObligations:Leaseobligations 19 43 38 37 29 491 657Long-termdebt(3) — — — — 505 2,295 2,800Interestonlong-termdebt(3) 47 187 187 187 157 263 1,028Decommissioningobligation(4) — 4 5 4 4 778 795TotalCommitmentsandObligations $ 331 $ 687 $ 708 $ 686 $ 1,127 $ 9,568 $ 13,107

(1) Amountsrepresentcontractualmaturitiesoccurringinthefourthquarterof2021.(2) This represents transportationand storage commitments from2021 to2048, includingpipeline commitmentswhichare

awaiting regulatoryapprovalandarenotyet in service.Excludes finance leases recognizedon theconsolidatedbalancesheet.

(3) Thisrepresentsthescheduledprincipalrepaymentsoftheseniorsecuredsecondliennotes,theseniorunsecurednotes,andassociatedinterestpaymentsbasedoninterestandforeignexchangeratesineffectonSeptember30,2021.

(4) ThisrepresentstheundiscountedfutureobligationsassociatedwiththedecommissioningoftheCorporation’sassets.

Contingencies

The Corporation is involved in various legal claims associated with the normal course of operations. TheCorporationbelievesthatanyliabilitiesthatmayarisepertainingtosuchmatterswouldnothaveamaterialimpactonitsfinancialposition.

The Corporationwas the defendant to a statement of claim originally filed in 2014 in relation to legacy issuesinvolvingaunittraintransloadingfacilityinAlberta.Theclaimwasamendedinthefourthquarterof2017assertinga significant increase to damages claimed. The Corporation filed a statement of defense in the first quarter of2018. During the third quarter of 2021, the Corporation reached an agreement to settle this litigationmatter.Under theagreement, theCorporationpaid (subsequent to thequarter) the sumof$21million in full and finalsettlementoftheclaimandtheclaimhasbeendiscontinued.

13. NON-GAAPMEASURES

Cash operating netback is a non-GAAPmeasure. Its terms are not defined by IFRS and, therefore,may not becomparable to similarmeasures provided by other companies. This non-GAAP financialmeasure should not beconsideredinisolationorasanalternativeformeasuresofperformancepreparedinaccordancewithIFRS.

Cash operating netback is ameasure widely used in the oil and gas industry as a supplemental measure of acompany’sefficiencyanditsabilitytofundfuturecapitalexpenditures.TheCorporation’scashoperatingnetbackis calculated by deducting the related cost of diluent, blend purchases, transportation and storage, third-partycurtailmentcredits,operatingexpenses,royaltiesandrealizedcommodityriskmanagementgainsor lossesfromblendsalesandpower revenue.Theperbarrel calculationof cashoperatingnetback isbasedonbitumensalesvolume.

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14. CRITICALACCOUNTINGPOLICIESANDESTIMATES

TheCorporation'scriticalaccountingpoliciesandestimatesarethoseestimateshavingasignificantimpactontheCorporation's financial position and operations and that requiremanagement tomake judgments, assumptionsandestimatesintheapplicationofIFRS.Judgments,assumptionsandestimatesarebasedonhistoricalexperienceand other factors that management believes to be reasonable under current conditions. As events occur andadditional information is obtained, these judgments, assumptions and estimates may be subject to change.Detaileddisclosureofthesignificantaccountingpoliciesandthesignificantaccountingestimates,assumptionsandjudgmentsusedbytheCorporationcanbefoundintheCorporation'sannualconsolidatedfinancialstatementsfortheyearendedDecember31,2020.

15. RISKFACTORS

The Corporation's primary focus is on the ongoing development and operation of its thermal oil assets. Indeveloping and operating these assets, the Corporation is and will be subject to many risks, including amongothers,operationalrisks,risksrelatedtoeconomicconditions,environmentalandregulatoryrisks,andfinancingrisks.Manyoftheserisksimpacttheoilandgasindustryasawhole.Furtherinformationregardingtheriskfactorswhich may affect the Corporation is contained in the most recently filed AIF, which is available on theCorporation’swebsiteatwww.megenergy.comandisalsoavailableontheSEDARwebsiteatwww.sedar.com.

16. DISCLOSURECONTROLSANDPROCEDURES

TheCorporation’sChiefExecutiveOfficer(“CEO”)andChiefFinancialOfficer(“CFO”)havedesigned,orcausedtobedesignedundertheirsupervision,disclosurecontrolsandprocedurestoprovidereasonableassurancethat:(i)material information relating to the Corporation ismade known to the Corporation’s CEO and CFO by others,particularlyduringtheperiod inwhichtheannual filingsarebeingprepared;and(ii) informationrequiredtobedisclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it undersecurities legislation is recorded, processed, summarized and reported within the time period specified insecuritieslegislation.

17. INTERNALCONTROLSOVERFINANCIALREPORTING

TheCEOandCFOhavedesigned,orcausedtobedesignedundertheirsupervision,internalcontrolsoverfinancialreportingtoprovidereasonableassuranceregardingthereliabilityoftheCorporation’sfinancialreportingandthepreparationoffinancialstatementsforexternalpurposesinaccordancewithIFRS.

The CEO and CFO are required to cause the Corporation to disclose any change in the Corporation’s internalcontrolsoverfinancialreportingthatoccurredduringthemostrecentinterimperiodthathasmateriallyaffected,orisreasonablylikelytomateriallyaffect,theCorporation’sinternalcontrolsoverfinancialreporting.Nochangesininternalcontrolsoverfinancialreportingwereidentifiedduringsuchperiodthathavemateriallyaffected,orarereasonablylikelytomateriallyaffect,theCorporation’sinternalcontrolsoverfinancialreporting.

It should be noted that a control system, including the Corporation’s disclosure and internal controls andprocedures, nomatter howwell conceived, can provide only reasonable, but not absolute, assurance that theobjectivesofthecontrolsystemwillbemetanditshouldnotbeexpectedthatthedisclosureandinternalcontrolsand procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, managementnecessarily is required toapply its judgment inevaluating the cost/benefit relationshipofpossible controls andprocedures.

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18. ABBREVIATIONS

Thefollowingprovidesasummaryofcommonabbreviationsusedinthisdocument:

FinancialandBusinessEnvironment Measurement

AECO Albertanaturalgaspricereferencelocation bbl barrel

AIF AnnualInformationForm bbls/d barrelsperday

AWB AccessWesternBlend mcf thousandcubicfeet

$orC$ Canadiandollars mcf/d thousandcubicfeetperday

DSU Deferredshareunits MW megawatts

EDC ExportDevelopmentCanada MW/h megawattsperhour

eMSAGP enhancedModifiedSteamAndGasPush

eMVAPEX enhancedModifiedVAPourEXtraction

ESG Environment,SocialandGovernance

GAAP GenerallyAcceptedAccountingPrinciples

GHG GreenhouseGas

IFRS InternationalFinancialReportingStandards

LIBOR LondonInterbankOfferedRate

MD&A Management’sDiscussionandAnalysis

PSU Performanceshareunits

RSU Restrictedshareunits

SAGD Steam-AssistedGravityDrainage

SOR Steam-oilratio

U.S. UnitedStates

US$ UnitedStatesdollars

WCS WesternCanadianSelect

WTI WestTexasIntermediate

19. ADVISORY

Forward-LookingInformation

This documentmay contain forward-looking informationwithin themeaningof applicable securities laws. Thisforward-looking information is identified by words such as “anticipate”, “believe”, “could”, “drive”, “expect”,“estimate”,“focus”,“forward”,“future”,“guidance”,“may”,“ontrack”,“outlook”,“plan”,“position”,“potential”,“priority”, “should”, “strategy”, “target”, “will”, “would” or similar expressions and includes statements aboutfuture outcomes, including but not limited to: the Corporation’s 2021 guidance, including full year 2021production, non-energy operating costs, general and administrative costs, capital expenditures and totaltransportation costs; the Corporation’s intention to continue debt reduction as a key component of its capitalallocationstrategy;theCorporation’sactionstakentoensurethehealthandsafetyofitspersonnelandbusinesspartnersandthesafeandreliableoperationoftheChristinaLakefacility;theCorporation’sclimate-relatedgoals,includingachievingnetzerocarbonemissionsby2050andreachinga30%reduction inbitumenGHGemissionsintensity (Scope1 and Scope2) from2013 levels by 2030; theOilsands Pathways toNet ZeroAllianceworkingcollectivelywiththefederalandAlbertagovernmentstoachievenetzeroGHGemissionsfromoilsandsoperationsby2050;theCorporation'sexpectationregardingtheChristinaLakecentralplantfacility'soilprocessingcapacityofapproximately 100,000 barrels per day and the amount of capital investment and the timing of such capitalinvestmentrequiredtoallowtheCorporationtofullyutilizethiscapacity;futureproduction,revenues,expenses,cashflow,operatingcosts,steam-oil ratios,pricingdifferentials, reliability,profitabilityandcapitalexpenditures;actions taken to respond to the impactof reduceduseof fossil fuelsandaddressing risksarisingoutof climatechange concerns; commodity prices; estimates of reserves and resources; anticipated sources of funding for

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operations and capital expenditures; the Corporation’s liquidity and ability to meet its current and futureobligations; and the Corporation’s hedge book. Such forward-looking information is based on management'sexpectationsandassumptionsregardingfuturegrowth,resultsofoperations,production,futurecapitalandotherexpenditures,competitiveadvantage,plansforandresultsofdrillingactivity,environmentalmatters,andbusinessprospectsandopportunities.

Forward-lookinginformationcontainedinthisdocumentisbasedonmanagement'sexpectationsandassumptionsregarding, among other things: future crude oil, bitumen blend, natural gas, electricity, condensate and otherdiluent prices, differentials, the level of apportionment on the Enbridgemainline system, transportation costs,foreign exchange rates and interest rates; the recoverability of the Corporation's reserves and contingentresources;theCorporation'sabilitytoproduceandmarketproductionofbitumenblendsuccessfullytocustomers;future growth, results of operations and production levels; future capital and other expenditures; revenues,expenses and cash flow; operating costs; reliability; anticipated sources of funding for operations and capitalinvestments;plansforandresultsofdrillingactivity;theregulatoryframeworkgoverningroyalties,landuse,taxesandenvironmentalmatters,includingthetimingandlevelofgovernmentproductioncurtailmentandfederalandprovincialclimatechangepolicies,inwhichtheCorporationconductsandwillconductitsbusiness;theimpactoftheCorporation’sresponsetotheCOVID-19globalpandemic,includingvaccinerollouts;actionstakenbyOPEC+inrelation to supplymanagement; and business prospects and opportunities. By its nature, such forward-lookinginformation involvessignificantknownandunknownrisksanduncertainties,whichcouldcauseactual results todiffermateriallyfromthoseanticipated.

These risks and uncertainties include, but are not limited to, risks and uncertainties related to: the oil and gasindustry, for example, the securing of adequate access tomarkets and transportation infrastructure (includingpipelinesandrail)andthecommitmentstherein;theavailabilityofcapacityontheelectricitytransmissiongrid;theuncertaintyofreserveandresourceestimates;theuncertaintyofestimatesandprojectionsrelatingtoproduction,costsand revenues;health, safetyandenvironmental risks, includingpublichealthcrises, suchas theCOVID-19pandemic,andany relatedactions takenbygovernmentsandbusinesses; legislativeand regulatory changes to,amongst other things, tax, land use, royalty and environmental laws and production curtailment; the cost ofcompliancewithcurrentandfutureenvironmentallaws,includingclimatechangelaws;risksrelatingtoincreasedactivismandpublicoppositiontofossilfuelsandoilsands;assumptionsregardingandthevolatilityofcommodityprices, interestratesandforeignexchangerates;commodityprice, interestrateandforeignexchangerateswapcontractsand/orderivativefinancialinstrumentsthattheCorporationmayenterintofromtimetotimetomanageits riskrelatedtosuchpricesandrates; timingofcompletion,commissioning,andstart-up,of theCorporation’sturnarounds;theoperationalrisksanddelaysinthedevelopment,exploration,production,andthecapacitiesandperformanceassociatedwiththeCorporation'sprojects;theCorporation’sabilitytoreduceorincreaseproductiontodesired levels, includingwithoutnegative impacts to itsassets; theCorporation’sability to financesustainingcapital expenditures; the Corporation’s ability to maintain sufficient liquidity to sustain operations through aprolongedmarketdownturn; changes incredit ratingsapplicable to theCorporationoranyof its securities; theCorporation’s response to theCOVID-19globalpandemic; theseverityanddurationof theCOVID-19pandemic;thepotentialforatemporarysuspensionofoperationsimpactedbyanoutbreakofCOVID-19;theavailabilityandcostof labourandgoodsandservices required in theCorporation’soperations, including inflationarypressures;supply chain issues including transportation delays; the cost and availability of equipment necessary to ouroperations;andchangesingeneraleconomic,marketandbusinessconditions.

AlthoughtheCorporationbelievesthattheassumptionsusedinsuchforward-lookinginformationarereasonable,therecanbenoassurancethatsuchassumptionswillbecorrect.Accordingly,readersarecautionedthattheactualresultsachievedmayvaryfromtheforward-looking informationprovidedhereinandthatthevariationsmaybematerial.Readersarealsocautionedthattheforegoinglistofassumptions,risksandfactorsisnotexhaustive.

Furtherinformationregardingtheassumptionsandrisksinherentinthemakingofforward-lookingstatementscanbe found in the Corporation's most recently filed AIF, along with the Corporation's other public disclosuredocuments.CopiesoftheAIFandtheCorporation'sotherpublicdisclosuredocumentsareavailablethroughtheSEDARwebsiteatwww.sedar.com.

The forward-looking information included in thisdocument isexpresslyqualified in itsentiretyby the foregoingcautionary statements. Unless otherwise stated, the forward-looking information included in this document ismadeasofthedateofthisdocumentandtheCorporationassumesnoobligationtoupdateorreviseanyforward-lookinginformationtoreflectneweventsorcircumstances,exceptasrequiredbylaw.

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MEGEnergy Corp. is an energy company focused on sustainable in situ thermal oil production in the southernAthabascaoilregionofAlberta,Canada.TheCorporationisactivelydevelopinginnovativeenhancedoilrecoveryprojectsthatutilizeSAGDextractionmethodstoimprovetheresponsibleeconomicrecoveryofoilaswellaslowercarbon emissions. MEG transports and sells its thermal oil (known as AWB) to customers throughout NorthAmericaandinternationally.TheCorporation'scommonsharesarelistedontheTorontoStockExchangeunderthesymbol"MEG".

EstimatesofReservesandResources

For informationregarding theCorporation'sestimatedreservesandresources,please refer to theCorporation'smostrecentlyfiledAIF.

Non-GAAPFinancialMeasures

CertainfinancialmeasuresinthisMD&AdonothaveastandardizedmeaningasprescribedbyIFRS.Cashoperatingnetbackisanon-GAAPfinancialmeasure.ItstermsarenotdefinedbyIFRSand,therefore,maynotbecomparabletosimilarmeasuresprovidedbyothercompanies.Thisnon-GAAPfinancialmeasureshouldnotbeconsideredinisolation or as an alternative for measures of performance prepared in accordance with IFRS. This measure ispresented and described in order to provide shareholders and potential investors with additional measures inunderstanding the Corporation's ability to generate funds and to finance its operations as well as profitabilitymeasures specific to the oil industry. The definition of this non-GAAPmeasure is presented in the “NON-GAAPMEASURES”sectionofthisMD&A.

20. ADDITIONALINFORMATION

Additional information relating to theCorporation, including itsAIF, isavailableon theCorporation'swebsiteatwww.megenergy.comandisalsoavailableonSEDARatwww.sedar.com.

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21. QUARTERLYSUMMARIES

2021 2020 2019

Unaudited Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4

FINANCIAL($millionsunlessspecified)

Netearnings(loss) 54 68 (17) 16 (9) (80) (284) 26

Pershare,diluted 0.17 0.22 (0.06) 0.05 (0.03) (0.26) (0.95) 0.09

Adjustedfundsflow 239 166 127 84 26 89 76 156

Pershare,diluted 0.77 0.53 0.41 0.27 0.09 0.29 0.25 0.51

Capitalexpenditures 84 70 70 40 36 20 54 72

Cashandcashequivalents 210 159 54 114 49 120 62 206

Workingcapital 199 127 8 55 131 173 371 123

Long-termdebt 2,769 2,820 2,852 2,912 3,030 3,096 3,212 3,123

Shareholders'equity 3,628 3,564 3,491 3,506 3,495 3,507 3,593 3,853

BUSINESSENVIRONMENT

AverageBenchmarkCommodityPrices:

WTI(US$/bbl) 70.56 66.07 57.84 42.66 40.93 27.85 46.17 56.96

Differential–WTI:WCS–Edmonton(US$/bbl) (13.58) (11.49) (12.47) (9.30) (9.09) (11.47) (20.53) (15.83)

Differential–WTI:AWB–Edmonton(US$/bbl) (15.13) (13.11) (14.22) (10.56) (10.48) (13.44) (22.78) (18.44)

AWB–Edmonton(US$/bbl) 55.43 52.96 43.62 32.10 30.45 14.41 23.39 38.52

Differential–WTI:AWB–U.S.GulfCoast(US$/bbl) (5.57) (3.92) (2.52) (2.83) (3.20) (7.29) (5.74) (5.25)

AWB–U.S.GulfCoast(US$/bbl) 64.99 62.15 55.32 39.83 37.73 20.56 40.43 51.71

C$equivalentof1US$–average 1.2602 1.2280 1.2663 1.3031 1.3316 1.3860 1.3445 1.3201

Naturalgas–AECO($/mcf) 3.92 3.37 3.43 2.88 2.48 2.21 2.26 2.70

OPERATIONAL($/bblunlessspecified)

Blendsales,netofpurchasedproduct–bbls/d 127,546 129,474 128,236 136,623 93,479 100,980 142,380 134,932

Diluentusage–bbls/d (35,295) (39,494) (40,938) (40,892) (25,910) (30,583) (45,166) (40,585)

Bitumensales–bbls/d 92,251 89,980 87,298 95,731 67,569 70,397 97,214 94,347

Bitumenproduction–bbls/d 91,506 91,803 90,842 91,030 71,516 75,687 91,557 94,566

Steam-oilratio(SOR) 2.56 2.39 2.37 2.31 2.36 2.32 2.31 2.27

Blendsales 74.54 69.27 61.28 45.75 45.44 20.96 36.46 56.55

Costofdiluent (9.63) (9.18) (8.94) (7.11) (5.76) (10.78) (17.01) (9.69)

Bitumenrealization 64.91 60.09 52.34 38.64 39.68 10.18 19.45 46.86

Transportationandstorage–net (10.03) (10.91) (11.41) (14.11) (18.55) (11.77) (8.63) (10.75)

Third-partycurtailmentcredits — — — 0.03 — — 0.18 (0.21)

Royalties (2.67) (1.71) (0.85) (0.23) (0.21) (0.05) (0.63) (1.18)

Non-energyoperatingcosts (4.46) (3.84) (4.05) (4.70) (3.96) (4.09) (4.57) (4.49)

Energyoperatingcosts (4.77) (4.27) (4.34) (3.73) (3.17) (3.00) (3.15) (2.95)

Powerrevenue 2.06 2.57 3.14 1.45 1.08 0.95 2.21 1.57

Realizedgain(loss)oncommodityriskmanagement (7.73) (10.63) (8.80) 1.31 1.71 33.62 11.97 (0.52)

Cashoperatingnetback 37.31 31.30 26.03 18.66 16.58 25.84 16.83 28.33

Powersalesprice(C$/MWh) 82.17 88.40 93.27 46.34 39.03 28.34 69.39 49.61

Powersales(MW/h) 101 113 128 125 78 98 129 124

Averagecostofdiluent($/bblofdiluent) 99.69 90.18 80.34 62.37 60.48 45.76 73.09 79.07

Averagecostofdiluentasa%ofWTI 112% 111% 110% 112% 111% 119% 118% 105%

Depletionanddepreciationrateperbblofproduction 12.78 12.99 13.15 12.64 13.33 13.55 14.83 13.18

Generalandadministrativeexpenseperbblofproduction 1.72 1.56 1.77 1.65 1.50 1.29 1.96 2.25

COMMONSHARES

Sharesoutstanding,endofperiod(000) 306,773 306,716 303,137 302,681 302,657 302,645 299,547 299,508

Commonshareprice($)-close(endofperiod) 9.89 8.97 6.53 4.45 2.77 3.77 1.67 7.39

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During the eight most recent quarters the following items have had a significant impact on the Corporation’squarterlyresults:

• fluctuationsinblendsalespricingduetosignificantchangesinthepriceofWTIwithperiodsofsignificantvolatility in2020,whichhasrangedfromaquarterlyaverageofUS$27.85/bbltoUS$70.56/bbl,andthedifferential betweenWTI and theCorporation'sAWBat Edmonton,whichhas ranged fromaquarterlyaverageofUS$10.48/bbltoUS$22.78/bbldrivenbysupply/demandfundamentals;

• beginninginearlyMarch2020,followedbyaslowrecoverythroughthesecondhalfof2020andfirsthalfof2021,andcontinueduncertainty,globalcrudeoilpricesexperiencedmulti-decadelowscoupledwithextreme levels of volatility driven primarily by an unprecedented reduction in global demand due toCOVID-19;

• thecostofdiluentduetochangesinCanadianandU.S.benchmarkpricing,thetimingofdiluentinventorypurchasesandtheimpactofforeignexchange;

• changesinthevalueoftheCanadiandollarrelativetotheU.S.dollaranditsimpactonblendsalesprices,the cost of diluent, interest expense, and foreign exchange gains and losses associated with theCorporation'sU.S.dollardenominateddebt;

• timingofcapitalprojects;

• costreductionefforts;

• apportionmentandtheabilitytoreachUSGCmarkets;

• fluctuationsinnaturalgasandpowerpricing;

• gainsandlossesoncommodityriskmanagementcontracts;

• AlbertaGovernmentenactedcurtailmentrules;

• changes in depletion and depreciation expense as a result of changes in production rates, futuredevelopmentcostsanduncertaintyoffuturebenefitsassociatedwithspecificnon-coreassets;

• explorationexpenseassociatedwithdiscontinuedexplorationandevaluationactivitiesincertainnon-coregrowthproperties;

• changes in the Corporation's share price and the implementation of financial equity price riskmanagementcontracts,andtheresultingimpactonstock-basedcompensation;

• plannedturnaroundandothermaintenanceactivitiesaffectingproduction;and

• voluntarycurtailmenteffortsassociatedwithuneconomicbenchmarkpricingenvironments.

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22. ANNUALSUMMARIES

2020 2019 2018(1) 2017(1) 2016(1) 2015(1) 2014(1)

FINANCIAL($millionsunlessspecified)

Netearnings(loss) (357) (62) (119) 166 (429) (1,170) (106)

Pershare,diluted (1.18) (0.21) (0.40) 0.57 (1.90) (5.21) (0.47)

Adjustedfundsflow 275 724 175 371 (63) 49 790

Pershare,diluted 0.90 2.41 0.58 1.28 (0.28) 0.22 3.51

Capitalexpenditures 149 198 622 502 140 314 1,314

Cashandcashequivalents 114 206 318 464 156 408 656

Workingcapital 55 123 290 313 96 363 526

Long-termdebt 2,912 3,123 3,740 4,668 5,053 5,190 4,350

Shareholders'equity 3,506 3,853 3,886 3,964 3,287 3,678 4,768

BUSINESSENVIRONMENT

AverageBenchmarkCommodityPrices:

WTI(US$/bbl) 39.40 57.03 64.77 50.95 43.33 48.80 93.00

Differential–WTI:WCS–Edmonton(US$/bbl) (12.60) (12.76) (26.31) (11.98) (13.84) (13.52) (19.40)

Differential–WTI:AWB–Edmonton(US$/bbl) (14.32) (14.95) (29.99) (14.09) (16.40) (16.69) (23.58)

AWB–Edmonton(US$/bbl) 25.08 42.08 34.78 36.86 26.93 32.11 69.42

Differential–WTI:AWB–U.S.GulfCoast(US$/bbl) (4.77) (1.77) (6.68) (7.61) (11.53) (8.53) (10.08)

AWB-U.S.GulfCoast(US$/bbl) 34.63 55.26 58.09 43.34 31.80 40.27 82.92

C$equivalentof1US$–average 1.3413 1.3269 1.2962 1.2980 1.3256 1.2788 1.1047

Naturalgas–AECO($/mcf) 2.43 1.92 1.62 2.29 2.25 2.71 4.50

OPERATIONAL($/bblunlessspecified)

Blendsales,netofpurchasedproduct–bbls/d 118,347 134,223 125,368 115,766 116,586 117,132 97,334

Diluentusage–bbls/d (35,626) (40,637) (38,317) (35,766) (36,159) (36,167) (30,092)

Bitumensales–bbls/d 82,721 93,586 87,051 80,000 80,427 80,965 67,242

Bitumenproduction–bbls/d 82,441 93,082 87,731 80,774 81,245 80,025 71,186

Steam-oilratio(SOR) 2.32 2.22 2.19 2.31 2.29 2.47 2.48

Blendsales 37.65 61.29 53.47 51.39 38.19 42.14 76.11

Costofdiluent (10.42) (8.08) (16.78) (9.36) (10.28) (11.43) (13.35)

Bitumenrealization 27.23 53.21 36.69 42.03 27.91 30.71 62.76

Transportationandstorage–net (12.92) (10.84) (8.42) (6.89) (6.46) (4.82) (1.38)

Third-partycurtailmentcredits 0.06 (0.37) — — — — —

Royalties (0.31) (1.30) (1.20) (0.77) (0.29) (0.70) (4.36)

Non-energyoperatingcosts (4.38) (4.61) (4.62) (4.62) (5.62) (6.54) (8.02)

Energyoperatingcosts (3.29) (2.38) (1.98) (2.98) (3.01) (3.84) (6.30)

Powerrevenue 1.49 1.75 1.51 0.76 0.64 0.99 2.26

Realizedgain(loss)oncommodityriskmanagement 11.34 (3.31) (4.37) (0.39) 0.08 — —

Cashoperatingnetback 19.22 32.15 17.61 27.14 13.25 15.80 44.96

Powersalesprice(C$/MWh) 47.81 56.70 47.87 21.49 18.74 27.48 48.83

Powersales(MW/h) 108 121 114 118 115 121 129

Averagecostofdiluent($/bblofdiluent) 61.86 79.89 91.60 72.32 61.06 67.72 105.94

Averagecostofdiluentasa%ofWTI 117% 106% 109% 109% 106% 109% 103%Depletionanddepreciationrateperbblofproduction 13.60 20.90 14.12 16.13 16.81 16.00 14.57Generalandadministrativeexpenseperbblofproduction 1.62 1.99 2.58 2.94 3.24 4.06 4.29

COMMONSHARES

Sharesoutstanding,endofperiod(000) 302,681 299,508 296,841 294,104 226,467 224,997 223,847

Commonshareprice($)-close(endofperiod) 4.45 7.39 7.71 5.14 9.23 8.02 19.55

(1) TheCorporationadoptedIFRS16Leases,effectiveJanuary1,2019,thereforepriorperiodshavenotbeenrestated.

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ConsolidatedBalanceSheet(Unaudited,expressedinmillionsofCanadiandollars)

Asat Note September30,2021 December31,2020AssetsCurrentassetsCashandcashequivalents 16 $ 210 $ 114Tradereceivablesandother 400 281Inventories 146 96Riskmanagement 18 27 6

783 497Non-currentassetsProperty,plantandequipment 3 5,869 5,993Explorationandevaluationassets 4 125 125Otherassets 5 196 206Riskmanagement 18 34 21Deferredincometaxasset 345 382

Totalassets $ 7,352 $ 7,224

LiabilitiesCurrentliabilitiesAccountspayableandaccruedliabilities $ 437 $ 279Interestpayable 34 78Currentportionofprovisionsandotherliabilities 7 38 56Riskmanagement 18 75 29

584 442Non-currentliabilitiesLong-termdebt 6 2,769 2,912Provisionsandotherliabilities 7 371 364

Totalliabilities 3,724 3,718

Shareholders’equitySharecapital 8 5,485 5,460Contributedsurplus 169 177Deficit (2,053) (2,158)Accumulatedothercomprehensiveincome 27 27

Totalshareholders’equity 3,628 3,506Totalliabilitiesandshareholders’equity $ 7,352 $ 7,224

Commitmentsandcontingencies(Note20)

TheaccompanyingnotesareanintegralpartoftheseInterimConsolidatedFinancialStatements.

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ConsolidatedStatementofEarnings(Loss)andComprehensiveIncome(Loss)(Unaudited,expressedinmillionsofCanadiandollars,exceptpershareamounts)



Note 2021 2020 2021 2020

Revenues

Petroleumrevenue,netofroyalties 10 $ 1,070 $ 523 $ 2,942 $ 1,464

Otherrevenue 10 21 10 72 41

Totalrevenues 1,091 533 3,014 1,505

Expenses

Diluentandtransportation 11 412 263 1,216 848

Operatingexpenses 78 44 211 158

Inventoryimpairment 5 — — 5 —

Purchasedproduct 218 134 587 416

Curtailment — — — (2)

Depletionanddepreciation 3,5 108 87 324 304

Explorationexpense — — — 366

Generalandadministrative 14 10 41 35

Stock-basedcompensation 9 10 10 16 (12)

Netfinanceexpense 13 62 67 195 206

Otherexpenses 14 21 11 21 41

Otherincome — — (4) (6)

Commodityriskmanagement(gain)loss,net 18 (2) 6 269 (476)

Foreignexchange(gain)loss,net 12 77 (70) (7) 84

Earnings(loss)beforeincometaxes 93 (29) 140 (457)

Incometaxexpense(recovery) 15 39 (20) 35 (84)

Netearnings(loss) 54 (9) 105 (373)

Othercomprehensiveincome(loss),netoftax

Itemsthatmaybereclassifiedtoprofitorloss:

Foreigncurrencytranslationadjustment 5 (4) — 6

Comprehensiveincome(loss) $ 59 $ (13)$ 105 $ (367)

Netearnings(loss)percommonshare

Basic 17 $ 0.17 $ (0.03)$ 0.34 $ (1.24)

Diluted 17 $ 0.17 $ (0.03)$ 0.34 $ (1.24)


40

ConsolidatedStatementofChangesinShareholders’Equity(Unaudited,expressedinmillionsofCanadiandollars)

ShareCapital

ContributedSurplus Deficit

AccumulatedOther

ComprehensiveIncome

TotalShareholders’

EquityBalanceasatDecember31,2020 $ 5,460 $ 177 $ (2,158) $ 27 $ 3,506Stock-basedcompensation — 13 — — 13Stockoptionsexercised 6 (2) — — 4RSUvestedandreleased 19 (19) — — —Comprehensiveincome(loss) — — 105 — 105BalanceasatSeptember30,2021 $ 5,485 $ 169 $ (2,053) $ 27 $ 3,628

BalanceasatDecember31,2019 $ 5,443 $ 182 $ (1,801) $ 29 $ 3,853Stock-basedcompensation — 9 — — 9RSUsvestedandreleased 17 (17) — — —Comprehensiveincome(loss) — — (373) 6 (367)BalanceasatSeptember30,2020 $ 5,460 $ 174 $ (2,174) $ 35 $ 3,495


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ConsolidatedStatementofCashFlow(Unaudited,expressedinmillionsofCanadiandollars)



Note 2021 2020 2021 2020

Cashprovidedby(usedin):

Operatingactivities

Netearnings(loss) $ 54 $ (9)$ 105 $ (373)

Adjustmentsfor:

Deferredincometaxexpense(recovery) 15 39 (20) 37 (83)

InventoryImpairment 5 — — 5 —

Depletionanddepreciation 3,5 108 87 324 304

Explorationexpense — — — 366

Stock-basedcompensation 9 (3) 11 (24) (2)

Unrealizednet(gain)lossonforeignexchange 12 78 (70) (6) 83Unrealizednet(gain)lossoncommodityriskmanagement 18 (68) 17 47 (144)Amortizationofdebtdiscountanddebtissuecosts 6 2 2 6 6

Gainonassetdispositions 3,5 — — (4) (6)

Debtextinguishmentexpense 13 — — 5 —

Other 3 3 6 7

Decommissioningexpenditures 7 (1) (1) (3) (3)

Paymentsononerouscontracts 7 (6) — (18) —

Netchangeinotherliabilities 6 (1) 13 3Fundsflowfromoperatingactivities 212 19 493 158

Netchangeinnon-cashworkingcapitalitems 16 45 (50) (44) 28

Netcashprovidedby(usedin)operatingactivities 257 (31) 449 186

Investingactivities

Capitalexpenditures 3 (84) (35) (225) (109)

Netproceedsondispositions 3 — — 44 6

Netchangeinnon-cashworkingcapitalitems 16 15 (1) (10) (42)

Netcashprovidedby(usedin)investingactivities (69) (36) (191) (145)

Financingactivities

Issuanceofseniorunsecurednotes 6 — — 769 1,581

Repaymentandredemptionoflong-termdebt 6 (126) — (889) (1,723)

Debtredemptionpremiumandrefinancingcosts 6 (4) — (23) (49)

Issueofshares,netofissuecosts — — 4 —

Receiptsonleasedassets 16 1 — 2 1

Paymentsonleasedliabilities 16 (7) (6) (21) (19)

Netcashprovidedby(usedin)financingactivities (136) (6) (158) (209)

Effectofexchangeratechangesoncashandcashequivalentsheldinforeigncurrency (1) 2 (4) 11

Changeincashandcashequivalents 51 (71) 96 (157)

Cashandcashequivalents,beginningofperiod 159 120 114 206

Cashandcashequivalents,endofperiod $ 210 $ 49 $ 210 $ 49

TheaccompanyingnotesareanintegralpartoftheseConsolidatedFinancialStatements.

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1. CORPORATEINFORMATION

MEGEnergyCorp.(the"Corporation")wasincorporatedundertheAlbertaBusinessCorporationsActonMarch9,1999.TheCorporation'ssharestradeontheTorontoStockExchangeunderthesymbol"MEG".TheCorporationownsa100%interestinover400squaremilesofmineralleasesinthesouthernAthabascaoilregionofAlberta,CanadaandisprimarilyengagedinsustainableinsituthermaloilproductionatitsChristinaLakeProject.

Thecorporateofficeislocatedat600–3rdAvenueSW,Calgary,Alberta,Canada.

2. BASISOFPRESENTATION

The unaudited interim consolidated financial statements ("interim consolidated financial statements") werepreparedusingthesameaccountingpoliciesandmethodsasthoseusedintheCorporation'sauditedconsolidatedfinancialstatementsfortheyearendedDecember31,2020.TheinterimconsolidatedfinancialstatementsareincompliancewithInternationalAccountingStandard34,InterimFinancialReporting("IAS34").Accordingly,certaininformationandfootnotedisclosurenormallyincludedinannualfinancialstatementspreparedinaccordancewithInternational Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board("IASB"), has been omitted or condensed. The preparation of interim consolidated financial statements inaccordancewith IAS34requirestheuseofcertaincriticalaccountingestimates. Italsorequiresmanagementtoexercise judgment in applying the Corporation's accounting policies. The areas involving a higher degree ofjudgmentor complexity,orareaswhereassumptionsandestimatesare significant to theconsolidated financialstatements,havebeen setout inNote4of theCorporation's audited consolidated financial statements for theyear endedDecember 31, 2020. These interim consolidated financial statements should be read in conjunctionwiththeCorporation'sauditedconsolidatedfinancialstatementsfortheyearendedDecember31,2020.

InMarch 2020, theWorld HealthOrganization declared a global pandemic following the emergence and rapidspreadofanovelstrainofcoronavirus("COVID-19").COVID-19continuestoimpactworldwidedemandforcrudeoilandthereforeglobalcommoditymarkets.PricevolatilityremainslargelyduetomarketsensitivitytoCOVID-19relatednewsincludingvaccinebreakthroughsandrollouts,andtheresurgenceofCOVID-19casesanddevelopingvariantsofconcern.Commoditypriceshaveimprovedin2021inlinewithincreaseddemand,optimismrelatingtovaccinerolloutsandOPEC+supplymanagement.

Thecontinuedimpactoncapitalandfinancialmarketsonamacro-scalepresentuncertaintyandriskwithrespecttotheCorporation'sperformance,andestimatesandassumptionsusedinthepreparationofitsfinancialresults.

These interim consolidated financial statements are presented in Canadian dollars ($ or C$), which is theCorporation'sfunctionalcurrencyandwereapprovedbytheCorporation'sAuditCommitteeonNovember8,2021.

NOTESTOTHEINTERIMCONSOLIDATEDFINANCIALSTATEMENTSPeriodendedSeptember30,2021AllamountsareexpressedinmillionsofCanadiandollarsunlessotherwisenoted.(Unaudited)

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3. PROPERTY,PLANTANDEQUIPMENT

CrudeoilTransportation

andstorageRight-of-use

assetsCorporate

assets TotalCostBalanceasatDecember31,2020 $ 9,245 $ 88 $ 296 $ 78 $ 9,707Additions 225 — 8 — 233Dispositions — (39) — — (39)Changeindecommissioningliabilities 7 (2) — — 5BalanceasatSeptember30,2021 $ 9,477 $ 47 $ 304 $ 78 $ 9,906

Accumulateddepletionanddepreciation

BalanceasatDecember31,2020 $ 3,580 $ 32 $ 53 $ 49 $ 3,714Depletionanddepreciation 299 — 20 4 323BalanceasatSeptember30,2021 $ 3,879 $ 32 $ 73 $ 53 $ 4,037

CarryingamountsBalanceasatDecember31,2020 $ 5,665 $ 56 $ 243 $ 29 $ 5,993BalanceasatSeptember30,2021 $ 5,598 $ 15 $ 231 $ 25 $ 5,869

AsatSeptember30,2021,property,plantandequipmentwasassessedfor impairmentandno impairmentwasrecognized. There were no assets under construction as at September 30, 2021 (assets under construction atDecember31,2020–$244million).

During the ninemonths ended September 30, 2021, the Corporation completed the sale of non-core industriallands near Edmonton for cash proceeds of approximately $44 million, and a gain on sale of $4 million wasrecognized.

4. EXPLORATIONANDEVALUATIONASSETS

AsatSeptember30,2021,explorationandevaluationassetsconsistof$125millioninexplorationprojectswhicharependingthedeterminationofprovedorprobablereserves.Theseassetswereassessedforimpairmentandnoimpairmenthasbeenrecognizedonexplorationandevaluationassets.

5. OTHERASSETS

Asat September30,2021 December31,2020

Non-currentpipelinelinefill(a) $ 170 $ 176

Financesubleasereceivables 15 17

Intangibleassets(b) 6 7

Deferredfinancingcosts — 3

Prepaidtransportationcosts(c) 8 8

199 211

Lesscurrentportion,includedintradereceivablesandother (3) (5)

$ 196 $ 206

a. Non-current pipeline linefill on third-party owned pipelines is classified as a non-current asset as thesetransportationcontractsexpirebetweentheyears2025and2048.DuringtheninemonthsendedSeptember30,2021,animpairmentof$5millionwasrecognizedonlong-termlinefill.

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b. As at September 30, 2021, intangible assets consist of software that is not an integral component of therelatedcomputerhardware.Depreciationof$1millionwasrecognizedfortheninemonthsendedSeptember30, 2021 (year ended December 31, 2020 – $2 million). In 2020, the Corporation sold patents that wererecordedatanominalamount,andrecognizedagainonassetdispositionof$6million.

c. Prepaid transportation costs related to upgrading third-party transportation infrastructure have beencapitalizedandarebeingamortizedtotransportationexpenseoverthe30-yeartermoftheagreement.

6. LONG-TERMDEBT


SecondLien:

6.5%seniorsecuredsecondliennotes(Sept30,2021-US$396million;due2025;December31,2020-US$496million) $ 505 $ 633

Unsecured:

7.125%seniorunsecurednotes(Sept30,2021-US$1.2billion;due2027;December31,2020-US$1.2billion) 1,530 1,531

5.875%seniorunsecurednotes(Sept30,2021-US$600million;due2029;December31,2020-US$nil) 765 —

7.0%seniorunsecurednotes(Sept30,2021-US$nil;December31,2020-US$600million;due2024) — 765

2,800 2,929

Debtredemptionpremium — 9

Unamortizeddeferreddebtdiscountanddebtissuecosts (31) (26)

$ 2,769 $ 2,912

TheU.S.dollardenominateddebtwastranslatedintoCanadiandollarsattheperiodendexchangerateofUS$1=C$1.2750(December31,2020–US$1=C$1.2755).


On February 2, 2021, the Corporation successfully closed on a private offering of US$600million in aggregateprincipalamountof5.875%seniorunsecurednotesdueFebruary2029.Thenetproceedsoftheoffering,togetherwithcash-on-hand,wereused to fully redeemUS$600million inaggregateprincipalamountof its7.00%seniorunsecurednotesdueMarch2024ataredemptionpriceof101.167%andtopayfeesandexpensesrelatedtotheoffer. The redemption included a prepayment option, recognized as at December 31, 2020, whereby theCorporationwasrequiredtomakeanestimateatthereportingdateofthe likelihoodoftheprepaymentoptionbeingexercised.

AsatSeptember30,2021,theCorporationhad$788millionofunutilizedcapacityunderthe$800millionrevolvingcredit facility and the Corporation had $85million of unutilized capacity under the $500million EDC Facility. Aletterofcreditof$15millionwasissuedundertherevolvingcreditfacilityduringthefirstquarterof2020and$12millionremainsoutstandingasatSeptember30,2021.

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7. PROVISIONSANDOTHERLIABILITIES


Leaseliabilities(a) $ 273 $ 286

Decommissioningprovision(b) 103 96

Onerouscontractprovision(c) 7 25

Long-termincentivecompensationliability(d) 26 13

Provisionsandotherliabilities 409 420

Lesscurrentportion (38) (56)

Non-currentportion $ 371 $ 364

a. Leaseliabilities:


Balance,beginningofperiod $ 286 $ 281

Additions 9 19

Modifications — 7

Payments (41) (47)

Interestexpense 19 26

Balance,endofperiod 273 286



TheCorporation'sminimumleasepaymentsareasfollows:

AsatSeptember30 2021

Withinoneyear $ 49

Laterthanoneyearbutnotlaterthanfiveyears 143

Laterthanfiveyears 476

Minimumleasepayments 668

Amountsrepresentingfinancecharges (395)

Netminimumleasepayments $ 273

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b. Decommissioningprovision:

The following table presents the decommissioning provision associated with the reclamation andabandonmentoftheCorporation’sproperty,plantandequipmentandexplorationandevaluationassets:


Balance,beginningofperiod $ 96 $ 71

Changesinestimatedlifeandestimatedfuturecashflows 1 4

Changesindiscountrates 3 16

Liabilitiessettled (3) (3)

Accretion 6 8

Balance,endofperiod 103 96



ThedecommissioningprovisionrepresentsthepresentvalueoftheestimatedfuturecostsforthereclamationandabandonmentoftheCorporation'sproperty,plantandequipmentandexplorationandevaluationassets.Thetotalundiscountedamountoftheestimatedfuturecashflowstosettlethedecommissioningobligationsis$796million(December31,2020–$802million).AsatSeptember30,2021,theCorporationhasestimatedthenetpresentvalueofthedecommissioningobligationsusingaweightedaveragecredit-adjustedrisk-freerateof11.3% (December31,2020–11.7%)andan inflation rateof2.1% (December31,2020 -2.1%).Thedecommissioningprovision isestimated tobe settled inperiodsup to theyear2066 (December31,2020 -periodsuptotheyear2066).

c. Onerouscontractprovision:

TheprovisionrepresentsthepresentvalueoftheminimumfuturepaymentsthattheCorporationisobligatedtomake under the non-cancelable onerous contract. There is no impact from discounting as the onerouscontractwillbesettledbyDecember31,2021.LiabilitiessettledduringtheninemonthsendedSeptember30,2021were$18million.

d. Long-termincentivecompensationliability:

As at September30, 2021, theCorporation recognizeda liabilityof $61million relating to the fair valueofcash-settledRSUs,PSUsandDSUs (December31,2020–$23million).Thecurrentportionof$35million isincludedwithinaccountspayableandaccrued liabilitiesand$26million is includedasanon-current liabilitywithinprovisionsandotherliabilitiesbasedontheexpectedpayoutdatesoftheindividualawards.

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8. SHARECAPITAL

TheCorporationisauthorizedtoissueanunlimitednumberofcommonshareswithoutnominalorparvalueandanunlimitednumberofpreferredshares.

Changesinissuedcommonsharesareasfollows:

NinemonthsendedSeptember30,2021

YearendedDecember31,2020

Numberofshares

(thousands) Amount

Numberofshares

(thousands) Amount

Balance,beginningofyear 302,681 $ 5,460 299,508 $ 5,443

Issueduponexerciseofstockoptions 847 6 39 —

IssueduponvestingandreleaseofRSUsandPSUs 3,245 19 3,134 17

Balance,endofperiod 306,773 $ 5,485 302,681 $ 5,460

9. STOCK-BASEDCOMPENSATION



2021 2020 2021 2020

Cash-settledexpense(recovery)(i) $ 13 $ (1)$ 48 $ (10)

Equity-settledexpense 4 2 12 9

Equitypriceriskmanagement(gain)loss(ii) (7) 9 (44) (11)

Stock-basedcompensation $ 10 $ 10 $ 16 $ (12)

(i) Cash-settledRSUsandPSUsareaccountedforasliabilityinstrumentsandaremeasuredatfairvaluebasedonthemarketvalueoftheCorporation’scommonsharesateachperiodendandcertainestimatesincludingaperformancemultiplierforPSUs.Fluctuationsinthefairvaluearerecognizedduringtheperiodinwhichtheyoccur.

(ii) RelatestofinancialderivativesenteredintotomanagetheCorporation'sexposuretocash-settledRSUsandPSUsvestingin2021,2022and2023grantedundertheCorporation'sstock-basedcompensationplans.Amountsareunrealizeduntilvestingoftherelatedunitsoccurs.Seenote18(d)forfurtherdetails.

A$48millioncash-settledexpensewasrecognizedduringtheninemonthsendedSeptember30,2021duetotheincrease in theCorporation's shareprice, andassociated increase invalueof cash-settledRSUs,PSUsandDSUscomparedtoDecember31,2020,whichtranslated intoan increased liabilityatSeptember30,2021,andhigherexpensefortheninemonthsendedSeptember30,2021comparedtothepriorperiod.AsatSeptember30,2021,theCorporationrecognizedaliabilityof$61millionrelatingtothefairvalueofcash-settledRSUs,PSUsandDSUs(December 31, 2020 – $23million). The current portionof $35million is includedwithin accounts payable andaccruedliabilitiesand$26millionisincludedasanon-currentliabilitywithinprovisionsandotherliabilitiesbasedontheexpectedpayoutdatesoftheindividualawards.

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10. REVENUES



2021 2020 2021 2020

Salesfrom:

Production $ 868 $ 385 $ 2,376 $ 1,035

Purchasedproduct(i) 225 140 610 437


Royalties (23) (2) (44) (8)

Petroleumrevenue,netofroyalties $ 1,070 $ 523 $ 2,942 $ 1,464

Powerrevenue $ 18 $ 6 $ 64 $ 32

Transportationrevenue 3 4 8 9

Otherrevenue $ 21 $ 10 $ 72 $ 41

Totalrevenues $ 1,091 $ 533 $ 3,014 $ 1,505

(i) The associated third-party purchases are included in the consolidated statement of earnings (loss) and comprehensiveincome(loss)underthecaption“Purchasedproduct”.

a. Disaggregationofrevenuefromcontractswithcustomers

TheCorporationrecognizesrevenueupondeliveryofgoodsandservicesinthefollowinggeographicregions:


2021 2020

PetroleumRevenue PetroleumRevenue

Proprietary Third-party Total Proprietary Third-party Total

Country:

Canada $ 503 $ 13 $ 516 $ 115 $ — $ 115

UnitedStates 365 212 577 270 140 410

$ 868 $ 225 $ 1,093 $ 385 $ 140 $ 525


2021 2020

PetroleumRevenue PetroleumRevenue

Proprietary Third-party Total Proprietary Third-party Total

Country:

Canada $ 1,305 $ 13 $ 1,318 $ 507 $ 34 $ 541

UnitedStates 1,071 597 1,668 528 403 931

$ 2,376 $ 610 $ 2,986 $ 1,035 $ 437 $ 1,472

OtherrevenuerecognizedduringthethreeandninemonthsendedSeptember30,2021and2020isattributedtoCanada.

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b. Revenue-relatedassets

TheCorporationhasrecognizedthefollowingrevenue-relatedassetsintradereceivablesandother:


Petroleumrevenue $ 369 $ 249

Otherrevenue 6 4

Totalrevenue-relatedassets $ 375 $ 253

Revenue-relatedreceivablesaretypicallysettledwithin30days.AsatSeptember30,2021andDecember31,2020,therewasnomaterialexpectedcreditlossrequiredagainstrevenue-relatedreceivables.

11. DILUENTANDTRANSPORTATION



2021 2020 2021 2020

Diluentexpense $ 324 $ 144 $ 944 $ 572

Transportationandstorage 88 119 272 276

Diluentandtransportation $ 412 $ 263 $ 1,216 $ 848

12. FOREIGNEXCHANGE(GAIN)LOSS,NET



2021 2020 2021 2020

Unrealizedforeignexchange(gain)losson:

Long-termdebt $ 77 $ (67)$ (9)$ 95

US$denominatedcashandcashequivalents 1 (3) 3 (12)

Unrealizednet(gain)lossonforeignexchange 78 (70) (6) 83

Realized(gain)lossonforeignexchange (1) — (1) 1

Foreignexchange(gain)loss,net $ 77 $ (70)$ (7)$ 84

C$equivalentof1US$

Beginningofperiod 1.2405 1.3616 1.2755 1.2965

Endofperiod 1.2750 1.3324 1.2750 1.3324

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13. NETFINANCEEXPENSE



2021 2020 2021 2020

Interestexpenseonlong-termdebt $ 55 $ 59 $ 166 $ 183

Interestexpenseonleaseliabilities 6 6 19 19

Interestincome (1) — (1) (2)

Netinterestexpense 60 65 184 200

Accretiononprovisions 2 2 6 6

Debtextinguishmentexpense — — 5 —

Netfinanceexpense $ 62 $ 67 $ 195 $ 206

FortheninemonthsendedSeptember30,2021,debtextinguishmentexpensewasrecognizedinassociationwiththe August 23, 2021 debt redemption and included a cumulative debt redemption premium of $4million andassociatedunamortizeddeferreddebtissuecostsof$1million.RefertoNote6forfurtherdetails.

14. OTHEREXPENSES



2021 2020 2021 2020

Settlementexpense(i) $ 21 $ — $ 21 $ —

Contractcancellation(ii) — 7 — 33

Severanceandrestructuring — 4 — 8

Otherexpenses $ 21 $ 11 $ 21 $ 41

(i) Duringthethirdquarterof2021, theCorporationreachedanagreementtosettle the litigationmattercommenced in2014relatingtolegacyissuesinvolvingaunittraintransloadingfacilityinAlberta.Undertheagreement,theCorporationpaid(subsequenttothequarter)thesumof$21millioninfullandfinalsettlementoftheclaimandtheclaimhasbeendiscontinued.

(ii) Costsincurredtomitigaterailsalescontractexposure.

15. INCOMETAXEXPENSE(RECOVERY)



2021 2020 2021 2020

Currentincometaxexpense(recovery) $ — $ — $ (2)$ (1)

Deferredincometaxexpense(recovery) 39 (20) 37 (83)

Incometaxexpense(recovery) $ 39 $ (20)$ 35 $ (84)

ForthethreeandninemonthsendedSeptember30,2021,anincometaxexpensewasrecognizedcomparedtoanincome tax recovery in the same periods of 2020 due to increased earnings before income taxes and foreignexchangegainsandlossesonlong-termdebt.Also,theCorporationrecognizeda$12milliondeferredtaxexpenseduringthesecondquarterof2021associatedwiththetaxtreatmentofaprioryearinvestmentinpipelineaccess.TheCorporationdisputesCanadaRevenueAgency'sassessmentandcontinuestoconsideritsalternatives.

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16. SUPPLEMENTALCASHFLOWDISCLOSURES



2021 2020 2021 2020

Cashprovidedby(usedin):

Tradereceivablesandother $ 56 $ 17 $ (119)$ 175

Inventories (12) (46) (48) (19)

Accountspayableandaccruedliabilities 66 33 161 (124)

Interestpayable (50) (55) (48) (46)

$ 60 $ (51)$ (54)$ (14)

Changesinnon-cashworkingcapitalrelatingto:

Operating $ 45 $ (50)$ (44)$ 28

Investing 15 (1) (10) (42)

$ 60 $ (51)$ (54)$ (14)

Cashandcashequivalents:(a)

Cash $ 210 $ 49 $ 210 $ 49

Cashequivalents — — — —

$ 210 $ 49 $ 210 $ 49

Cashinterestpaid $ 94 $ 108 $ 190 $ 213

a. AsatSeptember30,2021,$7millionoftheCorporation’stotalcashandcashequivalentsbalancewasheldinU.S.dollars(September30,2020–$47million).TheU.S.dollarcashandcashequivalentsbalancehasbeentranslatedintoCanadiandollarsattheperiodendexchangerateofUS$1=C$1.2750(September30,2020–US$1=C$1.3324).

Thefollowingtableprovidesareconciliationofassetsandliabilitiestocashflowsarisingfromfinancingactivities:

Financesubleasereceivables

Leaseliabilities

Long-termdebt

BalanceasatDecember31,2020 $ 17 $ 286 $ 2,912

Financingcashflowchanges:

Receiptsonleasedassets (2) — —

Paymentsonleasedliabilities — (21) —

Issuanceofseniorunsecurednotes — — 769

Repaymentandredemptionoflong-termdebt — — (889)

Debtredemptionpremiumandrefinancingcosts — — (23)

Othercashandnon-cashchanges:

Leaseliabilitiessettled — (20) —

Leaseliabilitiesincurred — 9 —

Interestexpenseonleaseliabilities — 19 —

Unrealized(gain)lossonforeignexchange — — (9)

Debtredemptionpremium — — 4

Amortizationofdeferreddebtdiscountanddebtissuecosts — — 5

BalanceasatSeptember30,2021 $ 15 $ 273 $ 2,769

(i)Financesubleasereceivables,Leaseliabilities&Long-termdebtallincludetheirrespectivecurrentportion.

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17. NETEARNINGS(LOSS)PERCOMMONSHARE



2021 2020 2021 2020

Netearnings(loss) $ 54 $ (9)$ 105 $ (373)Weightedaveragecommonsharesoutstanding

(millions)(a) 307 303 306 302Dilutiveeffectofstockoptions,RSUsandPSUs

(millions)(b) 5 — 5 —Weightedaveragecommonsharesoutstanding–

diluted(millions) 312 303 311 302

Netearnings(loss)pershare,basic $ 0.17 $ (0.03)$ 0.34 $ (1.24)

Netearnings(loss)pershare,diluted $ 0.17 $ (0.03)$ 0.34 $ (1.24)

a. Weightedaveragecommonsharesoutstanding for the threemonthsendedSeptember30,2021 includenilPSUs vested but not yet released (three months ended September 30, 2020 - 571,529 PSUs). WeightedaveragecommonsharesoutstandingfortheninemonthsendedSeptember30,2021includes180,688PSUsvestedbutnotyetreleased(ninemonthsendedSeptember30,2020-508,256PSUs).

b. ForthethreeandninemonthsendedSeptember30,2020,theCorporationincurredanetlossandthereforetherewasnodilutiveeffectofstockoptions,RSUsandPSUs.IftheCorporationhadrecognizednetearningsforthethreeandninemonthsendedSeptember30,2020,thedilutiveeffectofstockoptions,RSUsandPSUswouldhavebeen3.9millionweightedaveragecommonshares.

18. FINANCIALINSTRUMENTSANDRISKMANAGEMENT

The financial instruments recognized on the consolidated balance sheet are comprised of cash and cashequivalents, trade receivables and other, risk management contracts, accounts payable and accrued liabilities,interestpayableandlong-termdebt.

a. Fairvalues:

Thecarryingvaluesofcashandcashequivalents,tradereceivablesandother,accountspayableandaccruedliabilitiesandinterestpayableincludedontheconsolidatedbalancesheetapproximatesthefairvaluesoftherespectiveassetsandliabilitiesduetotheshort-termnatureofthoseinstruments.

ThefollowingfairvaluesarebasedonLevel2inputstofairvaluemeasurement:

Asat September30,2021 December31,2020Carryingamount Fairvalue

Carryingamount Fairvalue

Recurringmeasurements:

Financialassets

Riskmanagementcontracts $ 61 $ 61 $ 27 $ 27

Financialliabilities

Long-termdebt(Note6) $ 2,800 $ 2,909 $ 2,929 $ 3,019

Riskmanagementcontracts $ 75 $ 75 $ 29 $ 29

Theestimatedfairvalueoflong-termdebtisderivedusingquotedpricesinaninactivemarketfromathird-partyindependentbroker.ThefairvaluewasdeterminedbasedonestimatesasatSeptember30,2021andisexpectedtofluctuategiventhevolatilityinthedebtandcommoditypricemarkets.

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The fair value of risk management contracts is derived using third-party valuation models which requireassumptions concerning the amount and timing of future cash flows and discount rates. Management'sassumptionsrelyonexternalobservablemarketdataincludingforwardpricesforcommodities,interestrateyieldcurvesandforeignexchangerates.Theobservableinputsmaybeadjustedusingcertainmethods,whichincludeextrapolationtotheendofthetermofthecontract.

b. Riskmanagement:

TheCorporation'sriskmanagementassetsandliabilitiesconsistofWTIandlight-heavydifferentialswaps,andifenteredinto,options,pluscondensateswapsandequityswaps.Theuseofthefinancialriskmanagementcontracts isgovernedbyaRiskManagementCommittee that followsguidelinesand limitsapprovedby theBoardofDirectors.TheCorporationdoesnotusefinancialderivativesforspeculativepurposes.Financialriskmanagementcontractsaremeasuredatfairvalue,withgainsandlossesonre-measurementincludedintheconsolidatedstatementofearningsandcomprehensiveincomeintheperiodinwhichtheyarise.

TheCorporation’sfinancialriskmanagementcontractsaresubjecttomasteragreementsthatcreatealegallyenforceable right to offset, by counterparty, the related financial assets and financial liabilities on theCorporation’sbalancesheetinallcircumstances.

ThefollowingtableprovidesasummaryoftheCorporation’sunrealizedoffsettingfinancialriskmanagementpositions:


Asset Liability Net Asset Liability Net

Grossamount $ 61 $ (205)$ (144)$ 27 $ (62)$ (35)

Amountoffset — 130 130 — 33 33

Netamount $ 61 $ (75)$ (14)$ 27 $ (29)$ (2)

Currentportion $ 27 $ (75)$ (48)$ 6 $ (29)$ (23)

Non-currentportion 34 — 34 21 — 21

Netamount $ 61 $ (75)$ (14)$ 27 $ (29)$ (2)

The following table provides a reconciliation of changes in the fair value of the Corporation’s financial riskmanagementassetsandliabilitiesfromJanuary1toSeptember30:

AsatSeptember30 2021 2020

Fairvalueofcontracts,beginningofyear $ (2) $ (77)

Fairvalueofcontractsrealized 222 332

Changeinfairvalueofcontracts (234) (177)

Fairvalueofcontracts,endofperiod $ (14)$ 78

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c. Commodityriskmanagement:

TheCorporationhadthefollowingfinancialcommodityriskmanagementcontractsrelatingtocrudeoilsalesandcondensatepurchasesoutstandingasatSeptember30,2021:

AsatSeptember30,2021

CrudeOilSalesContracts(ii)Volumes(bbls/d)(i) Term

AveragePrice(US$/bbl)(i)

EnhancedFixedPricewithSoldPutOption

WTIFixedPrice/SoldPutOptionStrikePrice 29,000 Oct1,2021-Dec31,2021 $46.18/$38.79

CondensatePurchaseContracts

WTI:MontBelvieuFixedDifferential 10,950 Oct1,2021-Dec31,2021 $(10.37)

WTI:MontBelvieuFixedDifferential 200 Jan1,2022-Dec31,2022 $(11.30)

NaturalGasPurchaseContractsVolumes(GJ/d)(i) Term

AveragePrice(C$/GJ)(i)


AECOFixedPrice 5,000 Jan1,2022-Dec31,2023 $2.50

(i) Thevolumesandpricesintheabovetablerepresentaveragesforvariouscontractswithdifferingtermsandprices.Theaveragepricesfortheportfoliomaynothavethesamepaymentprofileastheindividualcontractsandareprovidedforindicativepurposes.

(ii) Incremental to these crude oil sales contracts, the Corporation occasionally enters into contracts to fix the spreadbetweenWTIpricesforconsecutivemonthswithinaquarter.

(iii) WestTexasIntermediate(“WTI”)crudeoil(iv) WesternCanadianSelect(“WCS”)crudeoilblend

TheCorporationdidnotenter intofinancialcommodityriskmanagementcontractsbetweenSeptember30,2021andNovember8,2021.

Thefollowingtablesummarizesthefinancialcommodityriskmanagementgainsandlosses:



2021 2020 2021 2020Realizedloss(gain)oncommodityrisk

management $ 66 $ (11)$ 222 $ (332)Unrealizedloss(gain)oncommodityrisk

management (68) 17 47 (144)

Commodityriskmanagement(gain)loss,net $ (2)$ 6 $ 269 $ (476)

Thefollowingtablesummarizesthesensitivityoftheearnings(loss)beforeincometax impactoffluctuatingcommoditypriceson theCorporation’sopen financial commodity riskmanagementpositions inplaceasatSeptember30,2021:

Commodity SensitivityRange Increase Decrease

Crudeoilcommodityprice ±US$5.00perbblappliedtoWTIcontracts $ (17) $ 17

Condensatepurchaseprice ±5%incondensatepriceasapercentageofWTI $ 5 $ 5

Naturalgaspurchaseprice ±C$0.50perGJappliedtonaturalgascontracts $ 4 $ (4)

d. Equitypriceriskmanagement:

TheCorporationentersintofinancialequitypriceriskmanagementcontractstoincreasethepredictabilityoftheCorporation'scashflowbymanagingsharepricevolatility.EquitypriceriskistheriskthatchangesintheCorporation’s own share price impact earnings and cash flows. Earnings and funds flow from operating

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activitiesare impactedwhenoutstandingcash-settledRSUsandPSUs, issuedundertheCorporation'sstock-based compensation plans, are revalued each period based on the Corporation’s share price and therevaluation is recognized in stock-based compensation expense. Net cash provided by (used in) operatingactivities is impacted when these stock-based compensation units are ultimately settled. The Corporationenteredintotheseequitypriceriskmanagementcontractstomanageitsexposureoncash-settledRSUsandPSUsvestingbetween2021and2023.



2021 2020 2021 2020

Unrealizedequitypriceriskmanagement(gain)loss $ (7)$ 9 $ (36)$ (11)

Realizedequitypriceriskmanagement(gain)loss — — (8) —

Equitypriceriskmanagement(gain)loss $ (7)$ 9 $ (44)$ (11)

e. Creditriskmanagement:

Credit riskarises fromthepotential thattheCorporationmay incura loss ifacounterparty fails tomeet itsobligationsinaccordancewithagreedterms.TheCorporationappliesthesimplifiedapproachtoprovidingforexpectedcreditlossesprescribedbyIFRS9,whichpermitstheuseofthelifetimeexpectedlossprovisionforall trade receivables. The Corporation uses a combination of historical and forward looking information todetermine the appropriate loss allowance provisions. Credit risk exposure is mitigated through the use ofcredit policies governing the Corporation’s credit portfolio andwith credit practices that limit transactionsaccording to each counterparty's credit quality. A substantial portion of accounts receivable are withinvestment grade customers in the energy industry and are subject to normal industry credit risk. TheCorporationhasexperiencednomateriallossinrelationtotradereceivables.AsatSeptember30,2021,theCorporation’sestimatedmaximumexposuretocreditriskrelatedtotradereceivables,depositsandadvanceswas $396 million. All amounts receivable from commodity risk management activities are due from largeCanadian banks with strong investment grade credit ratings. Counterparty default risk associatedwith theCorporation’scommodityriskmanagementactivitiesisalsopartiallymitigatedthroughcreditexposurelimits,frequentassessmentofcounterpartycredit ratingsandnettingarrangements,asoutlined innote24of theCorporation’s2020annualconsolidatedfinancialstatements.

TheCorporation’scashbalancesareusedtofundthedevelopmentofitsproperties.Asaresult,theprimaryobjectivesof the investmentportfolioare lowriskcapitalpreservationandhigh liquidity.Thecashbalancesareheldinhighinterestsavingsaccountsorareinvestedinhighgrade,liquid,short-terminstrumentssuchasbankers’acceptances, commercialpaper,moneymarketdepositsor similar instruments.ThecashandcashequivalentsbalanceatSeptember30,2021was$210million.Noneoftheinvestmentsarepasttheirmaturityorconsideredimpaired.TheCorporation’sestimatedmaximumexposuretocreditriskrelatedtoitscashandcashequivalentsis$210million.

f. Liquidityriskmanagement:

Liquidity risk is the risk that theCorporationwill notbeable tomeet all of its financial obligations as theybecome due. Liquidity risk also includes the risk that the Corporation cannot generate sufficient cash flowfromtheChristinaLakeProjector isunabletoraisefurthercapital inordertomeet itsobligationsunder itsdebt agreements. The lenders are entitled to exercise any and all remedies available under the debtagreements. The Corporationmanages its liquidity risk through the activemanagement of cash, debt andrevolvingcreditfacilitiesandbymaintainingappropriateaccesstocredit.

Management believes its current capital resources and its ability tomanage cash flow andworking capitallevelswillallowtheCorporationtomeetitscurrentandfutureobligations,tomakescheduledprincipalandinterest payments, and to fund the other needs of the business for at least the next 12months.Meetingcurrent and future obligations through periods of volatility is supported by the Corporation's financialframework including a strong commodity riskmanagement program securing cash flow through 2021 andcreditriskmanagementpoliciesminimizingexposurerelatedtocustomerreceivablesprimarilytoinvestment

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gradecustomersintheenergyindustry.However,noassurancecanbegiventhatthiswillbethecaseorthatfuturesourcesofcapitalwillnotbenecessary.

The Corporation's earliest maturing long-term debt is more than three years out, represented by US$396millionof seniorunsecurednotesdue January2025.Noneof theCorporation’soutstanding long-termdebtcontainfinancialmaintenancecovenants.Additionally,theCorporation'smodifiedcovenant-lite$800millionrevolvingcreditfacilityhasnofinancialmaintenancecovenantunlessdrawninexcessof$400million.Ifdrawninexcessof$400million,theCorporationisrequiredtomaintainaquarterlyfirstliennetleverageratio(firstliennetdebttolasttwelve-monthEBITDA)of3.5orless.UndertheCorporation'screditfacility,firstliennetdebtiscalculatedasdebtunderthecreditfacilityplusotherdebtthatissecuredonaparipassubasiswiththecreditfacility,lesscashonhand.

19. CAPITALMANAGEMENT

TheCorporation'scapitalconsistsofcashandcashequivalents,debtandshareholders'equity.TheCorporation'sobjective formanaging capital is toprioritizebalance sheet strengthwhilemaintaining flexibility to repaydebt,fund sustaining capital, return capital to shareholders or fund future production growth. In the current priceenvironment,managementbelievesitscurrentcapitalresourcesanditsabilitytomanagecashflowandworkingcapitallevelswillallowtheCorporationtomeetitscurrentandfutureobligations,tomakescheduledprincipalandinterestpayments,andtofundtheotherneedsofthebusinessforatleastthenext12months.DebtrepaymentandsustainingcapitalexpenditureactivitiesareanticipatedtobefundedbytheCorporation'sadjustedfundsflow,cash-on-handand/orotheravailableliquidity.


On February 2, 2021, the Corporation successfully closed on a private offering of US$600million in aggregateprincipalamountof5.875%seniorunsecurednotesdueFebruary2029.Thenetproceedsoftheoffering,togetherwithcash-on-hand,wereusedtofullyredeemUS$600millioninaggregateprincipalamountofthe7.00%seniorunsecurednotesdueMarch2024ataredemptionpriceof101.167%andtopayfeesandexpensesrelatedtotheoffer.

The Corporation's earliest maturity date on outstanding debt is January 2025. As at September 30, 2021, theCorporation had $788 million of unutilized capacity under the $800 million revolving credit facility and had$85millionofunutilizedcapacityunderthe$500millionletterofcreditfacility.Aletterofcreditof$15millionwasissuedundertherevolvingcreditfacilityduringthefirstquarterof2020and$12millionremainsoutstandingasatSeptember30,2021.

ThefollowingtablesummarizestheCorporation'snetdebt:

Asat Note September30,2021 December31,2020

Long-termdebt 6 $ 2,769 $ 2,912

Cashandcashequivalents (210) (114)

Netdebt $ 2,559 $ 2,798

Netdebtisanimportantmeasureusedbymanagementtoanalyzeleverageandliquidity.

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ThefollowingtablesummarizestheCorporation'sfundsflowfrom(usedin)operationsandadjustedfundsflow:



Note 2021 2020 2021 2020Netcashprovidedby(usedin)operatingactivities $ 257 $ (31)$ 449 $ 186

Netchangeinnon-cashoperatingworkingcapitalitems 16 (45) 50 44 (28)

Fundsflowfrom(usedin)operations 212 19 493 158

Adjustments:

Settlementexpense(i) 14 21 — 21 —

Paymentsononerouscontracts 7 6 — 18 —

Contractcancellation 14 — 7 — 33


(i) Duringthethirdquarterof2021,theCorporationreachedanagreementtosettlethelitigationmattercommencedin2014relatingtolegacyissuesinvolvingaunittraintransloadingfacilityinAlberta.Undertheagreement,theCorporationpaid(subsequent to the quarter) the sum of $21 million in full and final settlement of the claim and the claim has beendiscontinued.

Management utilizes funds flow from (used in) operations and adjusted funds flow as a measure to analyzeoperatingperformanceandcashflowgeneratingability.Fundsflowfrom(usedin)operationsandadjustedfundsflow impacts the level and extent of debt repayment, funding for capital expenditures and returning capital toshareholders.Byexcludingchangesinnon-cashworkingcapitalandnon-recurringitemsfromcashflows,thefundsflowfrom(usedin)operationsandadjustedfundsflowmeasuresprovidemeaningfulmetricsformanagementbyestablishingaclearlinkbetweentheCorporation'scashflowsandtheoperatingnetbacksfromtheChristinaLakeProject. Funds flow from (used in) operations and adjusted funds flow are not intended to represent net cashprovidedby(usedin)operatingactivities.

Netdebt,fundsflowfrom(usedin)operationsandadjustedfundsflowarenotstandardizedmeasuresandmaynotbecomparablewiththecalculationofsimilarmeasuresbyothercompanies.

20. COMMITMENTSANDCONTINGENCIES

a. Commitments

The Corporation’s commitments are enforceable and legally binding obligations to make payments in thefutureforgoodsandservices.Theseitemsexcludeamountsrecordedontheconsolidatedbalancesheet.TheCorporationhadthefollowingcommitmentsasatSeptember30,2021:

2021(i) 2022 2023 2024 2025 Thereafter Total

Transportationandstorage(ii) $ 100 $ 405 $ 441 $ 441 $ 416 $ 5,677 $ 7,480

Diluentpurchases 121 28 17 — — — 166

Otheroperatingcommitments 6 16 16 13 12 37 100

Variableofficeleasecosts 1 4 4 4 4 27 44

Capitalcommitments 37 — — — — — 37

Commitments $ 265 $ 453 $ 478 $ 458 $ 432 $ 5,741 $ 7,827

(i) Amountsrepresentcontractualmaturitiesoccurringinthefourthquarterof2021.(ii) Thisrepresentstransportationandstoragecommitmentsfrom2021to2048,includingtheAccessPipelineTSA,and

pipeline commitmentswhich are awaiting regulatory approval and are not yet in service. Excludes finance leasesrecognizedontheconsolidatedbalancesheet(Note7(a)).

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b. Contingencies

The Corporation is involved in various legal claims associated with the normal course of operations. TheCorporationbelievesthatanyliabilitiesthatmayarisepertainingtosuchmatterswouldnothaveamaterialimpactonitsfinancialposition.

TheCorporationwasthedefendanttoastatementofclaimoriginallyfiledin2014inrelationtolegacyissuesinvolving aunit train transloading facility inAlberta. The claimwas amended in the fourthquarterof 2017assertingasignificantincreasetodamagesclaimed.TheCorporationfiledastatementofdefenseinthefirstquarter of 2018. During the third quarter of 2021, the Corporation reached an agreement to settle thislitigationmatter. Under the agreement, the Corporation paid (subsequent to the quarter) the sumof $21millioninfullandfinalsettlementoftheclaimandtheclaimhasbeendiscontinued.

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report to shareholders for the period ended september 30, 2021

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