Report to Shareholders for the period ended June 30, 2020€¦ · Report to Shareholders for the period ended June 30 ... • $120 million of cash on hand at quarter end benefiting

ReporttoShareholdersfortheperiodendedJune30,2020(AllfinancialfiguresareexpressedinCanadiandollars($orC$)unlessotherwisenoted)

MEGEnergyCorp.reportedsecondquarter2020operationalandfinancialresultsonJuly27,2020.

MEGcontinuestoproactivelyrespondtothesafetyandfinancialchallengesassociatedwiththeCOVID-19pandemicandremainscommittedtoensuringthehealthandsafetyofallitspersonnelandthesafeandreliableoperationoftheChristinaLakefacility.

“The second quarter was characterized by extreme negative movements in commodity prices coupled withunprecedenteduncertaintyregardingnear-termcrudeoilsupplyanddemandbalancesduetoCOVID-19”saidDerekEvans,PresidentandChiefExecutiveOfficer.“OurteamcontinuedtoreactquicklyduringthequartertoprotectMEG’sfinancialliquiditybyvoluntarilycurtailingproduction,makingadditionalcutstoourcapitalbudgetandfurtherreducingG&Aandnon-energyoperatingexpenses,allofwhichwhensupplementedbyourstronghedgepositionallowedMEGtoexitthequarterwithanundrawnrevolverand$120millionofcashonhand.”

MEGremainswellpositionedfromafinancialliquidityperspective,benefitingnotonlyfromitssignificant2020hedgebookandthetermandstructureofitsoutstandingindebtednessandcreditfacility,butalsofromthelowdeclineandlowcoststructureofitshigh-qualityChristinaLakeasset.

Secondquarterfinancialandoperatinghighlightsinclude:

• Freecash flowof$69milliondrivenbyadjusted funds flowof$89million ($0.29pershare)anddisciplinedcapitalspendingof$20million;

• $120 million of cash on hand at quarter end benefiting from a $215 million realized commodity riskmanagementgaininthequarter.MEG’s$800millionmodifiedcovenant-literevolverremainsundrawn;

• Bitumen production volumes of 75,687 barrels per day (bbls/d) at a steam-oil ratio (SOR) of 2.3, whileundertakingplannedturnaroundactivities;

• Netoperatingcostsof$6.14perbarrel, includingnon-energyoperatingcostsof$4.09perbarrelandstrongpowersaleswhichhad the impactofoffsetting32%ofperbarrelenergyoperatingcosts, resulting inanetenergyoperatingcostof$2.05perbarrel;

• OnMay4,2020,asaresultof thenegativeanduncertaincommoditypriceenvironmentat thattime,MEGreducedfullyear2020capitalinvestmentbyanadditional$50millionto$150million,or40%beloworiginalguidanceof$250million.Approximately75%oftheaggregate$100millioncapitalreductionintheyearwasassociatedwith futurebitumenproduction. MEGalso reducednon-energyoperating cost andgeneral andadministrative(“G&A”)expenseguidanceby$20millionand$10million,respectively;and

• Duringthequarter,adecisionwasmadetorollbacksalariesacrossthecompany,withanemphasisonBoard,executive and senior leader compensation. Effective June 1, 2020, base cash compensation for Boardmemberswasreducedby25%.ThePresidentandChiefExecutiveOfficerhadhisannualbasesalaryreducedby25%,theChiefOperatingOfficerandChiefFinancialOfficereachtooka15%annualbasesalaryreduction,vicepresidents receiveda12%annualbase salary rollbackandallotheremployees receiveda7.5%annualbasesalaryrollback.Inaddition,thevalueoftarget2020long-termincentiveawardsissuedtoemployeesanddirectorsonApril1,2020wasreducedby20%.

1

BlendSalesPricingandNorthAmericanMarketAccess

MEGrealizedanaverageAWBblendsalespriceofUS$15.12perbarrelduringthethreemonthsendedJune30,2020comparedtoUS$27.12perbarrelinthefirstquarterof2020.ThereductioninaverageAWBblendsalespricequarteroverquarterwasprimarilyaresultoftheaverageWTIpricedecreasingbyUS$18.32perbarrel,partiallyoffsetbytheaverageWTI:AWBdifferentialatEdmontonnarrowingbyUS$9.34perbarrel. MEGsold35%(allviapipe)ofitssalesvolumestotheUSGulfCoast(“USGC”)inthesecondquarterof2020comparedto23%(21%viapipeand2%viarail)inthefirstquarterof2020.TheincreaseinsalestotheUSGCinthesecondquarterisaresultoflowerapportionmentontheEnbridgemainlineof13%comparedwith50%apportionmentinthefirstquarterof2020.

Transportation and storage costs averaged US$5.92 per barrel of AWB blend sales in the second quarter of 2020compared toUS$4.39perbarrelofAWBblendsales in the firstquarterof2020.The increase in transportationandstoragecostsisprimarilyduetothefixedcostsassociatedwithcontractedcapacityallocatedto29%lowerAWBblendsalesvolumesquarteroverquarter,partiallyoffsetbytheeliminationofrailcoststotheUSGC.MEG’sAWBblendsalesbyrailwas4,391bbls/d(allFOBEdmonton)inthesecondquarterof2020comparedto30,152bbls/d(27,867bbls/dFOBEdmonton)inthefirstquarterof2020.Thereductioninbarrelssoldviarailquarteroverquarterwasaresultofrail costmitigationeffortsundertakenby theCorporation in the secondquartergiven the relativeeconomicsof railtransportationcomparedtopipelinetransportationcosts.

ExcludingtransportationandstoragecostsupstreamoftheEdmontonindexsalespoint,MEG’snetAWBblendsalesprice at Edmonton averaged US$11.28 per barrel during the threemonths ended June 30, 2020 compared to thepostedAWBindexpriceatEdmontonofUS$14.41perbarrel,largelyasaresultofhavingsalesexposuretotheweakerpricedmonthsofAprilandMay(approximately110,000bbls/dofAWBblendsales),withreducedvolumessoldinthestrongerpricedmonthofJune(approximately84,000bbls/dofAWBblendsales)duetothemajorplannedturnaroundinitiatedatthebeginningofJune.

OperationalPerformance

Bitumen production averaged 75,687 bbls/d in the second quarter of 2020, compared to 91,557 bbls/d in the firstquarter of 2020. Bitumen production in the second quarter was impacted primarily by major planned turnaroundactivities at theCorporation’s Phase1&2 facilitieswhichbeganat thebeginningof June, impactingproductionbyapproximately10,000bbls/dinthequarter,andvoluntaryprice-relatedproductioncurtailmentsintheAprilandMaytimeframe.Netoperatingcostsinthesecondquarterof2020averaged$6.14perbarrel,an11%increasecomparedtothefirstquarterof2020,directly impactedbylowersurpluspowersalesrevenuefromMEG’scogenerationfacilities.Non-energyoperatingcostsaveraged$4.09perbarrelinthesecondquarterof2020comparedto$4.57perbarrelinthefirstquarterof2020.Netenergyoperatingcostsaveraged$2.05perbarrelinthesecondquarterof2020comparedto$0.94perbarrelinthefirstquarterof2020.

G&Aexpensewas$9million,or$1.29perbarrelofproduction,inthesecondquarterof2020comparedto$16million,or$1.96perbarrelofproduction,inthefirstquarterof2020.ThedecreaseinaggregateG&Aquarteroverquarterwasprimarily a result of the temporary Canadian EmergencyWage Subsidy, salary rollbacks and reductions in staff andconsultingcosts.

AdjustedFundsFlowandNetLoss

MEG’sbitumenrealizationaveraged$10.18perbarrelinthesecondquarterof2020comparedto$19.45perbarrelinthefirstquarterof2020.ThereductioninaveragebitumenrealizationquarteroverquarterwasdrivenbythelowerWTI price and lower sales volumes, partially offset by a narrowerWTI:AWB differential which resulted in a higherrecoveryofthecostofdiluentthroughblendsales,decreasingtheCorporation’sperbarrelcostofdiluent.

Offsetting thedecline inbitumenrealizationwasa realizedcommodity riskmanagementgainof$215million in thequarter increasingMEG’sbitumenrealizationby$21.65perbarrelquarteroverquarter.TherealizedcommodityriskmanagementgaincontributedtotheincreaseintheCorporation’scashoperatingnetbackto$25.84perbarrelinthesecond quarter of 2020 compared to $16.83 per barrel in the first quarter of 2020. The increased cash operating

2

netbackdrovetheincreaseintheCorporation’sadjustedfundsflowfrom$78millioninthefirstquarterof2020to$89millioninthesecondquarterof2020.

TheCorporation recognizedanet lossof$80million in the secondquarterof2020compared toanet lossof$284millioninthefirstquarterof2020.Non-cashitemsinthesecondquarterof2020includeanunrealizedgainonforeignexchangeof$114millionandanunrealizedlossoncommodityriskmanagementof$267million.Comparatively,inthefirstquarterof2020,non-cashitemsconsistedofanunrealizedforeignexchangelossof$267million,anexplorationexpenseof$366millionassociatedwith certainnon-coregrowthpropertiesandan inventory impairment chargeof$29million,partiallyoffsetbya$429millionunrealizedgainoncommodityriskmanagementcontracts.

CapitalExpenditures

MEG reacted quickly to the extremely negative oil price environment experienced in the second quarter of 2020,protectingtheCorporation’sfinancial liquiditypartiallybyreducingcapitalexpendituresto$20millioninthequartercomparedto$54million inthefirstquarterof2020.Ofthe$20million,$10millionwasdirectedtowardssustainingandmaintenance activitieswith the remaining $10million related to the planned turnaround at the Christina LakePhase1and2facilitieswhichwasinitiatedatthebeginningofJune.Theexpandedscopeanddurationoftheplannedturnaround,whichwascommittedtoinearlyMay,isexpectedtobeexecutedatreducedcostsbyrelyingoninternalresourcesandwilleliminatetheneedforaturnaroundin2021.

COVID-19GlobalPandemic

The Corporation is continuously monitoring and responding to the ongoing evolving COVID-19 situation. TheCorporation’s business activities have been declared an essential service by the Alberta Government and theCorporation remains committed to the health and safety of all personnel and to the safety and continuity ofoperations. Thehealth and safetymeasures implementedby theCorporation's COVID-19 task force during the firstquarter of 2020 currently remain in place. The vast majority of office staff are still working remotely, however,beginning in June theCorporation lifted certain restrictionswhich allowedmore location essential personnel at theChristinaLakesitetofacilitateMEG’splannedturnaroundactivitywhilestillmaintainingCOVID-19relatedscreening,proceduresandprotocolstoensurecontinuedsafeandreliableoperations.

Outlook

OnMay4,theCorporationsuspendedfullyear2020productionguidanceduetotheglobalcrudeoilpriceenvironmentat that time, which was experiencing multi-decade lows coupled with extreme levels of volatility driven by theunprecedenteddemandshockduetoCOVID-19.

Sincethattime,crudeoilpricelevelsandvolatilityhavestabilizedtoalevelthatallowstheCorporationtore-instatefullyearproductionguidancewhichisnowtargetedat78,000–80,000bbls/d.Comparedtotheoriginalguidanceof94,000–97,000bbls/dannouncedNovember21,2019,approximatelyhalfofthedifferenceisduetotheimpactofthescheduled 70-day major turnaround at the Christina Lake Phase 1 and 2 facilities announced May 4, 2020. Theremainderofthedifferenceresultsfromacombinationofpreviouslydisclosedweather-relatedproductionimpactsinthefirstquarterof2020,voluntaryprice-relatedproductioncurtailmentsinthesecondquarterof2020andtheimpactofreducedwellcapitalthroughout2020,whichmadeupapproximately75%ofthecombined$100millionreductionincapitalspendingannouncedonMarch10andMay4of2020.

Guidancefornon-energyoperatingcosts,G&AexpenseandcapitalexpendituresremainunchangedfromtherevisedguidanceannouncedMay4,2020.

FinancialLiquidity

Notwithstandingmulti-decadelowcrudeoilprices,MEGgenerated$92millionoffreecashflowinthefirsthalfofyear,andexitedthesecondquarterwithitscreditfacilityundrawnand$120millionofcashonhand.

3

TheCorporation’searliestlong-termdebtmaturityisapproximatelyfouryearsout,representedbyUS$600millionofsenior unsecured notes due March 2024. None of the Corporation’s outstanding long-term debt contain financialmaintenance covenants. Additionally, MEG’s modified covenant-lite $800 million revolving credit facility has nofinancialmaintenance covenant unless drawn in excess of $400million. If drawn in excess of $400million,MEG isrequiredtomaintainaquarterlyfirstliennetleverageratio(firstliennetdebttolasttwelve-monthEBITDA)of3.5orless.UnderMEG’screditfacility,firstliennetdebtiscalculatedasdebtunderthecreditfacilityplusotherdebtthatissecuredonaparipassubasiswiththecreditfacility,lesscashonhand.

2H2020CommodityHedges

Forthesecondhalfof2020,todateMEGhasenteredintobenchmarkWTIfixedpricehedgesforapproximately70%offorecast second half bitumen production at an average price of approximately US$46 per barrel. The table belowreflectsallofMEG’scurrent2020financialandphysicalhedgepositions.

Q32020 Q42020 2H2020

WTIHedges

WTIFixedPriceHedges

Volume(bbls/d) 60,812 46,783 53,797

WeightedaveragefixedWTIprice(US$/bbl) $ 44.74 $ 47.42 $ 45.91

EnhancedWTIFixedPriceHedgeswithSoldPutOptions(1)

Volume(bbls/d) 16,870 24,500 20,685

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

$59.38/$52.00

$59.11/$52.00

$59.22/$52.00

WTI:WCSDifferentialHedges

Volume(2)(bbls/d) 45,853 41,150 43,501

WeightedaveragefixedWTI:WCSdifferential(US$/bbl) $ (17.82) $ (20.02) $(18.86)

CondensateHedges

Volume(3)(bbls/d) 23,208 23,208 23,208

Average%ofWTIlandedinEdmonton 100% 100% 100%

(1) Includesfixedpriceswapsandsoldputoptionsenteredintoforthesecondhalfof2020.Atanaverage2H2020WTIpriceofUS$52.00perbarrelorhigher,MEG’seffectiveWTIhedgepricefor2H2020isUS$49.60perbarrel.Illustratively,atanaverage2H2020WTIpriceofUS$40.00,MEG’seffectiveWTIhedgepricefor2H2020isUS$46.27perbarrel.

(2) Includes approximately 24,500 bbls/d (Q3 2020) and 13,000 bbls/d (Q4 2020) of physical forward blend sales at a fixedWTI:AWBdifferential.

(3) 2H2020 includesapproximately8,200bbls/dofphysical forwardcondensatepurchases.Whereapplicable, theaverage%ofWTIlandedinEdmontonincludesestimatednettransportationcoststoEdmonton.

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 an

4

alternativeformeasuresofperformancepreparedinaccordancewithIFRS.

FreeCashFlow

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

ThreemonthsendedJune30 SixmonthsendedJune30

($millions) 2020 2019 2020 2019

Netcashprovidedby(usedin)operatingactivities $ 117 $ 302 $ 216 $ 233Netchangeinnon-cashoperatingworking

capitalitems (48) (75) (78) 145

Fundsflowfrom(usedin)operations 69 227 138 378

Adjustments:

Contractcancellation(1) 20 — 26 —

Decommissioningexpenditures — — 2 —

Adjustedfundsflow $ 89 $ 227 $ 166 $ 378

Capitalexpenditures (20) (32) (74) (85)

Freecashflow $ 69 $ 195 $ 92 $ 293

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.

5

ThisManagement'sDiscussionandAnalysis("MD&A")ofthefinancialconditionandperformanceofMEGEnergyCorp.("MEG"or the "Corporation") for the threeand sixmonths ended June30, 2020wasapprovedby theCorporation'sAuditCommitteeonJuly27,2020.ThisMD&AshouldbereadinconjunctionwiththeCorporation'sunauditedinterimconsolidated financial statements and notes thereto for the three and sixmonths ended June 30, 2020, the auditedannualconsolidated financial statementsandnotes thereto for theyearendedDecember31,2019, the2019annualMD&A and the Corporation's most recently filed Annual Information Form (“AIF”). This MD&A and the unauditedinterim consolidated financial statements and comparative information have been prepared in accordance withInternationalFinancialReportingStandards(“IFRS”)asissuedbytheInternationalAccountingStandardsBoard(“IASB”)andarepresentedinmillionsofCanadiandollars,exceptwhereotherwiseindicated.

Unlessotherwiseindicated,allperbarrelfiguresarebasedonbitumensalesvolumes.

MD&A-TableofContents

1. BUSINESSDESCRIPTION................................................................................................................................ 7

2. OPERATIONALANDFINANCIALHIGHLIGHTS................................................................................................ 7

3. RESULTSOFOPERATIONS............................................................................................................................. 8

4. OUTLOOK...................................................................................................................................................... 19

5. BUSINESSENVIRONMENT............................................................................................................................. 20

6. OTHEROPERATINGRESULTS........................................................................................................................ 22

7. LIQUIDITYANDCAPITALRESOURCES............................................................................................................ 26

8. RISKMANAGEMENT..................................................................................................................................... 28

9. SHARESOUTSTANDING................................................................................................................................. 30

10. CONTRACTUALOBLIGATIONS,COMMITMENTSANDCONTINGENCIES....................................................... 30

11. NON-GAAPMEASURES................................................................................................................................. 31

12. CRITICALACCOUNTINGPOLICIESANDESTIMATES....................................................................................... 31

13. RISKFACTORS............................................................................................................................................... 32

14. DISCLOSURECONTROLSANDPROCEDURES................................................................................................. 33

15. INTERNALCONTROLSOVERFINANCIALREPORTING.................................................................................... 33

16. ABBREVIATIONS............................................................................................................................................ 34

17. ADVISORY...................................................................................................................................................... 34

18. ADDITIONALINFORMATION......................................................................................................................... 36

19. QUARTERLYSUMMARIES.............................................................................................................................. 37

20. ANNUALSUMMARIES................................................................................................................................... 39

6

1. BUSINESSDESCRIPTION

MEGisanenergycompanyfocusedonsustainableinsituthermaloilproductioninthesouthernAthabascaregionof Alberta, Canada. MEG is actively developing innovative enhanced oil recovery projects that utilize steam-assistedgravitydrainage("SAGD")extractionmethodstoimprovetheresponsibleeconomicrecoveryofoilaswellas lower carbon emissions. MEG transports and sells its thermal oil production to refiners throughout NorthAmericaandinternationally.

MEG owns a 100%working interest in over 700 squaremiles ofmineral leases. In the report prepared byGLJPetroleum Consultants Ltd. ("GLJ") and effective December 31, 2019, GLJ estimated that the leases it hadevaluatedcontainedapproximately2.1billionbarrelsofgrossprovedplusprobable("2P")bitumenreservesattheChristinaLakeProject.For informationregardingMEG'sestimatedreservescontained in thereportpreparedbyGLJ,pleaserefer to theCorporation’smost recently filedAIF,which isavailableontheCorporation’swebsiteatwww.megenergy.comandisalsoavailableontheSEDARwebsiteatwww.sedar.com.

2. OPERATIONALANDFINANCIALHIGHLIGHTS

BeginninginearlyMarch2020andcontinuingintothesecondquarterof2020,marketconditionsprecipitatedbytheCOVID-19globalpandemic ("COVID-19"), and subsequentmeasures intended to limit theoutbreakglobally,contributedtoanunprecedentedimpactonglobalcommodityprices.Withreducedcrudeoildemandandexcesssupply,thepriceofcrudeoilandotherpetroleumproductsdeterioratedsignificantlyduringthefirsthalfof2020andalthoughtherehasbeenanimprovementinthestabilityoftheglobaloilmarketneartheendofJuneandintoJuly,thereremainsuncertaintyregardingtheongoingimpactofCOVID-19onglobalcommodityprices.

TheCorporation iscontinuallymonitoringandresponding to theevolvingCOVID-19situation.TheCorporation’sbusiness activities have been declared an essential service by the Alberta Government and the Corporationremainscommittedtothehealthandsafetyofallpersonnelandtothesafetyandcontinuityofoperations.ThehealthandsafetymeasuresimplementedbytheCorporation'sCOVID-19taskforceduringthefirstquarterof2020currentlyremaininplace.Thevastmajorityofofficestaffarestillworkingremotely;however,beginninginJunetheCorporation lifted certain restrictionswhichallowedmore locationessentialpersonnel tobepresentat theChristina Lake site to facilitateplanned turnaroundactivitieswhile stillmaintainingCOVID-19 related screening,proceduresandprotocolstoensurecontinuedsafeandreliableoperations.

Bitumenproductionaveraged75,687bbls/dduringthesecondquarterof2020comparedto97,288bbls/dinthesecond quarter of 2019. The decrease in average bitumen production was primarily driven by major plannedturnaround activities at the Phase 1 and 2 facilities,which began in early June 2020, decreasing production byapproximately10,000bpdinthesecondquarterof2020aswellasvoluntaryprice-relatedproductioncurtailmentsinAprilandMay2020.ThemajorplannedturnaroundisexpectedtobecompleteinAugust2020.

Realized commodity risk management gains of $215million in the second quarter of 2020 partially offset theimpactofdeterioratingcommoditypricesanddecreasedproductionlevels. TheCorporationgeneratedadjustedfundsflowof$89millioninthesecondquarterof2020comparedto$227millioninthesecondquarterof2019.

TheCorporationrecognizedanetlossof$80millioninthesecondquarterof2020comparedtoanetlossof$64millioninthesecondquarterof2019.Theincreaseinthenetlossisduetothedecreasedcashoperatingnetbackaswellasanunrealizedlossoncommodityriskmanagementcontractsof$267million.Comparatively,thenetlossinthesecondquarterof2019reflectsa$237millionaccelerateddepreciationexpense.

7

http://www.megenergy.com

http://www.sedar.com

ThefollowingtablesummarizesselectedoperationalandfinancialinformationoftheCorporationfortheperiodsnoted.AlldollaramountsarestatedinCanadiandollars($orC$)unlessotherwisenotedandallperbarrelfiguresarebasedonbitumensalesvolumes:

SixmonthsendedJune30 2020 2019 2018

($millions,exceptasindicated) 2020 2019 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3

Bitumenproduction-bbls/d 83,622 92,228 75,687 91,557 94,566 93,278 97,288 87,113 87,582 98,751

Steam-oilratio 2.31 2.18 2.32 2.31 2.27 2.26 2.16 2.20 2.22 2.17

Bitumensales-bbls/d 83,806 92,486 70,397 97,214 94,347 94,992 95,120 89,822 88,283 93,856

Bitumenrealization-$/bbl 15.56 56.42 10.18 19.45 46.86 53.37 62.23 50.21 15.31 49.63

Netoperatingcosts-$/bbl(1) 5.78 5.39 6.14 5.51 5.87 4.30 4.66 6.17 4.55 4.34

Non-energyoperatingcosts-$/bbl 4.37 4.86 4.09 4.57 4.49 4.22 4.53 5.22 4.25 4.38

Cashoperatingnetback-$/bbl(2) 20.62 33.98 25.84 16.83 28.33 32.44 37.88 29.80 7.14 24.01

Adjustedfundsflow(3) 166 378 89 78 157 192 227 151 (37) 116

Pershare,diluted 0.55 1.26 0.29 0.26 0.51 0.63 0.76 0.50 (0.13) 0.39

Revenue 972 1,980 307 665 992 958 1,062 919 520 803

Netearnings(loss) (364) (111) (80) (284) 26 24 (64) (48) (199) 118

Pershare,diluted (1.21) (0.37) (0.26) (0.95) 0.09 0.08 (0.21) (0.16) (0.67) 0.39

Capitalexpenditures 74 85 20 54 72 40 32 53 144 139

Cashandcashequivalents 120 399 120 62 206 154 399 154 318 373

Long-termdebt-C$ 3,096 3,582 3,096 3,212 3,123 3,257 3,582 3,660 3,740 3,544

Long-termdebt-US$ 2,274 2,737 2,274 2,275 2,409 2,459 2,737 2,740 2,741 2,742

(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) RefertoNote20oftheinterimconsolidatedfinancialstatementsforfurtherdetails.

3. RESULTSOFOPERATIONS

BitumenProductionandSteam-OilRatio


2020 2019 2020 2019

Bitumenproduction–bbls/d 75,687 97,288 83,622 92,228

Steam-oilratio(SOR) 2.32 2.16 2.31 2.18

BitumenProduction

Bitumenproductionaveraged75,687bbls/dand83,622bbls/dduring the threeandsixmonthsended June30,2020, compared to97,288bbls/dand92,228bbls/dduring the sameperiodsof2019. Thedecrease inaveragebitumenproductionwasprimarilydrivenbymajorplanned turnaroundactivitiesat thePhase1and2 facilities,whichbeganinearlyJune2020,decreasingproductionbyapproximately10,000bbls/dduringthethreemonthsendedJune30,2020aswellasvoluntaryprice-relatedproductioncurtailmentsinAprilandMay2020.ThemajorplannedturnaroundisexpectedtobecompleteinAugust2020.

8

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.TheCorporationcontinuestofocusonimprovingefficiencyofproductionthroughalowerSOR,whichgenerallyindicatesthatsteamisbeingmoreefficientlyused,but isalso influencedby the introductionofnewwells intocirculation.TheSOR increased for the threeandsixmonthsendedJune30,2020,comparedtothesameperiodsof2019,duetothetimingofnewwellpairsandwellsbeingbrought intosteamcirculationandproduction,aswellas reducedproduction levelsduetoCOVID-19andplantturnaroundactivities.

AdjustedFundsFlow

During the three and sixmonths ended June 30, 2020, adjusted funds flow decreased compared to the sameperiods of 2019, primarily driven by the Corporation's reduced cash operating netback which was significantlyimpacted by a sharp decline in global crude oil prices, partially offset by realized gains on commodity riskmanagement contracts. The decrease in adjusted funds flow was also partially mitigated by ongoing costreductionstogeneralandadministrativeexpenseandcashinterestcosts.

$millions

AdjustedFundsFlowThreemonthsendedJune30

$227

(429)

26625 $89

2019

Cashoperatingnetback,exclriskmgm

t

Realizedgainonriskmanagem

ent

Othercashco

sts

2020

-300

-200

-100

0

100

200

$millions

AdjustedFundsFlowSixmonthsendedJune30

$378

(648)

39343 $166

2019

Cashoperatingnetback,exclriskmgm

t

Realizedgainonriskmanagem

ent

Othercashco

sts

2020

-400

-300

-200

-100

0

100

200

300

400

9

Thefollowingtablereconcilesnetcashprovidedbyoperatingactivitiestoadjustedfundsflow:

ThreemonthsendedJune30 SixmonthsendedJune30($millions) 2020 2019 2020 2019

Netcashprovidedby(usedin)operatingactivities $ 117 $ 302 $ 216 $ 233

Netchangeinnon-cashoperatingworkingcapitalitems (48) (75) (78) 145


Adjustments:

Contractcancellation(1) 20 — 26 —

Decommissioningexpenditures — — 2 —


(1) Costsincurredtomitigaterailsalescontractexposure.Contractcancellationcostsorrecoveriesareexcludedfromadjustedfundsflowastheyarenotconsideredpartofordinarycontinuingoperatingresults.

NetcashprovidedbyoperatingactivitiesisanIFRSmeasureintheCorporation'sconsolidatedstatementofcashflow.Adjusted funds flow is calculatedasnet cashprovidedbyoperating activities excluding thenet change innon-cash operating working capital, items not considered part of ordinary continuing operating results, anddecommissioning expenditures. Adjusted funds flow is used by management to analyze the Corporation'soperating performance and cash flow generating ability. By excluding changes in non-cashworking capital andother adjustments from cash flows, the adjusted funds flow measure provides a meaningful metric formanagementbyestablishingaclearlinkbetweentheCorporation'scashflowsandthecashoperatingnetback.

CashOperatingNetback

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


2020 2019 2020 2019

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

Salesfromproduction $ 181 $ 863 $ 650 $1,559

Salesfrompurchasedproduct(1) 118 199 297 402

Petroleumrevenue 299 1,062 947 1,961

Purchasedproduct (106) (199) (282) (394)

Blendsales(2) $ 193 $ 20.96 $ 863 $ 69.19 $ 665 $30.03 $1,567 $64.22

Costofdiluent (128) (10.78) (325) (6.96) (428) (14.47) (622) (7.80)

Bitumenrealization 65 10.18 538 62.23 237 15.56 945 56.42

Transportationandstorage(3) (75) (11.77) (93) (10.80) (152) (9.96) (185) (11.03)

Third-partycurtailmentcredits(4) — — (8) (0.89) 2 0.11 (8) (0.46)

Royalties — (0.05) (18) (2.06) (6) (0.37) (21) (1.24)

NNetoperatingcosts (40) (6.14) (40) (4.66) (88) (5.78) (90) (5.39)

Cashoperatingnetback-excludingrealizedcommodityriskmanagement (50) (7.78) 379 43.82 (7) (0.44) 641 38.30

Realizedgain(loss)oncommodityriskmanagement 215 33.62 (51) (5.94) 321 21.06 (72) (4.32)

Cashoperatingnetback(5) $ 165 $ 25.84 $ 328 $ 37.88 $ 314 $20.62 $ 569 $33.98

Bitumensalesvolumes-bbls/d 70,397 95,120 83,806 92,486

10

(1) Salesfrompurchasedoilproductsrelatedtomarketingassetoptimizationactivities.(2) Blendsalesperbarrelarebasedonblendsalesvolumes.(3) Defined as transportation and storage expense less transportation revenue. Transportation and storage includes costs

associatedwithmovingtheCorporation'sblendfromChristinaLaketoafinalsales locationandoptimizingthetimingofdelivery,netofthird-partyrecoveriesondiluenttransportationarrangements.

(4) The Corporation can purchase or sell production curtailment credits to either increase its production, or sell excessproductioncapacity,comparedtoitsprovincially-mandatedcurtailmentlevel.

(5) Anon-GAAPmeasureasdefinedinthe“NON-GAAPMEASURES”sectionofthisMD&A.

Blendsalesincludesnetrevenuerelatedtomarketingassetoptimizationactivitiesfocusedontherecoveryoffixedcostsrelatedtoanymarketingassetsduringperiodsofunderutilizationofsuchassets,withthegoaltostrengthencashoperatingnetback.Assetoptimizationactivitiesconsistofthepurchaseandsaleofthird-partyproducts.TheCorporationdoesnot engage in speculative trading. Thepurchaseand saleof third-partyproducts requires theconcurrentlockinginofpriceriskpursuanttopoliciesapprovedbytheCorporation'sBoardofDirectorswhichcanbeachievedeitherthroughthecounterpartyorthroughfinancialpriceriskmanagement.

$/bb

l

CashOperatingNetbackThreemonthsendedJune30

$37.88

(48.23)

(3.82)

39.562.01

(1.48) (0.08)

$25.84

2019

Blend

sales

Costof

diluen

t

Realize

driskm

anagem

ent

Royalti

es

Netop

erating

costs

Other

2020

-20

-10

0

10

20

30

40

$/bb

l

CashOperatingNetbackSixmonthsendedJune30

$33.98

(34.19)

(6.67)

25.38 1.07 0.87 0.18 $20.62

2019

Blend

sales

Costof

diluen

t

Realize

driskm

anagem

ent

Transp

ortatio

n&sto

rage

Royalti

esOth

er202

0

-10

0

10

20

30

40

BitumenRealization

BitumenrealizationrepresentstheCorporation'sblendsalesnetofcostofdiluent,expressedonaperbarrelofbitumensoldbasis.BlendsalesrepresentstheCorporation'srevenuefromitsoilblendknownasAWB,which iscomprisedofbitumenproducedattheChristinaLakeProjectblendedwithpurchaseddiluent.Thecostofdiluentisimpacted by Canadian and U.S. benchmark pricing, the amount of diluent required which is impacted byseasonalityandpipelinespecifications,thecostoftransportingdiluenttotheproductionsitefrombothEdmontonandU.S.GulfCoast("USGC")markets,thetimingofdiluentinventorypurchasesandchangesinthevalueoftheCanadiandollarrelativetotheU.S.dollar.Aportionofthecostofdiluentiseffectivelyrecoveredinthesalespriceoftheblendedproduct.Bitumenrealizationperbarrelfluctuatesprimarilybasedonaveragebenchmarkpricesandlight:heavyoildifferentials.

11


2020 2019 2020 2019


Salesfromproduction $ 181 $ 863 $ 650 $ 1,559

Salesfrompurchasedproduct(1) 118 199 297 402

Petroleumrevenue $ 299 $ 1,062 $ 947 $ 1,961

Purchasedproduct (106) (199) (282) (394)

Blendsales(2) $ 193 $ 20.96 $ 863 $ 69.19 $ 665 $ 30.03 $ 1,567 $ 64.22

Costofdiluent (128) (10.78) (325) (6.96) (428) (14.47) (622) (7.80)

Bitumenrealization $ 65 $ 10.18 $ 538 $ 62.23 $ 237 $ 15.56 $ 945 $ 56.42

(1) Salesfrompurchasedoilproductsrelatedtomarketingassetoptimizationactivities.(2) Blendsalesperbarrelarebasedonblendsalesvolumes.

The blend sales price decreased by $48.23 per barrel, or 70%, during the threemonths ended June 30, 2020comparedtothesameperiodof2019.DuringthesixmonthsendedJune30,2020,theblendsalespricedecreasedby$34.19perbarrel,or54%,comparedtothesameperiodof2019.ThedecreaseinblendsalespriceduringthethreeandsixmonthsendedJune30,2020isduetoalowerWTIpriceandwiderWTI:AWBdifferentials.TheWTIprice experienced a significant decline during the three and sixmonths ended June 30, 2020, largely driven byunprecedented demand shock in the global oil markets due to COVID-19. The widening of the WTI:AWBdifferentialatEdmontonreflectedprevailingdemand/supply fundamentals forheavyoil inWesternCanadaandegressconstraintsmovingbeyondwesternCanada.

TheCorporationcontinuestoexecuteonitsstrategytopartiallymitigatethecostofunutilizedtransportationandstorageassets.Duringthesecondquarterof2020,theseactivitiesadded$12milliontoblendsales,or$1.24perbarrel, to theblend salesprice.Ona year-to-datebasis, anadditional$15millionwasadded toblend sales,or$0.65perbarrel to theblendsalesprice.TheCorporationdoesnotengage inspeculative trading.Thepurchaseandsaleofthird-partyproductsrequirestheconcurrent locking inofpriceriskpursuanttopoliciesapprovedbytheCorporation'sBoardofDirectorswhichcanbeachievedeitherthroughthecounterpartyorthroughfinancialpriceriskmanagement.

Costofdiluentincreasedby$3.82perbarrel,or55%,duringthethreemonthsendedJune30,2020comparedtothesameperiodof2019.DuringthesixmonthsendedJune30,2020,thecostofdiluentincreasedby$6.67perbarrel,or86%,comparedtothesameperiodof2019.TheincreaseduringthethreeandsixmonthsendedJune30,2020reflectswiderWTI:AWBdifferentialsandtheuseofhigherpriceddiluentfrominventoryresultinginalowerrecoveryofthecostofdiluentthroughblendsales.

Theabovefactors,combinedwith lowerproductionandsalesvolumesduringthethreemonthsendedJune30,2020,decreasedbitumenrealizationby$52.05perbarrel,or84%,and$40.86perbarrel,or73%,duringthethreeandsixmonthsendedJune30,2020,respectively,comparedtothesameperiodsof2019.

TransportationandStorage

TheCorporation'smarketingstrategyfocusesonmaximizingtherealizedAWBsalespriceaftertransportationandstoragecostsbyutilizingitsnetworkofpipeline,railandstoragefacilitiestooptimizemarketaccess.


2020 2019 2020 2019


Transportationandstorage $ (75)$ (11.77)$ (93)$ (10.80)$ (152)$ (9.96)$ (185)$ (11.03)

DuringthethreeandsixmonthsendedJune30,2020,totaltransportationandstoragecostsdecreased19%and18%,respectively,comparedtothesameperiodsof2019.Thedecreaseisprimarilytheresultofdecreasedblend

12

sales volumes transported by rail to the USGC market. Beginning in 2020, the Corporation suspended itscontracted transport of blend sales by rail to theUSGC in favour of increasing its blend sales freight on board("FOB") at rail terminals at Edmonton. The Corporation no longer leases rail cars nor has contracted railcommitmentsbeyondloadingcapacityofFOBsalesatEdmonton.

Transportationandstoragecostsonaperbarrelbasis increasedduring the threemonthsendedJune30,2020,comparedtothesameperiodof2019,asfixedcostswereallocatedover lowersalesvolumes.Thesefixedcostswereoffsetby$1.24perbarrelthroughassetoptimizationactivitiesrecognizedinblendsales.

EffectiveJuly1,2020,theCorporationhascontractedfor100,000barrelsperdayofblendtransportationcapacityon the Flanagan South and Seaway pipeline systems, providing pipeline transportation directly to the USGCrefineriesandexportterminals.Totheextentthatcapacityisunderutilized,theCorporationwill looktomitigatetheassociatedcoststhroughshort-termthird-partycontracts.

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.


2020 2019 2020 2019


Royalties $ — $ (0.05)$ (18)$ (2.06)$ (6)$ (0.37)$ (21)$ (1.24)

Thedecrease in royalties for the threeand sixmonthsended June30, 2020, compared to the sameperiodsof2019,isprimarilytheresultofthedecreaseintheWTIbenchmarkprice.

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 itssteamandelectricity requirements.Anyexcesspowerthat issold intotheprovincialpowergriddisplaces other power sources that have a higher carbon intensity, thereby reducing the Corporation's carbonfootprint.


2020 2019 2020 2019


Operatingcosts-non-energy $ (27)$ (4.09)$ (39)$ (4.53)$ (67)$ (4.37)$ (81)$ (4.86)

Operatingcosts-energy (19) (3.00) (15) (1.78) (47) (3.09) (43) (2.55)

Powerrevenue 6 0.95 14 1.65 26 1.68 34 2.02

Netoperatingcosts $ (40)$ (6.14)$ (40)$ (4.66)$ (88)$ (5.78)$ (90)$ (5.39)Averagenaturalgaspurchase

price(C$/mcf) $ 2.11 1.68 $ 2.39 $ 2.35Averagerealizedpowersales

price(C$/Mwh) $ 28.34 55.33 $ 51.67 $ 63.32

13

Non-energyoperatingcostsdecreasedforthethreeandsixmonthsendedJune30,2020,comparedtothesameperiods of 2019, primarily as a result of the temporary Canadian EmergencyWage Subsidy ("CEWS") program,salary rollbacks and reductions in staff and consulting costs. The provincial and federal governments haverecognizedtheseriouseconomicimpactsofCOVID-19resultinginthecollapseofoilpricesandtheimpactontheoilandgas industryandhave takensteps toprovidevariousprograms,suchasCEWS.During the threemonthsended June 30, 2020, the Corporationwas able to benefit fromnon-recurring cost reductions, including CEWS,whichoffsetnon-energyoperatingcostsbyapproximately$4million.

Netenergyoperatingcosts increasedforthethreeandsixmonthsendedJune30,2020,comparedtothesameperiodsof2019,predominantlyduetomarketdrivenenergyandpowerprices.TotalnetoperatingcostsforthethreeandsixmonthsendedJune30,2020wereessentiallyflatcomparedtothesameperiodsof2019.

RealizedGainorLossonCommodityRiskManagement

TheCorporationenters intofinancialcommodityriskmanagementcontractsto increasethepredictabilityoftheCorporation'scashflowbymanagingcommoditypricevolatility.


2020 2019 2020 2019


Realizedgain(loss)oncommodityriskmanagement $ 215 $ 33.62 $ (51)$ (5.94)$ 321 $ 21.06 $ (72)$ (4.32)

RealizedgainsrecognizedoncommodityriskmanagementcontractshavesignificantlyincreasedduringthethreeandsixmonthsendedJune30,2020,comparedtothesameperiodsof2019,duetotheunprecedenteddeclineintheWTIpricecomparedtotheWTIfixedpricecontractsinplace.Realizedlosseswererecognizedduringthethreeand sixmonths ended June 30, 2019. Refer to the commodity riskmanagement discussionwithin the “OTHEROPERATINGRESULTS”sectionofthisMD&Aforfurtherdetails.

14

MarketingActivity

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

ThreemonthsendedJune30,2020

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

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

WTI-benchmark $ 27.85 $ 27.85 $ 27.85 $ — $ 27.85

Differential-WTI:AWBatsalespoint (17.15) (26.01) (3.37) — (12.73)Blendsalesprice 10.70 1.84 24.48 — 15.12

Transportationandstorage(1) (2.08) (13.53) (11.66) — (5.92)

TransportationandstoragefromChristinaLaketoEdmonton(2) 2.08 2.08 2.08 — 2.08

Blendsalesprice,netoftransportation&storageatEdmonton $ 10.70 $ (9.61) $ 14.90 $ — $ 11.28

Totalblendsales-bbls/d 61,344 4,391 35,245 — 100,980%oftotalsales 61% 4% 35% —% 100%


USGCpremium(US$/bbl)

Averageblendsalespricebylocation $ 10.11 $ 24.48 $ 14.37

Transportationandstorage(1) (2.84) (11.66) (8.82)

TransportationandstoragefromChristinaLaketoEdmonton(2) 2.08 2.08 —

Blendsalesprice,netoftransportation&storageatEdmonton $ 9.35 $ 14.90 $ 5.55

ThreemonthsendedJune30,2019


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

WTI-benchmark $ 59.82 $ 59.82 $ 59.82 $ 59.82 $ 59.82

Differential-WTI:AWBatsalespoint (13.29) (10.87) 1.48 (0.78) (8.10)

Blendsalesprice 46.53 48.95 61.30 59.04 51.72

Transportationandstorage(1) (1.65) (3.86) (10.28) (26.02) (5.60)

TransportationandstoragefromChristinaLaketoEdmonton(2) 1.65 1.65 1.65 1.65 1.65

Blendsalesprice,netoftransportation&storageatEdmonton $ 46.53 $ 46.74 $ 52.67 $ 34.67 $ 47.77

Totalblendsales-bbls/d 73,822 16,783 39,855 6,660 137,120

%oftotalsales 54% 12% 29% 5% 100%







(1) Definedastransportationandstorageexpenseslesstransportationrevenue,perbarrelofblendsalesvolumes.Forreference,totaltransportationandstoragecostsperbarrel,basedonbitumensalesvolumes,wereC$11.77perbarrelforthethreemonthsendedJune30,2020comparedtoC$10.80perbarrelforthethreemonthsendedJune30,2019.

(2) IncludesalltransportationandstoragecostsassociatedwithmovingbarrelsofblendfromChristinaLaketoEdmontonsalespoint.(3) Salesfrommarketingassetoptimizationactivitiesarerecognizedintheblendsalespriceandnotasarecoveryoftransportation

andstoragecosts forconsistencywiththefinancialstatements.Theseactivitiescontributed$12milliontoblendrevenue,orUS$2.56perbarrel,totheblendsalespriceattheUSGC.Ifpresentedasatransportationandstoragecostrecovery,transportationandstoragecostsperbarrelattheUSGCwouldbeUS$9.10perbarrelandtheWTI:AWBdifferentialattheUSGCwouldbeUS$5.93perbarrel.

(4) Resultsaretranslatedattheaverageforeignexchangerateof1.3860forthethreemonthsendedJune30,2020and1.3376forthethreemonthsendedJune30,2019.

15

SixmonthsendedJune30,2020


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

WTI-benchmark $ 37.01 $ 37.01 $ 37.01 $ 37.01 $ 37.01

Differential-WTI:AWBatsalespoint (19.84) (15.81) (4.78) 12.65 (15.02)Blendsalesprice 17.17 21.20 32.23 49.66 21.99




Totalblendsales-bbls/d 72,150 16,129 32,258 1,143 121,680%oftotalsales 59% 13% 27% 1% 100%









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

WTI-benchmark $ 57.36 $ 57.36 $ 57.36 $ 57.36 $ 57.36

Differential-WTI:AWBatsalespoint (14.60) (10.18) 1.19 (2.31) (9.20)

Blendsalesprice 42.76 47.18 58.55 55.05 48.16




Totalblendsales-bbls/d 77,269 13,459 36,434 7,600 134,762

%oftotalsales 57% 10% 27% 6% 100%







(1) Definedastransportationandstorageexpenseslesstransportationrevenue,perbarrelofblendsalesvolumes.Forreference,totaltransportationandstoragecostsperbarrel,basedonbitumensalesvolumes,wereC$9.96perbarrelforthesixmonthsendedJune30,2020comparedtoC$11.03perbarrelforthesixmonthsendedJune30,2019.

(2) IncludesalltransportationandstoragecostsassociatedwithmovingbarrelsofblendfromChristinaLaketoEdmontonsalespoint.(3) Salesfrommarketingassetoptimizationactivitiesarerecognizedintheblendsalespriceandnotasarecoveryoftransportation

andstoragecosts forconsistencywiththefinancialstatements.Theseactivitiescontributed$15milliontoblendrevenue,orUS$1.80perbarrel,totheblendsalespriceattheUSGC.Ifpresentedasatransportationandstoragecostrecovery,transportationandstoragecostsperbarrelattheUSGCwouldbeUS$9.54perbarrelandtheWTI:AWBdifferentialattheUSGCwouldbeUS$6.58perbarrel.

(4) Resultsaretranslatedattheaverageforeignexchangerateof1.3653forthesixmonthsendedJune30,2020and1.3335forthesixmonthsendedJune30,2019.

16

TheCorporation'saccesstotheUSGC,wheresalespricingisnotsubjecttothesamelight:heavyoildifferentialasattheEdmontonmarket,translatedintopremiumsearnedonAWBblendsalesattheUSGCovertheEdmontonmarket ofUS$5.55 per barrel andUS$5.59 per barrel for the three and sixmonths ended June 30, 2020. ThiscomparestopremiumsofUS$3.50perbarrelandUS$3.66perbarrelattheUSGCcomparedtoEdmontonmarketduringthethreeandsixmonthsendedJune30,2019.ThepremiumsrecognizedduringthethreeandsixmonthsendedJune30,2020werehigherthanthesameperiodsof2019primarilyduetothewiderWTI:AWBdifferentialat Edmonton and the suspension of USGC rail during the three and six months ended June 30, 2020. TheCorporationactivelymanagesitssalesstrategytomaximizebenefitsfromlocationdifferentialswhentheyarise.

ExcludingtransportationandstoragecostsupstreamoftheEdmontonmarket,theCorporation'snetAWBblendsalespriceatEdmontonaveragedUS$11.28perbarrelduringthethreemonthsendedJune30,2020comparedtothepostedAWBbenchmarkpriceatEdmontonofUS$14.41perbarrel.ThiswaslargelyaresultofhavinggreatersalesexposuretotheweakerpricedmonthsofAprilandMay2020(approximately110,000bbls/dofAWBblendsales),withreducedvolumessoldinthestrongerpricedmonthofJune2020(approximately84,000bbls/dofAWBblendsales)duetothemajorplannedturnaroundthatbeganinearlyJune2020.

ExcludingtransportationandstoragecostsupstreamoftheEdmontonmarket,theCorporation'sAWBblendsalespriceaveragedUS$18.90perbarrelduringthesixmonthsendedJune30,2020consistentwiththepostedAWBbenchmark price at Edmonton of US$18.90 per barrel. Notwithstanding that EnbridgeMainline apportionmentaveraged32%duringthesixmonthsendedJune30,2020,theCorporationwasabletocapturepricinginlinewiththeEdmontonAWBbenchmarkpriceasaresultofitsmarketingandstorageassetsandtheabilitytomovebarrelstothehigher-pricedUSGCmarket.

Revenue

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


($millions) 2020 2019 2020 2019

Salesfrom:

Production $ 181 $ 863 $ 650 $ 1,559

Purchasedproduct(1) 118 199 297 402


Royalties — (18) (6) (21)

Petroleumrevenue,netofroyalties $ 299 $ 1,044 $ 941 $ 1,940

Powerrevenue $ 6 $ 14 $ 26 $ 34

Transportationrevenue 2 3 5 6

Otherrevenue $ 8 $ 17 $ 31 $ 40

Totalrevenues $ 307 $ 1,061 $ 972 $ 1,980

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

DuringthethreeandsixmonthsendedJune30,2020,totalrevenuesdecreased71%and51%,respectively,fromthe same periods of 2019 primarily as a result of the decrease to the average blend sales price driven by thedeclineinWTIprices,thewideningofWTI:AWBdifferentialsandreducedblendsalesvolumes.

17

NetLoss


($millions,exceptpershareamounts) 2020 2019 2020 2019

Netloss $ (80)$ (64)$ (364)$ (111)

Pershare,diluted $ (0.26)$ (0.21)$ (1.21)$ (0.37)

ThenetlossforthethreemonthsendedJune30,2020reflectsalowercashoperatingnetbackcomparedtothesameperiodof2019aswellasanunrealizedlossoncommodityriskmanagementcontractsof$267millionandanunrealized gainon foreign exchangeof $114million. Thenet loss for the sixmonths ended June30, 2020 alsoreflectsalowercashoperatingnetbackcomparedtothesameperiodof2019aswellasanexplorationexpenseof$366millionandanunrealizedlossonforeignexchangeof$153million,partiallyoffsetbyanunrealizedgainoncommodityriskmanagementcontractsof$161million.

Comparatively,thenetlossinthethreemonthsendedJune30,2019reflectsanaccelerateddepreciationexpenseof$237millionandanexplorationexpenseof$58million,partiallyoffsetbyunrealizedgainsoncommodityriskmanagementcontractsandforeignexchangeof$87millionand$67million,respectively.Thenet loss inthesixmonthsendedJune30,2019alsoreflectsthe$237millionaccelerateddepreciationexpenseandanunrealizedlossoncommodityriskmanagementcontractsof$122million,partiallyoffsetbyanunrealizedforeignexchangegainof$145million.

CapitalExpenditures


($millions) 2020 2019(1) 2020 2019(1)

Sustainingandmaintenance $ 10 $ 19 $ 50 $ 41

Turnaround 10 — 10 —

Phase2Bbrownfieldexpansion — 7 14 20

eMVAPEX — 5 — 12

Fieldinfrastructure,corporateandother — 1 — 12

$ 20 $ 32 $ 74 $ 85(1) Certain prior year costs have been reclassified for consistencywith the Corporation's Phase 2B brownfield development

plan.

ThedecreaseincapitalspendingforthethreeandsixmonthsendedJune30,2020,comparedtothesameperiodsof2019,reflectstheCorporation'sdecisiontoreducecapitalspendinginthefirsthalfof2020duetotheeconomicinstabilitycreatedbyCOVID-19.CapitalexpendituresduringthethreeandsixmonthsendedJune30,2020wereprimarilydirectedtowardssustainingandmaintenanceactivitiesincludingtheturnaroundthatbeganinearlyJune2020.Phase2Bbrownfieldexpansionexpendituresarecurrentlysuspendeduntilprojecteconomicsimprove.

18

4. OUTLOOK

OnMay4,2020,theCorporationsuspendedfullyear2020productionguidanceduetotheglobalcrudeoilpriceenvironment at that time which was experiencing multi-decade lows coupled with extreme levels of volatilitydrivenbytheunprecedenteddemandshockduetoCOVID-19.

Since that time, crudeoil price levels and volatility have stabilized to a level that allows theCorporation to re-instatefullyearproductionguidancewhichisnowtargetedat78,000–80,000bbls/d.Comparedtotheoriginalguidanceof94,000–97,000bbls/dannouncedNovember21,2019,approximatelyhalfofthedifferenceisduetotheimpactofthescheduled70-daymajorturnaroundattheChristinaLakePhase1and2facilitiesannouncedMay4, 2020. The remainder of the difference results from a combination of previously disclosed weather-relatedproduction impacts in the first quarter of 2020, voluntary price-related production curtailments in the secondquarter of 2020 and the impact of reduced well capital in 2020, which made up approximately 75% of thecombined$100millionreductionincapitalspendingannouncedonMarch10andMay4of2020.

Guidance for non-energyoperating costs, general and administrative expense ("G&A") and capital expendituresremainsunchangedfromtherevisedguidanceannouncedMay4,2020.

Summaryof2020Guidance

Production(fullyear2020average) 78,000-80,000bbls/d

Non-energyoperatingcost $140-$150million

G&Aexpense $52.5-$55million

Capitalexpenditures $150million

19

5. BUSINESSENVIRONMENT

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

SixmonthsendedJune30 2020 2019

2020 2019 Q2 Q1 Q4 Q3 Q2 Q1AverageBenchmarkCommodityPricesCrudeoilpricesBrent(US$/bbl) 42.13 66.11 33.30 50.95 62.50 61.97 68.32 63.90WTI(US$/bbl) 37.01 57.36 27.85 46.17 56.96 56.45 59.82 54.90

Differential–WTI:WCS–Edmonton(US$/bbl) (16.00) (11.48) (11.47) (20.53) (15.83) (12.24) (10.67) (12.29)Differential–WTI:AWB–Edmonton(US$/bbl) (18.11) (13.42) (13.44) (22.78) (18.44) (14.52) (12.32) (14.50)AWB–Edmonton(US$/bbl) 18.90 43.94 14.41 23.39 38.52 41.93 47.50 40.40

Differential–WTI:AWB–U.S.GulfCoast(US$/bbl) (6.52) 0.38 (7.29) (5.74) (5.25) (2.50) 1.64 (0.89)AWB–U.S.GulfCoast(US$/bbl) 30.49 57.74 20.56 40.43 51.71 53.95 61.46 54.01

CondensatepricesCondensateatEdmonton(C$/bbl) 46.24 71.00 30.72 61.76 70.01 68.73 74.76 67.25CondensateatEdmontonas%ofWTI 91.5% 92.8% 79.6% 99.5% 93.1% 92.2% 93.4% 92.1%CondensateatMontBelvieu,Texas(US$/bbl) 28.35 49.27 17.43 39.27 50.08 44.34 50.22 48.31CondensateatMontBelvieu,Texasas%ofWTI 76.6% 85.9% 62.6% 85.1% 87.9% 78.5% 84.0% 88.0%NaturalgaspricesAECO(C$/mcf) 2.23 1.99 2.21 2.26 2.70 0.95 1.12 2.86ElectricpowerpricesAlbertapowerpool(C$/MWh) 48.16 63.55 29.94 66.38 47.07 46.95 56.37 70.73ForeignexchangeratesC$equivalentof1US$–average 1.3653 1.3335 1.3860 1.3445 1.3201 1.3207 1.3376 1.3293C$equivalentof1US$–periodend 1.3616 1.3091 1.3616 1.4120 1.2965 1.3244 1.3091 1.3360

BeginninginearlyMarch2020andcontinuingintothesecondquarterof2020,marketconditionsprecipitatedbyCOVID-19, and subsequentmeasures intended to limit the outbreak globally, contributed to an unprecedentedimpactonglobalcommodityprices.Withreducedcrudeoildemandandexcesssupply,thepriceofcrudeoilandotherpetroleumproductsdeterioratedsignificantlyduringthefirsthalfof2020andalthoughtherehasbeenanimprovementinthestabilityoftheglobaloilmarketneartheendofJuneandintoJuly,thereremainsuncertaintyregardingtheongoingimpactofCOVID-19onglobalcommodityprices.

These events and conditions have also caused a significant decrease in the valuation of oil and natural gascompanies. These difficulties have been exacerbated in Canada by actions resulting in uncertainty surroundingregulatory,tax,royaltychangesandenvironmentalregulation. Inaddition,thedifficultiesencounteredtoobtainthe necessary approvals on a timely basis to build pipelines, liquefied natural gas plants and other facilities toprovide better access tomarkets for the oil and natural gas industry in western Canada has led to additionaldownwardpricepressureonoilandnaturalgasproducedinwesternCanada.

20

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,withthediscountdependentonboththequalitydifferentialbetweenAWBandWCSandthesupply/demand fundamentals for oil in Western Canada. AWB is also sold at the USGC and is sold at a discount orpremiumtoWTIdependentonthesupply/demandfundamentalsforoilintheUSGCregion.

OnDecember3,2018theGovernmentofAlbertaenactedrulestoenableatemporarycurtailmentofcrudeoilandbitumenproduction.TheCurtailmentRulescameintoforceonJanuary1,2019,andareinplaceuntilDecember31,2020,withpossibleearliertermination.TheCurtailmentRulesgivetheProvincetheauthoritytomakeanorderto set themaximumcombinedprovincialproductionamountof crudeoil andbitumenonamonthlybasis. Thelimitismonitoredcloselyandadjustedtomatchexportcapacityoutoftheprovince.

OnOctober31,2019theGovernmentofAlbertaSpecialProductionAllowanceprogramwasenactedtogivecrudeoil andbitumenproducers temporary curtailment relief equal to incremental increases in rail shipments. On amonthlybasis,operatorscanapplytoincreaseoilproductionifadditionalproductismovedbynewrailcapacityoutoftheprovince.

CondensatePrices

Inordertofacilitatepipelinetransportationofbitumen,theCorporationusescondensateasdiluentforblendingwiththeCorporation’sbitumen.TheCorporationsourcesitscondensatefromtheEdmontonarea,butduetohighdemand for condensate in the Edmonton market, the Corporation also purchases condensate from the USGCmarketwherepricing isgenerally lower. TheCorporation'scommitteddiluentpurchasesat theUSGCreferencebenchmarkpricingatMontBelvieu, Texas. TheCorporation'sperbarrel costof condensate sourced fromMontBelvieu,Texas includednet transportationcostsofapproximatelyUS$6.16perbarrelandUS$6.13perbarrel tomovetheproduct fromMontBelvieutotheEdmontonareaforthethreeandsixmonthsendedJune30,2020,respectively.

NaturalGasPrices

Natural gas is a primary energy input cost for theCorporation, used as fuel to generate steam for the thermalproductionprocessandtocreatesteamandelectricity fromtheCorporation'scogeneration facilities.TheAECOnaturalgaspriceincreasedduringthethreeandsixmonthsendedJune30,2020comparedtothesameperiodsof2019duetolowgasstorageinventories.

ElectricPowerPrices

Electric power prices impact the price that the Corporation receives on the sale of surplus power from theCorporation’s cogeneration facilities. The Alberta power pool price decreased during the three and sixmonthsendedJune30,2020comparedtothesameperiodsof2019primarilyasaresultofanoversupplyofgenerationintheprovince.

21

6. OTHEROPERATINGRESULTS

DepletionandDepreciation


($millions) 2020 2019 2020 2019

Depletionanddepreciationexpense $ 93$ 365$ 217$ 480

Depletionanddepreciationexpenseperbarrelofproduction $ 13.55$ 41.22$ 14.25$ 28.76

Depletion and depreciation expense was impacted by one-time charges as the Corporation narrows itsdevelopmentfocustocoreassetsatChristinaLake.TheCorporationincurredanaccelerateddepreciationexpenseof$13million,or$0.86perbarrel,duringthesixmonthsendedJune30,2020comparedto$237million,or$14.20perbarrel,forthesixmonthsendedJune30,2019.Theaccelerateddepreciationexpensein2019wasrecognizedon equipment, materials and engineering costs associated with greenfield expansion projects and a partialupgradingtechnologyproject.

Excludingone-timecharges,depletionanddepreciationexpensewas$13.55perbarreland$13.39perbarrelforthethreeandsixmonthsendedJune30,2020,respectively,comparedto$14.44perbarreland$14.56perbarrelforthethreeandsixmonthsendedJune30,2019.

ExplorationExpense


($millions) 2020 2019 2020 2019

Explorationexpense $ — 58 $ 366 58

Duringthefirstquarterof2020,theCorporationdiscontinuedexplorationandevaluationactivitiesincertainnon-core growth properties and as such the associated land lease and evaluation costs totaling $366million werechargedtoexplorationexpenseduring thesixmonthsendedJune30,2020comparedto$58millionduring thesame period of 2019. This is a result of focusing on the development of core assets to manage the businessthroughanunpredictableglobaldownturnofunknownduration.

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.

22


($millions) 2020 2019 2020 2019

Realized:

Crudeoilcontracts(1) $ 226 $ (44)$ 335 $ (62)

Condensatecontracts(2) (11) (7) (14) (10)

Realizedcommodityriskmanagementgain(loss) $ 215 $ (51)$ 321 $ (72)

Unrealized:

Crudeoilcontracts(1) $ (323)$ 91 $ 117 $ (112)

Condensatecontracts(2) 56 (4) 44 (10)

Unrealizedcommodityriskmanagementgain(loss) $ (267)$ 87 $ 161 $ (122)

Commodityriskmanagementgain(loss) $ (52)$ 36 $ 482 $ (194)

(1) IncludesWTIfixedpricecontracts,WTIoptions,WTI:WCSfixeddifferentialcontractsandWTI:WCS(USGC)fixeddifferentialcontracts.

(2) RelatestocondensatepurchasecontractsthateffectivelyfixcondensatepricesatMontBelvieu,TexasrelativetoWTI.

DuringthethreemonthsendedJune30,2020,a$215millioncommodityriskmanagementgainwasrealizedonsettled commodity riskmanagement contracts significantly insulating the Corporation's cash operating netbackfromthevolatilecommoditymarket,particularlycrudeoilprices.Thefairvalueofcommodityriskmanagementcontractswhich settle in futureperiodswas reducedas forwardpriceshad improvedat theendof the secondquarterof2020,comparedtoforwardpricesattheendofthefirstquarterof2020.ForwardWTIpricesincreasedandWTI:WCSdifferentialsnarrowedrelativetocontractedpricesresultingina$267millionunrealizedcommodityriskmanagementlossduringthesecondquarterof2020.

ForthesixmonthsendedJune30,2020,theCorporationrecognizeda$482millionnetgainfromcommodityriskmanagementprimarilydue toweakeningWTIprices relative to contractedprices. This compareswith the$194million net loss from commodity risk management for the six months ended June 30, 2019, whenWTI pricesincreasedandWTI:WCSdifferentialsnarrowedrelativetocontractedprices.

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) 2020 2019 2020 2019

WTIfixedpricecontracts:

Averagefixedprice $ 56.75 $ 63.96 $ 57.74 $ 64.14

Averagesettlementprice 27.85 60.17 37.01 57.53

Gain(loss)onWTIfixedpricecontracts $ 28.90 $ 3.79 $ 20.73 $ 6.61

WTI:WCSfixeddifferentialcontracts:

Averagefixeddifferential $ (18.67)$ (21.82)$ (19.85)$ (22.48)

Averagesettlementdifferential (11.47) (10.68) (16.00) (11.49)

Gain(loss)onWTI:WCSfixeddifferentialcontracts $ (7.20)$ (11.14)$ (3.85)$ (10.99)

Condensatepurchasecontracts:

Averagefixeddifferential(1) $ (5.81)$ (5.66)$ (5.59)$ (5.11)

Averagesettlementdifferential (10.47) (9.59) (8.69) (8.09)

Gain(loss)oncondensatepurchasecontracts $ (4.66)$ (3.93)$ (3.10)$ (2.98)

(1) CondensatepurchasecontractseitherfixtheWTI:condensatedifferentialatMontBelvieu,TexasrelativetoWTIorfixthecondensatepriceasa%ofWTI.

23

GeneralandAdministrative


($millions) 2020 2019 2020 2019

Generalandadministrativeexpense $ 9$ 16$ 25$ 34

Generalandadministrativeexpenseperbarrelofproduction $ 1.29$ 1.81$ 1.66$ 2.03

Generalandadministrativeexpensedecreased44%and26%forthethreeandsixmonthsendedJune30,2020,respectively,comparedtothesameperiodsof2019,primarilyasaresultofthetemporaryCEWS,salaryrollbacksandreductionsinstaffandconsultingcosts.DuringthethreemonthsendedJune30,2020,theCorporationwasabletobenefitfromnon-recurringcostreductions, includingCEWS,whichoffsetG&Acostsbyapproximately$3million.

DuringthethreemonthsendedJune30,2020,adecisionwasmadetorollbacksalariesacrosstheCorporation,with an emphasis on Board, executive and senior leader compensation. Effective June 1, 2020, base cashcompensationforBoardmemberswasreducedby25%.ThePresidentandChiefExecutiveOfficerhadhisannualbasesalaryreducedby25%,theChiefOperatingOfficerandChiefFinancialOfficereachtooka15%annualbasesalary reduction, vicepresidents receiveda12%annualbase salary rollbackandallotheremployees receiveda7.5%annualbasesalaryrollback.

Stock-basedCompensation


($millions) 2020 2019 2020 2019

Cash-settledexpense(recovery) $ 9 $ 5 $ (9)$ (5)

Equity-settledexpense 2 11 7 16

Equitypriceriskmanagementgain(1) $ (19)$ — $ (20)$ —

Stock-basedcompensation $ (8)$ 16 $ (22)$ 11

(1) RelatestofinancialderivativesenteredintotomanagetheCorporation'sexposuretocash-settledRSUsandPSUsvestingin2021, 2022 and 2023 granted under the Corporation's stock-based compensation plans. Amounts are unrealized untilvestingoftherelatedunitsoccurs.SeeRiskManagementsectionofthisMD&Aforfurtherdetails.

TheCorporation'scommonsharepricerecoveredto$3.77pershareasatJune30,2020,fromitsvalueof$1.67pershareasatMarch31,2020,resultingina$9millioncash-settledstock-basedcompensationexpenseduringthethreemonthsendedJune30,2020.

DuringthesixmonthsendedJune30,2020,theCorporation'scommonsharepricedecreased49%to$3.77pershareasatJune30,2020fromitsvalueof$7.39pershareonDecember31,2019primarilyduetotheimpactofCOVID-19oncapitalmarketswhichresultedina$9millioncash-settledstock-basedcompensationrecovery.

Equity-settledstock-basedcompensationexpensedecreased for thethreeandsixmonthsendedJune30,2020,comparedtothesameperiodsof2019,duetoadecreaseinthefairvalueofawardsgrantedinthecurrentperiodandrecoveriesasaresultofreductionsinstaff.EffectiveApril1,2020,adecisionwasmadetoreducethevalueoftarget2020long-termincentiveawardsissuedtoemployeesanddirectorsby20%.

24

ForeignExchangeGain(Loss),Net


($millions) 2020 2019 2020 2019

Unrealizedforeignexchangegain(loss)on:

Long-termdebt $ 116 $ 74 $ (162)$ 154

US$denominatedcashandcashequivalents (2) (7) 9 (9)

Unrealizednetgain(loss)onforeignexchange 114 67 (153) 145

Realizedgain(loss)onforeignexchange 2 2 (1) 3

Foreignexchangegain(loss),net $ 116 $ 69 $ (154)$ 148

C$equivalentof1US$

Beginningofperiod 1.4120 1.3360 1.2965 1.3646

Endofperiod 1.3616 1.3091 1.3616 1.3091

DuringthethreemonthsendedJune30,2020,theCanadiandollarstrengthenedrelativetotheU.S.dollarby4%,resultinginanunrealizedforeignexchangegainof$114million.DuringthethreemonthsendedJune30,2019,theCanadiandollarstrengthenedby2%,resultinginanunrealizedforeignexchangegainof$67million.

During the six months ended June 30, 2020, the Canadian dollar weakened relative to the U.S. dollar by 5%,resultinginanunrealizedforeignexchangelossof$153million.DuringthesixmonthsendedJune30,2019,theCanadiandollarstrengthenedby4%,resultinginanunrealizedforeignexchangegainof$145million.

NetFinanceExpense


($millions) 2020 2019 2020 2019

Interestexpenseonlong-termdebt $ 60 $ 69 $ 124 $ 141

Interestexpenseonleaseliabilities 7 7 13 13

Interestincome — (2) (2) (3)

Netinterestexpense 67 74 135 151

Accretiononprovisions 2 1 4 4 Unrealizedlossonderivativefinancialliabilities — 1 — —

Netfinanceexpense $ 69 $ 76 $ 139 $ 155

Averageeffectiveinterestrate 7.0% 6.6% 6.9% 6.6%

AsaresultoftheseniorsecuredtermloanrepaymentinJuly2019andpartialredemptionsontheCorporation'sseniorsecuredsecondliennotesandseniorunsecurednotesduringthesecondhalfof2019andthefirstquarterof2020,netfinanceexpenseforthethreeandsixmonthsendedJune30,2020decreased,comparedtothesameperiodsof2019.

IncomeTax


($millions) 2020 2019 2020 2019

Incometaxexpense(recovery) $ (62) $ 12 $ (64) $ (34)

Effectivetaxrate 43% (23)% 15% 23%

25

AsatJune30,2020,theCorporationhadapproximately$7.2billionofavailableCanadiantaxpoolsandrecognizedadeferredincometaxassetof$325million.Estimatedfuturetaxableincomeisexpectedtobesufficienttorealizethedeferredincometaxasset.

Theeffectivetaxrateof15%forthesixmonthsendedJune30,2020islowerthantheCanadianstatutoryrateof25%duetothetaxeffectofrealizedandunrealizedforeignexchangelossesontheCorporation'sdebt.

During the three months ended June 30, 2019, the Government of Alberta enacted legislation to reduce thecorporatetaxratefrom12%to8%byJanuary1,2022.Asaresult,theCorporationrecognizedaone-timedeferredincometaxexpenseof$34millionassociatedwiththeratereduction,astheratechangereducedthevalueoftheCorporation'sdeferredtaxassetasat June30,2019.Accelerationof theratechangeto8%by July1,2020wasannouncedduringthesecondquarterof2020andhadnofurtherimpactgiventheCorporation'staxhorizon.TheCorporationdoesnotexpecttopayCanadianincometaxesduringthenextfiveyears.

7. LIQUIDITYANDCAPITALRESOURCES

($millions) June30,2020 December31,2019

SecondLien:

6.5%seniorsecuredsecondliennotes(June30,2020-US$496million;December31,2019-US$596million;due2025) $ 675 $ 773

Unsecured:

7.0%seniorunsecurednotes(June30,2020-US$600million;December31,2019-US$1billion;due2024) 817 1,297

7.125%seniorunsecurednotes(June30,2020-US$1.2billion;December31,2019-US$nil;due2027) 1,634 —

6.375%seniorunsecurednotes(June30,2020-US$nil;December31,2019-US$800million;due2023) — 1,037

Less:

Debtredemptionpremium — 29

Unamortizeddeferreddebtdiscountanddebtissuecosts (30) (13)

Long-termdebt 3,096 3,123

Cashandcashequivalents (120) (206)

Netdebt(1) $ 2,976 $ 2,917

(1) Net debt is reconciled to long-term debt in accordance with IFRS in Note 20 of the interim consolidated financialstatements.

DuringthesixmonthsendedJune30,2020netdebtincreasedby$59millionduetothedecreaseincashandcashequivalents and the weakening of the Canadian dollar relative to the US dollar, partially offset by the partialredemptionofits6.5%seniorsecuredsecondliennotes.

On January 31, 2020 the Corporation successfully closed a private offering of $1.6 billion (US$1.2 billion) inaggregateprincipalamountof7.125%seniorunsecurednotesdueFebruary2027.OnFebruary18,2020,thenetproceedsoftheoffering,togetherwithcashonhand,wereusedto:

• Fully redeem $1 billion (US$800million) of the 6.375% senior unsecured notes due January 2023 at aredemptionpriceof101.063%;

• Partially redeem $530million (US$400million) of the US$1.0 billion 7.0% senior unsecured notes dueMarch2024ataredemptionpriceof102.333%;and

26

• Payfeesandexpensesrelatedtotheoffering.

Concurrent with the private offering, on February 18, 2020, the Corporation redeemed $132 million (US$100million) in aggregate principal amount of its 6.5% senior secured second lien notes due January 2025 at aredemptionpriceof104.875%.

Intotal,$180millionofcashonhandwasusedtofundthepartialredemptionofthesecondliennotes,tofundthecallpremiumsassociatedwiththeredemptionofthe2023and2024notes,andtopaydebtissuecostsassociatedwiththetransactions.

The Corporation's cash and cash equivalents balance was $120million as at June 30, 2020 compared to $206millionasatDecember31,2019.Adjustedfundsflowof$166millionduringthesixmonthsendedJune30,2020wasmore than offset by the repayment of debt and capital expenditures. Refer to the "Cash Flow Summary"sectionforfurtherdetails.

TheCorporationhastotalavailablecreditundertwofacilitiesof$1.3billion,comprisedof$800millionundertherevolvingcreditfacilityand$500millionunderaletterofcreditfacilityguaranteedbyExportDevelopmentCanada("EDCFacility").LettersofcreditundertheEDCfacilitydonotconsumecapacityoftherevolvingcreditfacility.Therevolving credit facility and the EDC Facility have a maturity date of July 30, 2024. The maturity dates of therevolvingcreditfacilityandtheEDCFacilityincludeafeaturethatwouldcausethematuritydatestospringbackto91dayspriortothematuritydateofcertainmaterialdebtoftheCorporationifsuchdebthasnotbeenrepaidorrefinancedprior tosuchdate.Therevolvingcredit facility,EDC facilityandseniorsecuredsecond liennotesaresecuredbysubstantiallyalltheassetsoftheCorporation.

The Corporation continues to proactively respond to the current business environment. The Corporationimplementedadditionalmeasures inthefirstquarterof2020toenhance its financial liquidityposition includingthe reductionof planned capital spendingby$100million, non-energyoperating costs by$20million andG&Acosts by $10million, versus original guidance.Meeting current and future obligations through the uncertaintyassociatedwithCOVID-19issupportedbytheCorporation'sfinancialframeworkincludingastrongcommodityriskmanagementprogramsecuringcashflowthrough2020andcreditriskmanagementpoliciesminimizingexposurerelatedtocustomerreceivablesprimarilytoinvestmentgradecustomersintheenergyindustry.TheCorporation'searliest maturing long-term debt is approximately four years out, represented by US$600 million of seniorunsecured notes due March 2024. None of the Corporation’s outstanding long-term debt contain financialmaintenancecovenants.Additionally,theCorporation'smodifiedcovenant-lite$800millionrevolvingcreditfacilityhasnofinancialmaintenancecovenantunlessdrawninexcessof$400million.Ifdrawninexcessof$400million,theCorporation isrequiredtomaintainaquarterlyfirst liennet leverageratio(first liennetdebtto lasttwelve-monthEBITDA)of3.5orless.UndertheCorporation'screditfacility,firstliennetdebtiscalculatedasdebtunderthecreditfacilityplusotherdebtthatissecuredonaparipassubasiswiththecreditfacility,lesscashonhand.

AsatJune30,2020,theCorporationhad$785millionofunutilizedcapacityunderthe$800millionrevolvingcreditfacilityandtheCorporationhad$63millionofunutilizedcapacityunderthe$500millionEDCfacility.Aletterofcredit of $15millionwas issued under the revolving credit facility during the sixmonths ended June 30, 2020.Letters of credit issuedunder the revolving credit facility arenot included in first liennet debt for purposesofcalculatingthefirstliennetleverageratio.

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.

27

CashFlowSummary


($millions) 2020 2019 2020 2019

Netcashprovidedby(usedin):

Operatingactivities $ 117 $ 302 $ 216 $ 233

Investingactivities (50) (41) (109) (125)

Financingactivities (7) (9) (203) (17)

Effectofexchangeratechangesoncashandcashequivalentsheldinforeigncurrency (2) (7) 10 (10)

Changeincashandcashequivalents $ 58 $ 245 $ (86)$ 81

CashFlow–OperatingActivities

The decrease in net cash provided by operating activities for the three and six months ended June 30, 2020comparedtothesameperiodsof2019isprimarilyduetodecreasedblendsalesasaresultof lowerbenchmarkcrudeoilpricesanddecreasedblendsalesvolumes,partiallyoffsetbyrealizedcommodityriskmanagementgains.

CashFlow–InvestingActivities

NetcashusedininvestingactivitiesincreasedduringthethreemonthsendedJune30,2020comparedtothesameperiodof2019reflectingtimingofworkingcapitalchanges.

NetcashusedininvestingactivitiesdecreasedduringthesixmonthsendedJune30,2020comparedtothesameperiodof2019whichalignswiththeCorporation'sreducedcapitalspending.

CashFlow–FinancingActivities

NetcashusedinfinancingactivitiesincreasedduringthesixmonthsendedJune30,2020comparedtothesameperiodof2019primarilyduetotheredemptionofaportionofthe6.5%seniorsecuredsecondliennotestotaling$132million(US$100million).Also,debtredemptionpremiumsandotherrefinancingcostswereincurredrelatedtotheJanuary31,2020refinancing.

8. RISKMANAGEMENT

CommodityPriceRiskManagement

Tomitigate theCorporation’s exposure to fluctuations in commodityprices, theCorporationperiodically entersinto financial commodity risk management contracts to partially manage its exposure on blend sales andcondensate purchases. The Corporation also periodically enters into physical delivery contracts which are notconsidered financial instruments and therefore no asset or liability has been recognized in the ConsolidatedBalanceSheetrelatedtothesecontracts.TheimpactofrealizedphysicaldeliverycontractpricesisincludedintheConsolidatedStatementofEarnings(Loss)andComprehensiveIncome(Loss)andincashoperatingnetback.

28

TheCorporationhadthefollowingfinancialcommodityriskmanagementcontractsrelatingtocrudeoilsalesandcondensatepurchasesoutstandingasatJune30,2020:

AsatJune30,2020Volumes(bbls/d)(1) Term

AveragePrice(US$/bbl)(1)

CrudeOilSalesContracts

WTIFixedPrice 47,042 Jul1,2020-Dec31,2020 $47.70

WTI:WCSFixedDifferential 24,500 Jul1,2020-Dec31,2020 $(20.46)

WTI:WCS(USGC)FixedDifferential 1,000 Aug1,2020-Aug31,2020 $(3.95)

EnhancedFixedPricewithSoldPutOption

WTIFixedPrice/SoldPutOptionStrikePrice 20,685 Jul1,2020-Dec31,2020 $59.22/$52.00

CondensatePurchaseContracts

WTI:MontBelvieuFixedDifferential 7,250 Jul1,2020-Dec31,2020 $(7.63)

WTI:MontBelvieuFixedDifferential 10,950 Jan1,2021-Dec31,2021 $(10.37)

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

WTI:MontBelvieuFixed%ofWTI 7,750 Jul1,2020-Dec31,2020 93.1%

(1) Thevolumes,pricesandpercentagesintheabovetablerepresentaveragesforvariouscontractswithdifferingtermsandprices. The average price and percentages for the portfolio may not have the same payment profile as the individualcontractsandareprovidedforindicativepurposes.

TheCorporationentered intothefollowingfinancialcommodityriskmanagementcontractsrelatingtocrudeoilsalesbetweenJune30,2020andJuly27,2020:

SubsequenttoJune30,2020Volumes(bbls/d)(1) Term


CrudeOilSales(Purchase)Contracts

WTIFixedPrice 25,250 Aug1,2020-Aug31,2020 $40.57

WTIFixedPrice 6,370 Oct1,2020-Dec31,2020 $41.45

(1) The volumes and prices in the above table represent averages for various contractswith differing terms and prices. Theaveragepriceandpercentagesfortheportfoliomaynothavethesamepaymentprofileastheindividualcontractsandareprovidedforindicativepurposes.

Thefollowingtablesummarizesthesensitivityofcashoperatingnetback,adjustedfundsflowandearnings(loss)before income tax of fluctuating commodity prices on the Corporation’s open financial commodity riskmanagementpositionsinplaceasatJune30,2020:

Commodity SensitivityRange Increase Decrease

Crudeoilcommodityprice ±US$5.00perbblappliedtoWTIcontracts $ (63)$ 60

Crudeoildifferentialprice(1) ±US$5.00perbblappliedtoWTI:WCSdifferentialcontracts $ 31 $ (31)

(1) AstheWCSdifferentialisexpressedasadiscounttoWTI,anincreaseinthedifferentialresultsinalowerWCSpriceandadecreaseinthedifferentialresultsinahigherWCSprice.

29

The Corporation had the following physical commodity risk management contracts relating to crude oil sales,condensatepurchasesandnaturalgaspurchasesoutstandingasatJune30,2020:

AsatJune30,2020Volumes(bbls/d)(1) Term



WTI:AWBFixedDifferential 13,150 Jul1,2020-Dec31,2020 (20.75)

WTI:AWBFixedDifferentialatUSGC 11,370 Jul1,2020-Sep30,2020 (4.11)


WTI:CondensateFixedDifferential 8,200 Jul1,2020-Dec31,2020 (5.31)

(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-basedcompensationplans,arerevaluedeachperiodbasedontheCorporation’sshareprice.Netcashprovidedby(usedin) operating activities is impacted when these stock-based compensation units are ultimately settled. TheCorporationentersintotheseequitypriceriskmanagementcontractstomanageitsexposureonapproximately9millioncash-settledRSUsandPSUsvestingbetween2021and2023.

9. SHARESOUTSTANDING

AsatJune30,2020,theCorporationhadthefollowingsharecapitalinstrumentsoutstandingorexercisable:

(millions) Units

Commonshares 302.6

Convertiblesecurities

Stockoptions(1) 5.3

Equity-settledRSUsandPSUs 7.3

(1) 4.6millionstockoptionswereexercisableasatJune30,2020.

Asat July25,2020, theCorporationhad302.6millioncommonshares,5.3millionstockoptionsand7.0millionequity-settledrestrictedshareunitsandequity-settledperformanceshareunitsoutstanding,and4.6millionstockoptionsexercisable.

10. CONTRACTUALOBLIGATIONS,COMMITMENTSANDCONTINGENCIES

ContractualObligationsandCommitments

Theinformationpresentedinthetablebelowreflectsmanagement’sestimateofthecontractualmaturitiesoftheCorporation’sobligationsasatJune30,2020.Thesematuritiesmaydiffersignificantlyfromtheactualmaturitiesof theseobligations. Inparticular,debtunder theseniorsecuredcredit facilities, theseniorsecuredsecond liennotes,and the seniorunsecurednotesmaybe retiredearlierdue tomandatoryordiscretionary repaymentsorredemptions.

30

($millions) 2020 2021 2022 2023 2024 Thereafter TotalCommitments:Transportationandstorage(1) $ 215 $ 436 $ 425 $ 467 $ 452 $ 6,046 $ 8,041Diluentpurchases 70 22 22 18 — — 132Otheroperatingcommitments 8 15 14 13 11 45 106Variableofficeleasecosts 2 4 4 4 5 30 49Capitalcommitments 1 — — — — — 1TotalCommitments 296 477 465 502 468 6,121 8,329OtherObligations:Leaseobligations 23 47 38 32 32 520 692Long-termdebt(2) — — — — 817 2,309 3,126Interestonlong-termdebt(2) 144 218 218 218 174 250 1,222Decommissioningobligation(3) 1 5 5 5 5 789 810TotalCommitmentsandObligations $ 464 $ 747 $ 726 $ 757 $ 1,496 $ 9,989 $ 14,179

(1) This represents transportationand storage commitments from2020 to2048, includingpipeline commitmentswhichareawaiting regulatoryapprovalandarenotyet in service.Excludes finance leases recognizedon theconsolidatedbalancesheet.

(2) Thisrepresentsthescheduledprincipalrepaymentsoftheseniorsecuredsecondliennotes,theseniorunsecurednotes,andassociatedinterestpaymentsbasedoninterestandforeignexchangeratesineffectonJune30,2020.

(3) ThisrepresentstheundiscountedfutureobligationsassociatedwiththedecommissioningoftheCorporation’sassets.

Contingencies

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

The Corporation is 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.TheCorporationcontinuestoviewthisclaimaswithoutmeritandwillcontinuetodefendagainstthisclaim.TheCorporationbelievesthatanyliabilitiesthatmightarisefromthismatterareunlikelytohaveamaterialeffectonitsfinancialposition.

11. 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.

Cashoperatingnetbackisanon-GAAPmeasurewidelyusedintheoilandgasindustryasasupplementalmeasureof a company’s efficiency and its ability to fund future capital expenditures. The Corporation’s cash operatingnetbackiscalculatedbydeductingtherelatedcostofdiluent,blendpurchases,transportationandstorage,third-partycurtailmentcredits,operatingexpenses,royaltiesandrealizedcommodityriskmanagementgainsorlossesfromblendsalesandpower revenue.Theperbarrel calculationof cashoperatingnetback isbasedonbitumensalesvolume.

12. 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,assumptionsand

31

judgmentsusedbytheCorporationcanbefoundintheCorporation'sannualconsolidatedfinancialstatementsfortheyearendedDecember31,2019.

InMarch 2020, theWorld HealthOrganization declared a global pandemic following the emergence and rapidspreadofanovelstrainofcoronavirus ("COVID-19"). Theoutbreakandsubsequentmeasures intendedto limitCOVID-19 globally have contributed to significant declines and volatility in capital and financial markets, andadversely impacted the global commoditymarket,most notably thedramatic decline inworldwidedemand forcrudeoil.TherearenocomparablerecenteventsthatprovideguidanceastothelongtermeffectthatCOVID-19mayhave,includingcontinuingglobaleffortstocontainthespreadandseverityofthevirus,andasaresult,theultimate impact of the outbreak is highly uncertain and subject to change. The full extent of the impact ofCOVID-19ontheCorporation’soperationsandfuturefinancialperformanceiscurrentlyunknown.Thecontinuedimpact on capital and financial markets on a macro-scale presents uncertainty and risk with respect to theCorporation’s performance, and the estimates and assumptions used byManagement in the preparation of itsfinancialresults.

Additional estimates, assumptions and judgments in response to COVID-19 have been disclosed in the interimconsolidatedfinancialstatementsasatJune30,2020regardingvaluationassessmentsrelatedtotheCorporation'sinventories, property, plant and equipment, exploration and evaluation assets, long-term pipeline linefill,decommissioningprovisionanddeferredincometaxasset.

13. 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.

RiskrelatedtoCOVID-19GlobalPandemic

TheCorporation'soperations,operatingresultsandfinancialconditioncouldbemateriallyadverselyimpactedbyeventsrelatedtoCOVID-19andactionstakenbygovernmentauthoritiesinresponsetoCOVID-19.COVID-19hasresultedin,andmaycontinuetoresultin,amongotherthings:increasedvolatilityinfinancialmarketsandforeigncurrency exchange rates; disruptions to global supply chains; labour shortages; reductions in trade volumes;temporary operational restrictions and restrictions on gatherings greater than a certain number of individuals,shelterinplacedeclarationsandquarantineorders,businessclosuresandtravelbans;anoverallslowdownintheglobaleconomy;politicalandeconomicinstability;andcivilunrest. Inparticular,COVID-19,andactionstakenbygovernmentalauthoritiesinresponsethereto,haveresultedin,andmaycontinuetoresultin,areductioninthedemand for oil and reduced oil prices. Also, there is an increased risk that oil storage could reach capacity inCanadaand theUSGCas a result of thedecreaseddemand.Aprolongedperiodofdecreaseddemand for, andlowerpricesofcrudeoil,andanyapplicablestorageconstraints,couldalsoresult in theCorporationvoluntarilycurtailingorshutting-inproduction,whichcouldadverselyimpactourbusiness,financialconditionandresultsofoperations.

Ifcrudeoilpricescontinuetoremainatlowlevelsforanextendedperiodoftime,orifthecoststodeveloptheCorporation’sresourcessignificantlyincreases,thecarryingvalueofitsassetsmaybesubjecttoimpairmentandnetearningscouldbeadverselyaffected.

TheCorporation is subject to risks relating to a temporary suspensionor physical interruptionof its operationsimpactedbyaCOVID-19outbreak,particularlyattheCorporation’ssoleoperatingfacilityatChristinaLake.IntheeventanemployeeorcontractorattheCorporation’sChristinaLakesitebecomesinfectedwithCOVID-19,itcouldplace theCorporation’sentire siteworkforceat risk,whichcould result in the suspensionofoperations. Suchasuspension in operations could also be mandated by governmental authorities in response to COVID-19. This

32



wouldhaveasignificantnegativeimpacton,orshut-downof,theCorporation’sproductionlevels,potentiallyforasustainedperiodoftime,whichcouldadverselyimpactourbusiness,financialconditionandresultsofoperations.

Inaddition, thedisruptionandvolatility inglobal capitalmarkets thathas resulted,andmaycontinue to result,fromCOVID-19couldincreaseourcostofcapitalandadverselyaffectourabilitytoaccessthecapitalmarketsonatimelybasis,oratall.

COVID-19continuestorapidlyevolveandtheextenttowhichitmayimpactourbusiness,financialconditionandresults of operations, as well as our future capital expenditures and other discretionary items, will depend onfuture developments, which are highly uncertain and cannot be predicted with any degree of confidence,including: thegeographicspreadof thevirus; thedurationandextentofCOVID-19, furtheractions thatmaybetakenbygovernmentalauthorities,includinginrespectoftravelrestrictionsandbusinessdisruptions;theseverityofthedisease;itsimpactonhealthcaresystemstomanageincreasesinpatients;andtheeffectivenessofactionstaken to contain the virus and treat the disease. To the extent that COVID-19 adversely affects our business,financial conditionand resultsofoperations, itmayalsohave theeffectofheighteningmanyof theother risksdescribedinthe2019annualMD&AandthemostrecentlyfiledAIF.

14. 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,particularly during the period in which the interim and annual filings are being prepared; and (ii) informationrequiredtobedisclosedbytheCorporationinitsannualfilings,interimfilingsorotherreportsfiledorsubmittedbyitundersecuritieslegislationisrecorded,processed,summarizedandreportedwithinthetimeperiodspecifiedinsecuritieslegislation.

15. 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.

Inmid-March2020,inaccordancewiththeguidanceofprovincialandfederalhealthofficialsandtolimittheriskand transmission of COVID-19, the Corporation implemented mandatory self-quarantine policies, travelrestrictions,enhancedcleaningand sanitationmeasures, and socialdistancingmeasures, includingdirecting thevastmajorityofitsofficestaffandcertainnon-essentialfieldstafftoworkfromhome.Monitoringthesemeasuresis an ongoing process, and the Corporation continues to follow the guidance of provincial and federal healthofficials, including the province's phased recovery plan. These changes to processes have not resulted in anymaterialchangestotheinternalcontrolsoverfinancialreporting.

33

16. 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

GAAP GenerallyAcceptedAccountingPrinciples

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

17. 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 aboutfutureoutcomes, includingbutnot limitedto:expectationsof futureproduction,revenues,expenses,cashflow,operatingcosts,steam-oilratios,pricingdifferentials,reliability,profitabilityandcapitalexpenditures;estimatesofreserves and resources; anticipated reductions in operating costs as a result of optimization and scalability ofcertain operations; anticipated sources of funding for operations and capital expenditures; and anticipatedregulatoryapprovals.Suchforward-lookinginformationisbasedonmanagement'sexpectationsandassumptionsregarding future growth, results of operations, production, future capital and other expenditures, competitiveadvantage, plans for and results of drilling activity, environmental matters, and business prospects andopportunities.

Forward-lookinginformationcontainedinthisdocumentisbasedonmanagement'sexpectationsandassumptionsregarding, among other things: future crude oil, bitumen blend, natural gas, electricity, condensate and otherdiluent prices, foreign exchange rates and interest rates; the recoverability of MEG's reserves and contingentresources;MEG'sabilitytoproduceandmarketproductionofbitumenblendsuccessfullytocustomers;extentandtimelines of the Alberta Government’s mandatory production curtailment program, future growth, results ofoperations and production levels; future capital and other expenditures; revenues, expenses and cash flow;

34

operating costs; reliability; continued liquidity and runway to sustain operations through a prolonged marketdownturn; ability to reduce oil sands production, including without negative impacts to its assets; anticipatedreductionsinoperatingcostsasaresultofoptimizationandscalabilityofcertainoperations;anticipatedsourcesoffunding foroperationsand capital investments;plans for and resultsofdrillingactivity;plans for and resultsofturnaround activity; the regulatory framework governing royalties, land use, taxes and environmentalmatters,including the timing and level of governmentproduction curtailment and federal andprovincial climate changepolicies, inwhichMEG conducts andwill conduct its business; the impact ofMEG’s response to the COVID-19global pandemic; and business prospects and opportunities. By its nature, such forward-looking informationinvolves significant known and unknown risks and uncertainties, which could cause actual results to differmateriallyfromthoseanticipated.

By itsnature,such forward-looking information involvessignificantknownandunknownrisksanduncertainties,whichcouldcauseactualresultstodiffermateriallyfromthoseanticipated.Theserisksanduncertaintiesinclude,butarenotlimitedtorisksanduncertaintiesrelatedto:theoilandgasindustry,forexample,securingaccesstomarkets and transportation infrastructure (including pipelines and rail) and the commitments therein; theavailabilityofcapacityontheelectricitytransmissiongrid;theuncertaintyofreserveandresourceestimates;theuncertainty of estimates and projections relating to production, costs and revenues; health, safety andenvironmental risks; legislative and regulatory changes to, amongst other things, tax, land use, royalty andenvironmental laws and production curtailment; assumptions regarding and the volatility of commodity prices,interestratesandforeignexchangerates;commodityprice,interestrateandforeignexchangerateswapcontractsand/orderivativefinancial instrumentsthattheCorporationmayenterintofromtimetotimetomanageitsriskrelated to such prices and rates; timing of completion, commissioning, and start-up, of the Corporation’sturnarounds;theoperationalrisksanddelaysinthedevelopment,exploration,production,andthecapacitiesandperformanceassociatedwiththeCorporation'sprojects;theCorporation’sabilitytoreduceorincreaseproductiontodesired levels; theCorporation’sability to financesustainingcapitalexpenditures; theCorporation’sability tomaintainsufficientliquiditytosustainoperationsthroughaprolongedmarketdownturn;changesincreditratingsapplicabletotheCorporationoranyofitssecurities;theCorporation’sresponsetotheCOVID-19globalpandemic;the severity and duration of the COVID-19 pandemic; the potential for a temporary suspension of operationsimpacted by an outbreak of COVID-19; continued weakness and volatility of crude oil and other petroleumproductsduetodecreasedglobaldemandduetotheCOVID-19pandemic;changesingeneraleconomic,marketandbusinessconditions;thepotentialcostsassociatedwithongoing litigationcases;theextentandtimelinesoftheAlbertaGovernment'smandatoryproductioncurtailmentprogram;risksoflegislativeandregulatorychangesto,amongstotherthings,tax,landuse,royaltyandenvironmentallawsandFederalandProvincialclimatechangepolicies;thecostofcompliancewithcurrentandfutureenvironmental laws, includingclimatechangelaws;risksrelated to increasedactivismandpublicopposition to fossil fuels andoil sands; assumptions regarding and thevolatilityof commodityprices, interest rates and foreignexchange rates, and, risks anduncertainties related tocommodityprice, interestrateandforeignexchangerateswapcontractsand/orderivativefinancial instrumentsthat theCorporationmayenter into from time to time tomanage its risk related to suchpricesand rates; anduncertaintiesarisinginconnectionwithanyfutureacquisitionsand/ordispositionsofassets.

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.

35


MEGEnergy Corp. is an energy company focused on sustainable in situ thermal oil production in the southernAthabasca region of Alberta, Canada. The Corporation is actively developing innovative enhanced oil recoveryprojectsthatutilizeSAGDextractionmethodstoimprovetheresponsibleeconomicrecoveryofoilaswellaslowercarbonemissions.MEGtransportsandsells itsthermaloilproductiontorefinersthroughoutNorthAmericaandinternationally. The Corporation's common shares are listed on the Toronto Stock Exchange under the symbol"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.

18. ADDITIONALINFORMATION

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

36



19. QUARTERLYSUMMARIES

2020 2019 2018(1)

Unaudited Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3

FINANCIAL($millionsunlessspecified)

Netearnings(loss) (80) (284) 26 24 (64) (48) (199) 118

Pershare,diluted (0.26) (0.95) 0.09 0.08 (0.21) (0.16) (0.67) 0.39

Adjustedfundsflow 89 78 157 192 227 151 (37) 116

Pershare,diluted 0.29 0.26 0.51 0.63 0.76 0.50 (0.13) 0.39

Capitalexpenditures 20 54 72 40 33 53 144 139

Cashandcashequivalents 120 62 206 154 399 154 318 373

Workingcapital 173 371 123 204 416 175 290 274

Long-termdebt 3,096 3,212 3,123 3,257 3,582 3,660 3,740 3,544

Shareholders'equity 3,507 3,593 3,853 3,828 3,795 3,851 3,886 4,068

BUSINESSENVIRONMENT

AverageBenchmarkCommodityPrices:

WTI(US$/bbl) 27.85 46.17 56.96 56.45 59.82 54.90 58.81 69.50

Differential–WTI:WCS–Edmonton(US$/bbl) (11.47) (20.53) (15.83) (12.24) (10.67) (12.29) (39.43) (22.25)

Differential–WTI:AWB–Edmonton(US$/bbl) (13.44) (22.78) (18.44) (14.52) (12.32) (14.50) (44.60) (25.69)

AWB–Edmonton(US$/bbl) 14.41 23.39 38.52 41.93 47.50 40.40 14.21 43.81

Differential–WTI:AWB–U.S.GulfCoast(US$/bbl) (7.29) (5.74) (5.25) (2.50) 1.64 (0.89) (6.25) (5.63)

AWB–U.S.GulfCoast(US$/bbl) 20.56 40.43 51.71 53.95 61.46 54.01 52.56 63.87

C$equivalentof1US$–average 1.3860 1.3445 1.3201 1.3207 1.3376 1.3293 1.3215 1.3070

Naturalgas–AECO($/mcf) 2.21 2.26 2.70 0.95 1.12 2.86 1.70 1.28

OPERATIONAL($/bblunlessspecified)

Blendsales,netofpurchasedproduct–bbls/d 100,980 142,380 134,932 132,455 137,120 132,377 126,750 130,823

Diluentusage–bbls/d (30,583) (45,166) (40,585) (37,463) (42,000) (42,555) (38,467) (36,967)

Bitumensales–bbls/d 70,397 97,214 94,347 94,992 95,120 89,822 88,283 93,856

Bitumenproduction–bbls/d 75,687 91,557 94,566 93,278 97,288 87,113 87,582 98,751

Steam-oilratio(SOR) 2.32 2.31 2.27 2.26 2.16 2.20 2.22 2.17

Blendsales 20.96 36.46 56.55 60.26 69.19 59.02 37.76 63.68

Costofdiluent (10.78) (17.01) (9.69) (6.89) (6.96) (8.81) (22.45) (14.05)

Bitumenrealization 10.18 19.45 46.86 53.37 62.23 50.21 15.31 49.63

Transportationandstorage–net (11.77) (8.63) (10.75) (10.57) (10.80) (11.27) (10.28) (9.11)

Third-partycurtailmentcredits — 0.18 (0.21) (0.37) (0.89) — — —

Royalties (0.05) (0.63) (1.18) (1.54) (2.06) (0.37) (0.15) (2.01)

Operatingcosts–non-energy (4.09) (4.57) (4.49) (4.22) (4.53) (5.22) (4.25) (4.38)

Operatingcosts–energy (3.00) (3.15) (2.95) (1.51) (1.78) (3.36) (1.98) (1.50)

Powerrevenue 0.95 2.21 1.57 1.43 1.65 2.41 1.68 1.54

ReRealizedgain(loss)oncommodityriskmanagement 33.62 11.97 (0.52) (4.15) (5.94) (2.60) 6.81 (10.16)

Cashoperatingnetback 25.84 16.83 28.33 32.44 37.88 29.80 7.14 24.01

Powersalesprice(C$/MWh) 28.34 69.39 49.61 50.30 55.33 70.83 55.38 51.53

Powersales(MW/h) 98 129 124 112 118 128 111 117

Averagecostofdiluent($/bblofdiluent) 45.76 73.09 79.07 77.71 84.95 77.61 89.28 99.37

Averagecostofdiluentasa%ofWTI 119% 118% 105% 104% 106% 106% 115% 109%

Depletionanddepreciationrateperbblofproduction 13.55 14.83 13.18 13.43 41.22 14.68 13.79 13.85

Generalandadministrativeexpenseperbblofproduction 1.29 1.96 2.25 1.66 1.81 2.27 2.54 2.35

COMMONSHARES

Sharesoutstanding,endofperiod(000) 302,645 299,547 299,508 299,288 299,207 296,857 296,841 296,813

Commonshareprice($)-close(endofperiod) 3.77 1.67 7.39 5.80 5.02 5.10 7.71 8.03

(1) TheCorporationadoptedIFRS16Leases,effectiveJanuary1,2019,thereforepriorperiodshavenotbeenrestated.

37

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

• fluctuationsinblendsalespricingduetosignificantchangesinthepriceofWTIwithperiodsofsignificantvolatility in2020,whichhasrangedfromaquarterlyaverageofUS$27.85/bbltoUS$69.50/bbl,andthedifferential betweenWTI and theCorporation'sAWBat Edmonton,whichhas ranged fromaquarterlyaverageofUS$12.32/bbltoUS$44.60/bbldrivenbysupply/demandfundamentals;

• in early March 2020, and continuing into the second quarter of 2020, global crude oil prices startedexperiencing multi-decade lows coupled with extreme levels of volatility driven primarily by anunprecedentedreductioninglobaldemanddueCOVID-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;

• adecreaseingeneralandadministrativeexpenseduetoreductioninstaffinglevels;

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

• plannedturnaroundandothermaintenanceactivitiesaffectingproduction;and

• voluntarycurtailmenteffortsassociatedwithuneconomicbenchmarkpricingenvironments.

38

20. ANNUALSUMMARIES

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

FINANCIAL($millionsunlessspecified)

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

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

Adjustedfundsflow 726 180 374 (62) 49 791

Pershare,diluted 2.41 0.60 1.29 (0.27) 0.22 3.52

Capitalexpenditures 198 622 502 140 314 1,314

Cashandcashequivalents 206 318 464 156 408 656

Workingcapital 123 290 313 96 363 526

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

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

BUSINESSENVIRONMENT

AverageBenchmarkCommodityPrices:

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

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

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

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

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

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

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

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

OPERATIONAL($/bblunlessspecified)

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

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

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

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

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

Blendsales 61.29 53.47 51.39 38.19 42.14 76.11

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

Bitumenrealization 53.21 36.69 42.03 27.91 30.71 62.76

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

Third-partycurtailmentcredits (0.37) — — — — —

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

Operatingcosts–non-energy (4.61) (4.62) (4.62) (5.62) (6.54) (8.02)

Operatingcosts–energy (2.38) (1.98) (2.98) (3.01) (3.84) (6.30)

Powerrevenue 1.75 1.51 0.76 0.64 0.99 2.26

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

Cashoperatingnetback 32.15 17.61 27.14 13.25 15.80 44.96

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

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

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

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

COMMONSHARES

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

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

(1) TheCorporationadoptedIFRS16Leases,effectiveJanuary1,2019,thereforepriorperiodshavenotbeenrestated.

39

ConsolidatedBalanceSheet(Unaudited,expressedinmillionsofCanadiandollars)

Asat Note June30,2020 December31,2019AssetsCurrentassetsCashandcashequivalents 17 $ 120 $ 206Tradereceivablesandother 233 382Inventories 3 80 93Riskmanagement 19 90 —

523 681Non-currentassetsProperty,plantandequipment 4 6,078 6,206Explorationandevaluationassets 5 124 490Otherassets 6 214 227Riskmanagement 19 24 —Deferredincometaxasset 7 325 262

Totalassets $ 7,288 $ 7,866

LiabilitiesCurrentliabilitiesAccountspayableandaccruedliabilities $ 226 $ 379Interestpayable 83 74Currentportionofprovisionsandotherliabilities 9 31 28Riskmanagement 19 10 77

350 558Non-currentliabilitiesLong-termdebt 8 3,096 3,123Provisionsandotherliabilities 9 335 332Riskmanagement 19 — —

Totalliabilities 3,781 4,013Shareholders’equitySharecapital 10 5,460 5,443Contributedsurplus 173 182Deficit (2,165) (1,801)Accumulatedothercomprehensiveincome 39 29

Totalshareholders’equity 3,507 3,853Totalliabilitiesandshareholders’equity $ 7,288 $ 7,866

Commitmentsandcontingencies(Note21)

TheaccompanyingnotesareanintegralpartoftheseInterimConsolidatedFinancialStatements.

40

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


Note 2020 2019 2020 2019

Revenues

Petroleumrevenue,netofroyalties 12 $ 299 $ 1,044 $ 941 $ 1,940

Otherrevenue 12 8 17 31 40

Totalrevenues 307 1,061 972 1,980

Expenses

Diluentandtransportation 13 205 421 585 813

Operatingexpenses 46 54 114 124

Inventoryimpairment(realized) 3 (29) — — —

Purchasedproduct 106 199 282 394

Third-partycurtailmentcredits — 8 (2) 8

Depletionanddepreciation 4,6 93 365 217 480

Explorationexpense 5 — 58 366 58

Generalandadministrative 9 16 25 34

Stock-basedcompensation 11 (8) 16 (22) 11

Netfinanceexpense 15 69 76 139 155

Otherexpenses 16 22 7 30 16

Gainonassetdispositions 6 — (2) (6) (14)

Commodityriskmanagement(gain)loss,net 19 52 (36) (482) 194

Foreignexchange(gain)loss,net 14 (116) (69) 154 (148)

Lossbeforeincometaxes (142) (52) (428) (145)

Incometaxexpense(recovery) (62) 12 (64) (34)

Netloss (80) (64) (364) (111)

Othercomprehensiveincome(loss),netoftax

Itemsthatmaybereclassifiedtoprofitorloss:

Foreigncurrencytranslationadjustment (8) (4) 10 (8)

Comprehensiveloss $ (88)$ (68)$ (354)$ (119)

Netlosspercommonshare

Basic 18 $ (0.26)$ (0.21)$ (1.21)$ (0.37)

Diluted 18 $ (0.26)$ (0.21)$ (1.21)$ (0.37)


41

ConsolidatedStatementofChangesinShareholders’Equity(Unaudited,expressedinmillionsofCanadiandollars)

ShareCapitalContributed

Surplus Deficit

AccumulatedOther

ComprehensiveIncome

TotalShareholders’

Equity

BalanceasatDecember31,2019 $ 5,443 $ 182 $ (1,801) $ 29 $ 3,853

Stock-basedcompensation — 8 — — 8

RSUsvestedandreleased 17 (17) — — —

Comprehensiveincome(loss) — — (364) 10 (354)

BalanceasatJune30,2020 $ 5,460 $ 173 $ (2,165) $ 39 $ 3,507

BalanceasatDecember31,2018 $ 5,427 $ 170 $ (1,751) $ 39 $ 3,885

IFRS16openingdeficitadjustment — — 12 — 12

Stock-basedcompensation — 17 — — 17

RSUsvestedandreleased 14 (14) — — —

Comprehensiveincome(loss) — — (111) (8) (119)

BalanceasatJune30,2019 $ 5,441 $ 173 $ (1,850) $ 31 $ 3,795


42

ConsolidatedStatementofCashFlow(Unaudited,expressedinmillionsofCanadiandollars)


Note 2020 2019 2020 2019

Cashprovidedby(usedin):

Operatingactivities

Netloss $ (80)$ (64)$ (364)$ (111)

Adjustmentsfor:

Deferredincometaxexpense(recovery) (61) 12 (63) (34)

Inventoryimpairment(realized) 3 (29) — — —

Depletionanddepreciation 4,6 93 365 217 480

Explorationexpense 5 — 58 366 58

Stock-basedcompensation 11 (17) 11 (13) 16

Unrealizednet(gain)lossonforeignexchange 14 (114) (67) 153 (145)Unrealizednet(gain)lossoncommodityriskmanagement 19 267 (87) (161) 122Amortizationofdebtdiscountanddebtissuecosts 2 3 4 9

Gainonassetdispositions 6 — (2) (6) (14)

Other 2 2 4 4

Decommissioningexpenditures 9 — — (2) —

Netchangeinotherliabilities 6 (4) 3 (7)Fundsflowfromoperatingactivities 69 227 138 378

Netchangeinnon-cashworkingcapitalitems 17 48 75 78 (145)

Netcashprovidedby(usedin)operatingactivities 117 302 216 233

Investingactivities

Capitalexpenditures 4 (20) (32) (74) (85)

Netproceedsondispositions 6 — 5 6 17

Netchangeinnon-cashworkingcapitalitems 17 (30) (14) (41) (57)

Netcashprovidedby(usedin)investingactivities (50) (41) (109) (125)

Financingactivities

Issueof7.125%seniorunsecurednotes 8 — — 1,581 —

Repaymentandredemptionoflong-termdebt 8 — (4) (1,723) (8)

Debtredemptionpremiumandrefinancingcosts 8 (1) — (49) —

Receiptsonleasedassets 17 1 — 1 —

Paymentsonleasedliabilities 17 (7) (5) (13) (9)

Netcashprovidedby(usedin)financingactivities (7) (9) (203) (17)

Effectofexchangeratechangesoncashandcashequivalentsheldinforeigncurrency (2) (7) 10 (10)

Changeincashandcashequivalents 58 245 (86) 81

Cashandcashequivalents,beginningofperiod 62 154 206 318

Cashandcashequivalents,endofperiod $ 120 $ 399 $ 120 $ 399


43

1. CORPORATEINFORMATION

MEGEnergyCorp.(the"Corporation")wasincorporatedundertheAlbertaBusinessCorporationsActonMarch9,1999.TheCorporation'ssharestradeontheTorontoStockExchangeunderthesymbol"MEG".TheCorporationownsa100%interestinover700squaremilesofmineralleasesinthesouthernAthabascaregionofAlbertaandisprimarilyengagedinsustainableinsituthermaloilproductionatitsChristinaLakeProject.

Thecorporateofficeislocatedat600–3rdAvenueSW,Calgary,Alberta,Canada.

2. BASISOFPRESENTATION

The unaudited interim consolidated financial statements (“interim consolidated financial statements”) werepreparedusingthesameaccountingpoliciesandmethodsasthoseusedintheCorporation’sauditedconsolidatedfinancialstatementsfortheyearendedDecember31,2019.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, 2019. These interim consolidated financial statements should be read in conjunctionwiththeCorporation’sauditedconsolidatedfinancialstatementsfortheyearendedDecember31,2019.

InMarch 2020, theWorld HealthOrganization declared a global pandemic following the emergence and rapidspreadofanovelstrainofcoronavirus ("COVID-19"). Theoutbreakandsubsequentmeasures intendedto limitCOVID-19globallycontributedtosignificantdeclinesandvolatilityincapitalandfinancialmarkets,andadverselyimpactedglobalcommoditymarkets,mostnotablythedramaticdeclineinworldwidedemandforcrudeoil.Thereare no comparable recent events that provide guidance as to the long term effect that COVID-19 may have,includingglobaleffortstocontainthespreadandseverityofthevirus.

The full extent of the impact of COVID-19 on the Corporation’s operations and future financial performance iscurrentlyunknown.Thecontinuedimpactoncapitalandfinancialmarketsonamacro-scalepresentsuncertaintyandriskwithrespecttotheCorporation'sperformance,andestimatesandassumptionsusedinthepreparationofitsfinancialresults.

Additionalestimates,assumptionsand judgments inresponsetoCOVID-19havebeendisclosed inthese interimconsolidated financial statements regarding valuation assessments related to the Corporation's inventories,property, plant and equipment, exploration and evaluation assets, long-term pipeline linefill, decommissioningprovisionanddeferredincometaxasset.

These interim consolidated financial statements are presented in Canadian dollars ($ or C$), which is theCorporation’sfunctionalcurrencyandwereapprovedbytheCorporation’sAuditCommitteeonJuly27,2020.

3. INVENTORIES

Asat June30,2020 December31,2019

Bitumenblend $ 66 $ 73

Diluent 6 13

Materialandsupplies 8 7

$ 80 $ 93

NOTESTOTHEINTERIMCONSOLIDATEDFINANCIALSTATEMENTSAllamountsareexpressedinmillionsofCanadiandollarsunlessotherwisenoted.(Unaudited)

44

Inventoriesaremeasuredatthelowerofcostandnetrealizablevalue.Inlightofthesignificantandacutedeclinein commoditypricesassociatedwith theCOVID–19globalpandemic,non-cash inventory impairment chargesof$19million and$10million, respectively,were recordedatMarch31, 2020 related to theestimateddecline invalueoftheCorporation’sbitumenblendanddiluentvolumesheldininventoryattheendofthefirstquarter.Therelated inventories were sold during the three months ended June 30, 2020 and the resulting cash impactassociatedwiththeimpairmentchargeswasrealizedthroughvariousexpenses.NoinventoryimpairmentswererecognizedatJune30,2020.

4. PROPERTY,PLANTANDEQUIPMENT

CrudeoilTransportation

andstorageRight-of-use

assetsCorporate

assets TotalCostBalanceasatDecember31,2019 $ 9,077 $ 159 $ 263 $ 78 $ 9,577Additions 75 1 26 — 102Dispositions (2) (71) — — (73)Leasemodification — — (2) — (2)Changeindecommissioningliabilities (6) — — — (6)BalanceasatJune30,2020 $ 9,144 $ 89 $ 287 $ 78 $ 9,598

Accumulateddepletionanddepreciation

BalanceasatDecember31,2019 $ 3,199 $ 102 $ 25 $ 45 $ 3,371Depletionanddepreciation 202 — 12 3 217Dispositions (3) (70) — — (73)Leasemodification — — 5 — 5BalanceasatJune30,2020 $ 3,398 $ 32 $ 42 $ 48 $ 3,520

CarryingamountsBalanceasatDecember31,2019 $ 5,878 $ 57 $ 238 $ 33 $ 6,206BalanceasatJune30,2020 $ 5,746 $ 57 $ 245 $ 30 $ 6,078

Includedinthecostofproperty,plantandequipmentis$244millionofassetsunderconstructionasatJune30,2020(December31,2019–$229million).

Inlightofthesignificantdegradationandvolatilityinglobalcrudeoilprices,internationaloilsupplyanddemandimbalances, and the uncertainty surrounding the economic impact of COVID–19, a test for impairment wasperformed atMarch 31, 2020, and no impairment charges were required. The economic conditions that werepresent atMarch 31, 2020 that required a test for impairment have improved, and therefore no indicators ofimpairmentexistedatJune30,2020.

When completing the impairment test as at March 31, 2020, estimating the recoverable amount of theCorporation'sCGUinvolvedseveralassumptionsandestimateswhichweresubjecttoestimationuncertainty,aswell as a significant degree of judgment. Significant estimates involved in the calculation included pricingassumptions,productionandcostassumptionsand theappropriatediscount rate.TheCorporationengagesGLJPetroleumConsultantsLtd.("GLJ")toprepareanannualreservereport,whichcontainsthepricing,productionandcost assumptions that form the basis for determining the recoverable amount. The report is prepared as atDecember31,2019,andthereforeadjustmentsweremadetoreflecttheupdatedcommoditypricingatthetimeof impairment testing. Other adjustments to the report are made as necessary to reflect the change in theeconomicenvironment.Theappropriatediscountraterequiresasignificantamountofjudgment,andasensitivityanalysiswasperformedtoensurethata1-2%change inthediscountratedidnotaffecttheconclusionreachedthatnoimpairmentwasrequired.

45

5. EXPLORATIONANDEVALUATIONASSETS

Cost

BalanceasatDecember31,2019 $ 490

Additions —

Explorationexpense (366)

Dispositions —

BalanceasatJune30,2020 $ 124

The Corporation is focused on the development of its core asset Christina Lake as it continues tomanage thebusiness through an unpredictable global economic downturn arising from COVID-19. The Corporation hasdiscontinuedexplorationandevaluationactivitiesincertainnon-coregrowthproperties.Landleaseandevaluationcostsassociatedwiththeseassetsof$366millionwaschargedtoexplorationexpenseduringthefirstquarterof2020. The remaining assetswere allocated to the related CGU for impairment testing and no impairmentwasrequired.

6. OTHERASSETS


Non-currentpipelinelinefill(a) $ 181 $ 190

Financesubleasereceivables 17 18

Intangibleassets(b) 8 9

Deferredfinancingcosts 5 7

Prepaidtransportationcosts(c) 8 9

219 233

Lesscurrentportion (5) (6)

$ 214 $ 227

a. Non-current pipeline linefill on third-party owned pipelines is classified as a non-current asset as thesetransportationcontractsexpirebetweentheyears2025and2048.

In light of the significant and acute decline in commodity prices associated with the COVID–19 globalpandemic,long-termpipelinelinefillwastestedforimpairmentunderIAS2bycomparingthecarryingvaluetothenetrealizablevalue,andnoimpairmentwasrecordedduetothelong-termnatureofthetransportationcontracts. The uncertainty surrounding the duration and depth of unprecedented low commodity prices,combinedwithsignificantvolatilityincommoditypricesincreasestheestimationuncertaintyassociatedwiththenetrealizablevalueatJune30,2020,andactualresultscoulddifferfromtheestimates.

b. As at June 30, 2020, intangible assets consist of $8 million invested in software that is not an integralcomponentof therelatedcomputerhardware (December31,2019–$9million).Depreciationof$1millionwasrecognizedforthesixmonthsendedJune30,2020(December31,2019–$2million).Atthebeginningof2020,theCorporationsoldpatentsthatwererecordedatanominalamount,andrecognizedagainonassetdispositionof $6million.During the comparative sixmonthperiod in 2019, theCorporation sold internallygeneratedemissionperformancecreditsthatwererecordedatanominalamount,andrecognizedagainonassetdispositionsof$12million.

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

46

7. DEFERREDINCOMETAXASSET

AsatJune30,2020,theCorporationrecognizedadeferredtaxassetof$325million(December31,2019-$262million).Thedeferredtaxasset isreviewedateachbalancesheetdatetoassesswhether it isprobablethattherelatedtaxbenefitwillberealized.AsatJune30,2020,theCorporationestimatesthatfuturetaxable incomeisexpectedtobesufficienttorealizethedeferredtaxasset.Theestimatesusedtodeterminefuturetaxableincomearesubjecttomeasurementuncertaintyandactualresultscoulddifferfromestimates.

8. LONG-TERMDEBT


SecondLien:

6.5%seniorsecuredsecondliennotes(June30,2020-US$496million;December31,2019-US$596million;due2025) $ 675 $ 773

Unsecured:

7.0%seniorunsecurednotes(June30,2020-US$600million;December31,2019-US$1billion;due2024) 817 1,297

7.125%seniorunsecurednotes(June30,2020-US$1.2billion;December31,2019-US$nil;due2027) 1,634 —

6.375%seniorunsecurednotes(June30,2020-US$nil;December31,2019-US$800million;due2023) — 1,037

3,126 3,107

Less:

Debtredemptionpremium — 29

Unamortizeddeferreddebtdiscountanddebtissuecosts (30) (13)

$ 3,096 $ 3,123

TheU.S.dollardenominateddebtwastranslatedintoCanadiandollarsattheperiodendexchangerateofUS$1=C$1.3616(December31,2019–US$1=C$1.2965).

During the first quarter of 2020, the Corporation successfully closed a private offering of $1.6 billion (US$1.2billion) in aggregate principal amount of 7.125% senior unsecured notes due February 2027. On February 18,2020,thenetproceedsoftheoffering,togetherwithcashonhand,wereusedto:


• Partially redeem$530million (US$400million)of theUS$1.0billion7.00%seniorunsecurednotesdueMarch2024ataredemptionpriceof102.333%;and


Concurrent with the private offering, on February 18, 2020, the Corporation redeemed $132 million (US$100million) in aggregate principal amount of its 6.5% senior secured second lien notes due January 2025 at aredemption price of 104.875%. Cash on hand was used to fund this senior secured second lien notes partialredemption.

The Corporation's total credit available under two facilities is $1.3 billion, comprised of $800million under therevolvingcreditfacilityand$500millionunderaletterofcreditfacility,guaranteedbyExportDevelopmentCanada("EDC"). Letters of credit under the EDC facility do not consume capacity of the revolving credit facility. TherevolvingcreditfacilityandtheEDCFacilitybothhaveamaturitydateofJuly30,2024.Thematuritydatesofthe

47

revolvingcreditfacilityandtheEDCFacilityincludeafeaturethatwouldcausethematuritydatestospringbackto91dayspriortothematuritydateofcertainmaterialdebtoftheCorporationifsuchdebthasnotbeenrepaidorrefinancedpriortosuchdate.

The revolving credit facilitydoesnot containa financialmaintenance covenantunless theCorporation isdrawnunder therevolvingcredit facility inexcessof$400million. If the facility isdrawn inexcessof$400million, theCorporation is required to maintain a first lien net debt to last twelve months earnings before interest, tax,depreciationandamortizationratioof3.50orless.Thefinancialmaintenancecovenant,iftriggered,willbetestedquarterly.Issuedlettersofcreditarenotincludedinthecalculationoftheratio.

Therevolvingcreditfacility,EDCfacilityandseniorsecuredsecondliennotesaresecuredbysubstantiallyalltheassetsoftheCorporation.

AsatJune30,2020,theCorporationhad$785millionofunutilizedcapacityunderthe$800millionrevolvingcreditfacilityandtheCorporationhad$63millionofunutilizedcapacityunderthe$500millionletterofcreditfacility.Aletterofcreditof$15millionwasissuedundertherevolvingcreditfacilityduringthesixmonthsendedJune30,2020.

9. PROVISIONSANDOTHERLIABILITIES


Leaseliabilities(a) $ 288 $ 281

Decommissioningprovision(b) 67 71

Otherliabilities 11 8

Provisionsandotherliabilities 366 360


Non-currentportion $ 335 $ 332

a. Leaseliabilities:


Balance,beginningofperiod $ 281 $ 131

IFRS16openingbalancesheetadjustment — 160

Additions 13 13

Modifications 2 (4)

Payments (21) (45)

Interestexpense 13 26

Balance,endofperiod 288 281



48

TheCorporation'sminimumleasepaymentsareasfollows:

Asat June30,2020

Withinoneyear $ 50

Laterthanoneyearbutnotlaterthanfiveyears 150

Laterthanfiveyears 513

Minimumleasepayments 713

Amountsrepresentingfinancecharges (425)

Netminimumleasepayments $ 288

TheCorporationhasshort-termleaseswithleasetermsoftwelvemonthsorlessaswellaslow-valueleases.As these lease costs are incurred they are recognized as either general and administrative expense oroperatingexpensedependingontheirnature.AsatJune30,2020,thepresentvalueofthesearrangementsis$3million(December31,2019-$2million),usingtheCorporation'sestimatedincrementalborrowingrate.

b. Decommissioningprovision:

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


Balance,beginningofperiod $ 71 $ 65

Changesinestimatedlifeandestimatedfuturecashflows 3 (2)

Changesindiscountrates (9) 2

Liabilitiesincurredanddisposed,net — 1

Liabilitiessettled (2) (2)

Accretion 4 7

Balance,endofperiod 67 71



ThedecommissioningprovisionrepresentsthepresentvalueoftheestimatedfuturecostsforthereclamationandabandonmentoftheCorporation'sproperty,plantandequipmentandexplorationandevaluationassets.Thetotalundiscountedamountoftheestimatedfuturecashflowstosettlethedecommissioningobligationsis$810million(December31,2019–$827million).Duetothesignificantdeclineinglobalcrudeoilpricesandincreased levelsofmarketvolatility, theCorporation’sestimatedweightedaveragecredit-adjusted risk freerate increased 1.5%during the sixmonths ended June 30, 2020. As at June 30, 2020, the Corporation hasestimatedthenetpresentvalueofthedecommissioningobligationsusingaweightedaveragecredit-adjustedrisk-freerateof15.2%(December31,2019–13.7%)andaninflationrateof2.1%(December31,2019-2.1%).Thedecommissioningprovisionisestimatedtobesettledinperiodsuptotheyear2066(December31,2019-periodsuptotheyear2066).

49

10. SHARECAPITAL

TheCorporationisauthorizedtoissueanunlimitednumberofcommonshareswithoutnominalorparvalueandanunlimitednumberofpreferredshares.

Changesinissuedcommonsharesareasfollows:


YearendedDecember31,2019

Numberofshares

(thousands) Amount

Numberofshares

(thousands) Amount

Balance,beginningofyear 299,508 $ 5,443 296,841 $ 5,427

Issueduponexerciseofstockoptions 39 — 266 2

IssueduponvestingandreleaseofRSUsandPSUs 3,098 17 2,401 14

Balance,endofperiod 302,645 $ 5,460 299,508 $ 5,443

11. STOCK-BASEDCOMPENSATION


2020 2019 2020 2019

Cash-settledexpense(recovery)(i) $ 9 $ 5 $ (9)$ (5)

Equity-settledexpense 2 11 7 16

Equitypriceriskmanagementgain(ii) (19) — (20) —

Stock-basedcompensation $ (8)$ 16 $ (22)$ 11

(i) Cash-settled RSUs and PSUs are accounted for as liability instruments and aremeasured at fair value based on themarket valueof theCorporation’s common sharesat eachperiodendand certain estimates includingaperformancemultiplierforPSUs.Fluctuationsinthefairvaluearerecognizedduringtheperiodinwhichtheyoccur.

(ii) RelatestofinancialderivativesenteredintotomanagetheCorporation'sexposuretocash-settledRSUsandPSUsvestingin2021,2022and2023grantedundertheCorporation'sstock-basedcompensationplans.Amountsareunrealizeduntilvestingoftherelatedunitsoccurs.Seenote19(d)forfurtherdetails.

A$9millioncash-settledrecoverywasrecognizedduringthesixmonthsendedJune30,2020duetothedecreaseintheCorporation'sshareprice,andassociateddecreaseinvalueofcash-settledRSUsPSUsandDSUscomparedtoDecember31,2019whichtranslatestoareducedliability(orrecovery)heldbytheCorporationatJune30,2020.AsatJune30,2020,theCorporationrecognizedaliabilityof$12millionrelatingtothefairvalueofcash-settledRSUs, PSUs and DSUs (December 31, 2019 – $25million). The current portion of $5million is includedwithinaccountspayableandaccruedliabilitiesand$7millionisincludedasanon-currentliabilitywithinprovisionsandotherliabilitiesbasedontheexpectedpayoutdatesoftheindividualawards.

50

12. REVENUES


2020 2019 2020 2019

Salesfrom:

Production $ 181 $ 863 $ 650 $ 1,559

Purchasedproduct(i) 118 199 297 402


Royalties — (18) (6) (21)

Petroleumrevenue,netofroyalties $ 299 $ 1,044 $ 941 $ 1,940

Powerrevenue $ 6 $ 14 $ 26 $ 34

Transportationrevenue 2 3 5 6

Otherrevenue $ 8 $ 17 $ 31 $ 40

Totalrevenues $ 307 $ 1,061 $ 972 $ 1,980

(i) Theassociated third-partypurchasesare included in theconsolidatedstatementofearnings (loss)andcomprehensiveincome(loss)underthecaption“Purchasedproduct”.

a. Disaggregationofrevenuefromcontractswithcustomers

TheCorporationrecognizesrevenueupondeliveryofgoodsandservicesinthefollowinggeographicregions:

ThreemonthsendedJune30

2020 2019

PetroleumRevenue PetroleumRevenue

Proprietary Third-party Total Proprietary Third-party Total

Country:

Canada $ 84 $ 3 $ 87 $ 518 $ 25 $ 543

UnitedStates 97 115 212 345 174 519

$ 181 $ 118 $ 299 $ 863 $ 199 $ 1,062

SixmonthsendedJune30

2020 2019

PetroleumRevenue PetroleumRevenue

Proprietary Third-party Total Proprietary Third-party Total

Country:

Canada $ 392 $ 34 $ 426 $ 949 $ 170 $ 1,119

UnitedStates 258 263 521 610 232 842

$ 650 $ 297 $ 947 $ 1,559 $ 402 $ 1,961

Other revenue recognized during the three and sixmonths ended June 30, 2020 and 2019 is attributed toCanada.

51

b. Revenue-relatedassets

TheCorporationhasrecognizedthefollowingrevenue-relatedassetsintradereceivablesandother:


Petroleumrevenue $ 168 $ 122

Otherrevenue 1 4

Totalrevenue-relatedassets $ 169 $ 126

Revenue-relatedreceivablesaretypicallysettledwithin30days.AsatJune30,2020andDecember31,2019,therewasnomaterialexpectedcreditlossrequiredagainstrevenue-relatedreceivables.

13. DILUENTANDTRANSPORTATION


2020 2019 2020 2019

Diluentexpense $ 128 $ 325 $ 428 $ 622

Transportationandstorage 77 96 157 191

Diluentandtransportation $ 205 $ 421 $ 585 $ 813

14. FOREIGNEXCHANGE(GAIN)LOSS,NET


2020 2019 2020 2019

Unrealizedforeignexchange(gain)losson:

Long-termdebt $ (116)$ (74)$ 162 $ (154)

US$denominatedcashandcashequivalents 2 7 (9) 9

Unrealizednet(gain)lossonforeignexchange (114) (67) 153 (145)

Realized(gain)lossonforeignexchange (2) (2) 1 (3)

Foreignexchange(gain)loss,net $ (116)$ (69)$ 154 $ (148)

C$equivalentof1US$

Beginningofperiod 1.4120 1.3360 1.2965 1.3646

Endofperiod 1.3616 1.3091 1.3616 1.3091

15. NETFINANCEEXPENSE


2020 2019 2020 2019

Interestexpenseonlong-termdebt $ 60 $ 69 $ 124 $ 141

Interestexpenseonleaseliabilities 7 7 13 13

Interestincome — (2) (2) (3)

Netinterestexpense 67 74 135 151

Accretiononprovisions 2 1 4 4

Unrealizedlossonderivativefinancialliabilities — 1 — —

Netfinanceexpense $ 69 $ 76 $ 139 $ 155

52

16. OTHEREXPENSES


2020 2019 2020 2019

Contractcancellation(i) $ 20 — $ 26 —

Severanceandrestructuring 2 5 4 12

Researchanddevelopment — 2 — 4

Otherexpenses $ 22 $ 7 $ 30 $ 16(i) Costsincurredtomitigaterailsalescontractexposure.

17. SUPPLEMENTALCASHFLOWDISCLOSURES


2020 2019 2020 2019

Cashprovidedby(usedin):

Tradereceivablesandother $ (7)$ 49 $ 157 $ (184)

Inventories(a) (7) 8 27 (1)

Accountspayableandaccruedliabilities (21) (51) (156) (14)

Interestpayable 53 55 9 (3)

$ 18 $ 61 $ 37 $ (202)

Changesinnon-cashworkingcapitalrelatingto:

Operating $ 48 $ 75 $ 78 $ (145)

Investing (30) (14) (41) (57)

$ 18 $ 61 $ 37 $ (202)

Cashandcashequivalents:(b)

Cash $ 120 $ 138 $ 120 $ 138

Cashequivalents — 261 — 261

$ 120 $ 399 $ 120 $ 399

Cashinterestpaid — $ 5 $ 105 $ 122

a. Excludesanon-cash inventory impairmentof$29millionrecognizedasatMarch31,2020asaresultofthedifferencebetweencostandnetrealizablevalueresultingfromthesignificantdeclineincrudeoilpricesattheendofthefirstquarter.Asinventorysoldinthesubsequentmonth,theimpactwasrecognizedthroughfundsflowfromoperatingactivitiesformatchingpurposes.

b. AsatJune30,2020,$90millionoftheCorporation’stotalcashandcashequivalentsbalancewasheldinU.S.dollars(June30,2019–$328million).TheU.S.dollarcashandcashequivalentsbalancehasbeentranslatedintoCanadiandollarsattheperiodendexchangerateofUS$1=C$1.3616(June30,2019–US$1=C$1.3091).

53

Thefollowingtableprovidesareconciliationofassetsandliabilitiestocashflowsarisingfromfinancingactivities:

Financesubleasereceivables

Leaseliabilities

Long-termdebt

BalanceasatDecember31,2019 $ 18 $ 281 $ 3,123

Cashchanges:

Receiptsonleasedassets (1) — —

Paymentsonleasedliabilities — (13) —

Issueof7.125%seniorunsecurednotes — — 1,581

Repaymentandredemptionoflong-termdebt — — (1,723)

Debtredemptionpremiumandrefinancingcosts — — (49)

Non-cashchanges:

Leaseliabilitiessettled (8)

Leaseliabilitiesincurred — 13 —

Leaseliabilitiesmodified — 2 —

Interestexpenseonleaseliabilities — 13 —

Unrealized(gain)lossonforeignexchange — — 162

Amortizationofdeferreddebtdiscountanddebtissuecosts — — 2

BalanceasatJune30,2020 $ 17 $ 288 $ 3,096

(i)Financesubleasereceivables,Leaseliabilities&Long-termdebtallincludetheirrespectivecurrentportion.

18. NETLOSSPERCOMMONSHARE


2020 2019 2020 2019

Netloss $ (80)$ (64)$ (364)$ (111)Weightedaveragecommonsharesoutstanding

(millions)(a) 303 298 302 297Dilutiveeffectofstockoptions,RSUsandPSUs

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

diluted(millions) 303 298 302 297

Netlosspershare,basic $ (0.26)$ (0.21)$ (1.21)$ (0.37)

Netlosspershare,diluted $ (0.26)$ (0.21)$ (1.21)$ (0.37)

a. Weightedaveragecommonsharesoutstanding for thethreemonthsendedJune30,2020 includes571,529PSUsvestedbutnotyetreleased(threemonthsendedJune30,2019-381,014PSUs).

b. ForthethreeandsixmonthsendedJune30,2020, theCorporation incurredanet lossandthereforetherewasnodilutiveeffectofstockoptions,RSUsandPSUs.IftheCorporationhadrecognizednetearningsforthethreeand sixmonthsended June30,2020, thedilutiveeffectof stockoptions,RSUsandPSUswouldhavebeen3.6millionweightedaveragecommonshares(threeandsixmonthsendedJune30,2019-2.8millionand3.1millionweightedaveragecommonshares,respectively).

19. 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.

54

a. Fairvalues:

The carrying values of cash and cash equivalents, trade receivables and other, riskmanagement contracts,accounts payable and accrued liabilities and interest payable included on the consolidated balance sheetapproximates the fair values of the respective assets and liabilities due to the short-term nature of thoseinstruments.

ThefollowingfairvaluesarebasedonLevel2inputstofairvaluemeasurement:

Asat June30,2020 December31,2019Carryingamount Fairvalue

Carryingamount Fairvalue

Recurringmeasurements:

Financialassets

Riskmanagementcontracts $ 114 $ 114 — —

Financialliabilities

Long-termdebt(Note8) $ 3,126 $ 2,716 $ 3,107 $ 3,160

Riskmanagementcontracts $ 10 $ 10 $ 77 $ 77

Theestimatedfairvalueoflong-termdebtisderivedusingquotedpricesinaninactivemarketfromathird-party independentbroker.ThefairvaluesweredeterminedbasedonestimatesasatJune30,2020andareexpectedtofluctuategiventhevolatilityinthedebtandcommoditypricemarkets.

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,andifentered intooptions,pluscondensateswapsandequityswaps.Theuseof the financial riskmanagementcontracts 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.

55

ThefollowingtableprovidesasummaryoftheCorporation’sunrealizedoffsettingfinancialriskmanagementpositions:


Asset Liability Net Asset Liability Net

Grossamount $ 157 $ (10)$ 147 $ — $ (77)$ (77)

Amountoffset (43) — (43) — — —

Netamount $ 114 $ (10)$ 104 $ — $ (77)$ (77)

Currentportion $ 90 $ (10)$ 80 $ — $ (77)$ (77)

Non-currentportion 24 — 24 — — —

Netamount $ 114 $ (10)$ 104 $ — $ (77)$ (77)

The following table provides a reconciliation of changes in the fair value of the Corporation’s financial riskmanagementassetsandliabilitiesfromJanuary1toJune30:

AsatJune30 2020 2019

Fairvalueofcontracts,beginningofyear $ (77)$ 93

Fairvalueofcontractsrealized 321 72

Changeinfairvalueofcontracts (140) (194)

Fairvalueofcontracts,endofperiod $ 104 $ (29)

c. Commodityriskmanagement:

TheCorporationhadthefollowingfinancialcommodityriskmanagementcontractsrelatingtocrudeoilsalesandcondensatepurchasesoutstandingasatJune30,2020:

AsatJune30,2020Volumes(bbls/d)(i) Term

AveragePrice(US$/bbl)(i)


WTI(ii)FixedPrice 47,042 Jul1,2020-Dec31,2020 $47.70

WTI:WCS(iii)FixedDifferential 24,500 Jul1,2020-Dec31,2020 $(20.46)

WTI:WCS(USGC)FixedDifferential 1,000 Aug1,2020-Aug31,2020 $(3.95)

EnhancedFixedPricewithSoldPutOption

WTIFixedPrice/SoldPutOptionStrikePrice 20,685 Jul1,2020-Dec31,2020 $59.22/$52.00


WTI:MontBelvieuFixedDifferential 7,250 Jul1,2020-Dec31,2020 $(7.63)

WTI:MontBelvieuFixedDifferential 10,950 Jan1,2021-Dec31,2021 $(10.37)

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

WTI:MontBelvieuFixed%ofWTI 7,750 Jul1,2020-Dec31,2020 93.1%

(i) Thevolumesandpricesintheabovetablerepresentaveragesforvariouscontractswithdifferingtermsandprices.The average price and percentages for the portfolio may not have the same payment profile as the individualcontractsandareprovidedforindicativepurposes.

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

56

TheCorporationenteredintothefollowingfinancialcommodityriskmanagementcontractsrelatingtocrudeoilsalesandcondensatepurchasessubsequenttoJune30,2020.Asaresult,thesecontractsarenotreflectedintheCorporation’sConsolidatedFinancialStatements:

SubsequenttoJune30,2020Volumes(bbls/d)(i) Term

AveragePrices(US$/bbl)(i)

CrudeOilSales(Purchase)Contracts

WTIFixedPrice 25,250 Aug1,2020-Aug31,2020 $40.57

WTIFixedPrice 6,370 Oct1,2020-Dec31,2020 $41.45

(i) Thevolumesandpricesintheabovetablesrepresentaveragesforvariouscontractswithdifferingtermsandprices.The average price and percentages for the portfolio may not have the same payment profile as the individualcontractsandareprovidedforindicativepurposes.

Thefollowingtablesummarizesthefinancialcommodityriskmanagementgainsandlosses:


2020 2019 2020 2019

Realizedloss(gain)oncommodityriskmanagement $ (215)$ 51 $ (321)$ 72

Unrealizedloss(gain)oncommodityriskmanagement 267 (87) (161) 122

Commodityriskmanagement(gain)loss,net $ 52 $ (36)$ (482)$ 194

Thefollowingtablesummarizesthesensitivityoftheearnings(loss)beforeincometaximpactoffluctuatingcommoditypricesontheCorporation’sopenfinancialcommodityriskmanagementpositionsinplaceasatJune30,2020:

Commodity SensitivityRange Increase Decrease

Crudeoilcommodityprice ±US$5.00perbblappliedtoWTIcontracts $ (63)$ 60

Crudeoildifferentialprice(i) ±US$5.00perbblappliedtoWTI:WCSdifferentialcontracts $ 31 $ (31)

(i) AstheWCSdifferentialisexpressedasadiscounttoWTI,anincreaseinthedifferentialresultsinalowerWCSpriceandadecreaseinthedifferentialresultsinahigherWCSprice.

d. Equitypriceriskmanagement:

TheCorporationentersintofinancialequitypriceriskmanagementcontractstoincreasethepredictabilityoftheCorporation'scashflowbymanagingsharepricevolatility.EquitypriceriskistheriskthatchangesintheCorporation’s own share price impact earnings and cash flows. Earnings and funds flow from operatingactivitiesare impactedwhenoutstandingcash-settledRSUsandPSUs, issuedundertheCorporation'sstock-based compensation plans, are revalued each period based on the Corporation’s share price. Net cashprovided by (used in) operating activities is impacted when these stock-based compensation units areultimately settled.TheCorporationenters into theseequityprice riskmanagementcontracts tomanage itsexposureonapproximately9millioncash-settledRSUsandPSUsvestingbetween2021and2023.

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 transactions

57

according 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. TheCorporation has experienced no material loss in relation to trade receivables. As at June 30, 2020, theCorporation’sestimatedmaximumexposuretocreditriskrelatedtotradereceivables,depositsandadvanceswas $228 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’s2019annualconsolidatedfinancialstatements.

TheCorporation’scashbalancesareusedtofundthedevelopmentofitsproperties.Asaresult,theprimaryobjectivesof the investmentportfolioare lowriskcapitalpreservationandhigh liquidity.Thecashbalancesareheldinhighinterestsavingsaccountsorareinvestedinhighgrade,liquid,short-terminstrumentssuchasbankers’acceptances, commercialpaper,moneymarketdepositsor similar instruments.Thecashandcashequivalentsbalanceat June30,2020was$120million.Noneof the investmentsarepast theirmaturityorconsidered impaired. TheCorporation’s estimatedmaximumexposure to credit risk related to its cash andcashequivalentsis$120million.

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 the uncertainty associated with COVID–19 is supported by theCorporation'sfinancialframeworkincludingastrongcommodityriskmanagementprogramsecuringcashflowthrough 2020 and credit risk management policies minimizing exposure related to customer receivablesprimarilytoinvestmentgradecustomersintheenergyindustry.However,noassurancecanbegiventhatthiswillbethecaseorthatfuturesourcesofcapitalwillnotbenecessary.

TheCorporation'searliestmaturing long-termdebt isapproximately fouryearsout, representedbyUS$600million of senior unsecured notes dueMarch 2024. None of the Corporation’s outstanding long-term debtcontainfinancialmaintenancecovenants.Additionally,theCorporation'smodifiedcovenant-lite$800millionrevolvingcreditfacilityhasnofinancialmaintenancecovenantunlessdrawninexcessof$400million.Ifdrawninexcessof$400million,theCorporationisrequiredtomaintainaquarterlyfirstliennetleverageratio(firstliennetdebttolasttwelve-monthEBITDA)of3.5orless.UndertheCorporation'screditfacility,firstliennetdebtiscalculatedasdebtunderthecreditfacilityplusotherdebtthatissecuredonaparipassubasiswiththecreditfacility,lesscashonhand.

20. 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,cashonhandand/orotheravailableliquidity.

58

On January 31, 2020, the Corporation closed the refinancing and extension of thematurity profile of its debtportfolio. Followingcompletionoftheassociatedtransactions,MEG'sfirstdebtmaturitywasextendedto2024.AsatJune30,2020,theCorporationhad$785millionofunutilizedcapacityunderthe$800millionrevolvingcreditfacilityandhad$63millionofunutilizedcapacityunderthe$500millionletterofcreditfacility.Aletterofcreditof$15millionwasissuedunderitsrevolvingcreditfacilityduringthesixmonthsendedJune30,2020.

ThefollowingtablesummarizestheCorporation'snetdebt:

Asat Note June30,2020 December31,2019

Long-termdebt 8 $ 3,096 $ 3,123

Cashandcashequivalents (120) (206)

Netdebt $ 2,976 $ 2,917

Netdebtisanimportantmeasureusedbymanagementtoanalyzeleverageandliquidity.DuringthesixmonthsendedJune30,2020,netdebtincreasedby$59millionduetotheweakeningoftheCanadiandollarrelativetotheUSdollaranddecreaseincashandcashequivalentsovertheperiod,partiallyoffsetbytheredemptionofits6.5%seniorsecuredsecondliennotes.

On January 31, 2020 the Corporation successfully closed a private offering of $1.6 billion (US$1.2 billion) inaggregateprincipalamountof7.125%seniorunsecurednotesdueFebruary2027.OnFebruary18,2020,thenetproceedsoftheoffering,togetherwithcashonhand,wereusedto:


• Partially redeem$530million (US$400million)of theUS$1.0billion7.00%seniorunsecurednotesdueMarch2024ataredemptionpriceof102.333%;and


Concurrent with the private offering, on February 18, 2020, the Corporation redeemed $132 million (US$100million) in aggregate principal amount of its 6.5% senior secured second lien notes due January 2025 at aredemption price of 104.875%. Cash on hand was used to fund this senior secured second lien notes partialredemption.

ThefollowingtablesummarizestheCorporation'sfundsflowfrom(usedin)operationsandadjustedfundsflow:


Note 2020 2019 2020 2019

Netcashprovidedby(usedin)operatingactivities $ 117 $ 302 $ 216 $ 233

Netchangeinnon-cashoperatingworkingcapitalitems (48) (75) (78) 145


Adjustments:

Contractcancellation(i) 16 20 — 26 —

Decommissioningexpenditures 9 — — 2 —


(i) Costs incurred to mitigate rail sales contract exposure. Contract cancellation costs or recoveries are excluded fromadjustedfundsflowastheyarenotconsideredpartofordinarycontinuingoperatingresults.

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. By excluding changes in non-cash working capital, non-recurring items and decommissioning

59

expendituresfromcashflows,thefundsflowfrom(usedin)operationsandadjustedfundsflowmeasuresprovidemeaningfulmetrics formanagement by establishing a clear link between the Corporation's cash flows and theoperatingnetbacksfromtheChristinaLakeProject.Fundsflowfrom(usedin)operationsandadjustedfundsflowarenotintendedtorepresentnetcashprovidedby(usedin)operatingactivities.

Netdebt,fundsflowfrom(usedin)operationsandadjustedfundsflowarenotstandardizedmeasuresandmaynotbecomparablewiththecalculationofsimilarmeasuresbyothercompanies.

21. COMMITMENTSANDCONTINGENCIES

a. Commitments

The Corporation’s commitments are enforceable and legally binding obligations to make payments in thefutureforgoodsandservices.Theseitemsexcludeamountsrecordedontheconsolidatedbalancesheet.TheCorporationhadthefollowingcommitmentsasatJune30,2020:

2020 2021 2022 2023 2024 Thereafter Total

Transportationandstorage(i) $ 215 $ 436 $ 425 $ 467 $ 452 $ 6,046 $ 8,041

Diluentpurchases 70 22 22 18 — — 132

Otheroperatingcommitments 8 15 14 13 11 45 106

Variableofficeleasecosts 2 4 4 4 5 30 49

Capitalcommitments 1 — — — — — 1

Commitments $ 296 $ 477 $ 465 $ 502 $ 468 $ 6,121 $ 8,329

(i) Thisrepresentstransportationandstoragecommitmentsfrom2020to2048,includingtheAccessPipelineTSA,andpipelinecommitmentswhichareawaiting regulatoryapprovalandarenotyet in service.Excludes finance leasesrecognizedontheconsolidatedbalancesheet(Note9(a)).

b. Contingencies

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

TheCorporation is thedefendanttoastatementofclaimoriginally filed in2014 inrelationto legacy issuesinvolving aunit train transloading facility inAlberta. The claimwas amended in the fourthquarterof 2017assertingasignificantincreasetodamagesclaimed.TheCorporationfiledastatementofdefenseinthefirstquarterof2018.TheCorporationcontinuestoviewthisclaimaswithoutmeritandwillcontinuetodefendagainst all such claims. The Corporation believes that any liabilities that might arise from this matter areunlikelytohaveamaterialeffectonitsfinancialposition.

60

Documents

Report to Shareholders for the period ended June 30, 2020€¦ · Report to Shareholders for the period ended June 30 ... • $120 million of cash on hand at quarter end benefiting