A U G U S T 2 0 2 1C O R P O R AT E P R E S E N TAT I O N

2

MEG IS THE LEADING PURE PLAY THERMAL OIL PRODUCER

Leading Operator with low-decline, high quality asset

base

Leader in GHG intensity reduction

(20% below peer average)

Committed to reducing debt and strengthening the

balance sheet

Focused on maximizing free

cash flow generation

Exposure to strong benchmark oil

price upside and heavy oil pricing

3

INVESTMENT HIGHLIGHTS

Outlook characterized by free cash flow generation and focus on financial and operating sustainability

ü Balance sheet strength remains a priority

• 4 years to first capital markets debt maturity• US$100 mm debt reduction to date in 2021

ü Sustainability integrated into development plan

• 2021 includes advancement of key ESG initiatives including the on-going development of GHG reducing technologies

• Targeting net zero emissions by 2050

ü Positioned to capture commodity price recovery

• Exposure to improving benchmark and differential environment• At current strip prices expect to generate material free cash flow

ü Dynamic approach to manage COVID-19 health and safety risk

• On-going improvements to safety protocols and flexible approach to management prioritizes safety for all stakeholders

ü Optimize plant capacity • $75 mm in capital in 2021 to begin to bring Christina Lake Facility up to its 100,000 bbls/d capacity by H2 2022

• Strong operating performance contributing to increased production guidance

4

ABOUT MEG

MEG is an energy company focused on sustainable in situ thermal oil production in the southern Athabasca oil region of Alberta, Canada. MEG transports and sells thermal oil (known as Access Western Blend or AWB) to customers throughout North America and internationally.

With proven, proprietary innovative technologies, we are reducing our energy and water use, capital and operating costs and greenhouse gas intensity. MEG is actively developing innovative enhanced oil recovery projects that utilize steam-assisted gravity drainage (“SAGD”) extraction methods to improve the economic recovery of oil as well as lower carbon emissions.

MEG is proud to be part of a vital industry promoting responsible resource development and fueling our economy.

1. All reserves are at Christina Lake. See additional information in Annual Information Form (AIF).

PROVED & PROBABLERESERVES1

PROVED1,300

PROBABLE 735

2,035

MILLIONS OF BBLS

CHRISTINA LAKE PRODUCTION

BBLS/D

DIVERSE MARKETING PORTFOLIO ENHANCES

NETBACK

2021 production guidance of ~91,000-93,000 bbls/d

Proved + Probable reserve life index of 62 years at 90,000 bbls/d

Enterprise TEPPCO

Enbridge Southern Lights

Edmonton

Chicago

St. James

Bayou Bridge

Flanagan South / Seaway

Hardisty

Cushing

Beaumont / Mont Belvieu

Bruderheim

Enbridge Mainline

W A T E RZero surface or fresh water used in MEG’s operationsApproximately 80% reduction in make-up water withdrawal intensity since 2013

H E A L T H & S A F E T YNo employee lost time incidents at our Christina Lake Facility since 2019Rapid, effective COVID-19 response

I N D I G E N O U S R E L A T I O N SCumulative spend on contracts with Indigenous businesses of over $900 mm

ESG PRIORIT IES

D I V E R S I T Y30% women on board target achieved in 2020

G H GGHG intensity is >20% below peer averageMethane conservation is > 99.5%

MEG is committed to the long-term sustainable development of our resource and investment in the communities where we operate – ESG objectives are a key component of corporate strategy and employee and executive compensation

Additional information can be found at www.megenergy.com/sustainability

5

Enhancement and implementation of an Inclusion and Diversity strategy

Grow economic participation for local communities and implement company wide training

Continue to implement technology to reduce emissions and achieve net zero emissions by 2050

Continued focus on optimization of % of water recycled

Promoting risk awareness at work and at home for our work force and their families

0

10

20

30

40

50

60

70

80

90 Yale Enviro. Performance Index Social Progress Index Worldbank Governance Index

6

CANADA’S ESG RANKING

TOP OIL RESERVE HOLDERS ESG SCORES

Source: BMO Capital Markets; Presentation uses an equal weight of each index representedNote: The Environmental Performance Index (EPI) is created jointly by Yale/Columbia Universities in collaboration with the World Economic Forum and ranks 180 countries on 24 performance indicators on environmental health and ecosystem vitality. The Social Progress Index (SPI) is developed by the Social Progress Imperative and ranks 149 countries on 51 measures of social responsibility that are independent of economic indicators. World Bank’s Worldwide Governance Indicators (WGI) rank over 200 countries on six dimensions including political stability, regulatory quality and corruption control.

ü Only top reserve holder to have a price on carbon

ü Stringent environmental regulation

ü High governance scoresü Enforcement of human rights

and social progress ü Low corruptionü Significant investment in

continuous improvement of environmental performance

Canadian oil companies earn a stronger ESG score than all other oil-rich countries, due to stringent environmental regulation, strong governance norms and commitment to safety and community

More than 20% below in situ industry average

45

55

65

75

2013 2014 2015 2016 2017 2018 2019 2020MEG Industry Average

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0

20

40

60

80

100

120

140

160

Global Crudes SAGD Mining SCO Mining Bitumen

Avg. In situ Intensity

MEG 2019 Intensity

Cogeneration

eMSAGP

7

GHG PERFORMANCEESTIMATED UPSTREAM CARBON INTENSITY (2019)

Source: BMO Capital Markets estimatesTrack Record of Using Technology to Improve

Environmental, Economic and Operating Performance (kg CO2e/bbl)

MEG NET GHG INTENSITY 1

• Technological innovation, such as eMSAGP and cogeneration have driven MEG’s GHG intensity down by 7% since 2013

• MEG uses cogeneration at its facilities with excess power being sold into the Alberta Power Market – electricity generated through cogeneration has a GHG intensity that is a fraction of the current Alberta provincial power grid

MEG has been a first mover in implementing technology to drive down MEG’s GHG intensity

MEG has taken measures to achieve one of the lowest GHG emissions intensities in the thermal heavy oil industry

Impact from future technology development

Below global average

52 kgCO2e/

bbl

1. Net GHG Intensity includes associated benefits of cogeneration.2. Based on public disclosure (see MEG’s ESG report for additional details).3. Data for 2020 is preliminary.

kgCO2e/bblLEADER IN LOWERING GHG INTENSITY

2

3

0.09 0.2 0.40.7

2.5

MEG In situ HydraulicFracturing

Enhancedoil recovery

Oil sandsmining

• MEG’s focus on technology has enabled us to reduce our total make-up water withdrawal intensity by approximately 80% since 2013

• MEG does not operate in water stressed areas5

• Make up water is supplied from deep non-drinkable groundwater for our current and future thermal operations

0.01

1.4

1.7

MEG Permian Eagle Ford

8

IN S ITU RELATIVE TO T IGHT OIL

MEG’s Non-Saline1 Water Use Intensity is significantly lower than

other extraction technologies2

(bbl of water used to produce a bbl of oil; Alberta 2014-2018 average)

Comprehensive environmental management compares favourably to North American production

Water Methane Land

1. Non-saline water is defined in Alberta as water with a total dissolved solids concentration of less than 4,000 mg/L. 2. AER Water Use Report.3. Schneising, O. et al (2020) - Remote sensing of methane leakage from natural gas and petroleum systems revisited. Atmospheric Chemistry and Physics.4. EIA, geoScout, BMO Capital Markets estimates.5. Aqueduct Water Risk Atlas.

MEG’s methane emissions intensity is less than 1% of the intensity of shale

producers3

(kg CH4/BOE)

• MEG continues to invest in technology to reduce methane emissions – MEG conserves > 99.5% of methane

• Christina Lake Facility is a gas conserving facility – meaning overall flaring and venting are virtually eliminated in normal operating conditions

Cumulative average number of tight oil wells drilled in support of base

production is 5x higher than SAGD4

(Wells per 1000 bbls/d)

• Tight oil averages 12.4 wells per 1,000 bbls/d compared to just 2.4 wells for SAGD to support base production4

• To date more than 100,000 tight oil wells have been drilled in the four main plays, compared to just 3,300 SAGD oil sands wells4

2.4

9.211.4

16.6

26.2

SAGD OilSands

Permian Bakken Eagle Ford Niobrara

Gulf Coast

9

Internally funded capital plan that supports 2021 production and contributes to sustainability in 2022+

R E V I S E D2 0 2 1 G U I D A N C E 1

Production – average (bbls/d) 91,000 – 93,000 bbls/d

Non-energy operating costs $4.40 – $4.60 / bbl

G&A costs $1.65 – $1.75 / bbl

2021 OUTLOOK AND GUIDANCE

• Annual production guidance of 91,000 – 93,000 bbls/d driven by better-than-expected reservoir performance, short-cycle investments and high uptime

• H1 2021 free cash flow plus non-core asset sale proceeds support $75 of incremental capex in 2H 2021 and US$100 mm of debt repayment

• Increased capital represents majority of well capital needed to bring back production to 100,000 bpd; Remaining $50 mm to be spent in H1 2022

• Expect to fully utilize oil processing capacity at Christina Lake Facility by H2 2022

• Reduced non-energy opex and G&A guidance predominantly a result of higher production, certain temporary costs savings in H1 2021

$75MM

$180MM

Sustaining and maintenance –Supports 2021 Production (largely spent in H1)

Sustaining and maintenance –Sustain 2022+ Production

Fill Christina Lake Facility capacity

Field infrastructure, regulatory, corporate and other

- No major turnaround planned during 20212021 CAPITAL BUDGET $335 MM

OPERATIONAL GUIDANCE

C$335 MM

$65MM

40% 60%Assumes ~40-45% annual average apportionment

2021 FORECAST REGIONAL BLEND SALES MARKET EXPOSURE

Edmonton

$15MM

1. Original guidance published on December 7, 2020 – a) original production guidance of 86,000 – 90,000 bbls/d; b) original non-energy opex guidance of $4.60 - $5.00 / bbl; and c) original G&A guidance of $1.70 - $1.80/bbl.

Base Production Incremental 10,000 bpd

Royalties

Non-Energy Opex

Net Energy Opex

TransportationCosts

Other Cash Costs

G&A

Net FinanceExpense

Cash Flow

$0.00

$0.25

$0.50

$0.75

$1.00

$1.25

US$55/bbl WTI US$65/bbl WTI US$75/bbl WTI

10

FREE CASH FLOW GENERATIONANNUAL CASH FLOW GENERATIONI l lustrat ive Analysis at 92,000 bbls/d(C$ bn)

Note: Cash flows above assume ~92,000 bbls/d of production, 25% FY apportionment and no hedges; US$65/bbl WTI scenario assumes ~US$14.50/bbl WTI:WCS differential, condensate priced at 103% of WTI and C$1.24/US$ exchange rate (assumptions are adjusted based on WTI price). See p. 19 for additional sensitivity analysis.

VALUE OF INCREMENTAL PRODUCTIONI l lustrat ive Cash Flow per bbl

Note: Illustrative netbacks shown at US$65/bbl WTI – assumes all barrels are sold into Edmonton for simplicity of comparison

Incremental barrels

~85% of costs are fixed

Incremental barrels add higher marginal cash flow per bbl and have significant impact on free cash flow

Base Production at 92,000 bbls/d

11

ASSETS TO ACCESS HIGH VALUE MARKETS

Enterprise TEPPCO

Enbridge Southern Lights

Edmonton

Chicago

St. James

Bayou Bridge

Flanagan South / Seaway

Hardisty

Cushing

Beaumont / Mont Belvieu

Bruderheim

100,000 bbls/don Flanagan South/Seaway

1.4 mmbbl U.S. Gulf Coast storage

Marine export capacity

1.4 mmbbl Western Canadian storage

~50% diluentpurchases from USGC

20,000 bbls/don TMX (Future)

~30,000 bbls/d rail loading capacity

Enbridge Mainline

MEG’s contracted infrastructure improves bitumen realizations and manages risk; expect >900,000 bbls/d incremental egress capacity from Western Canada by the end of 2022*

Enbridge Line 3 expansion expected onstream in H2 2021*; expected to reduce apportionment on mainline and increase MEG’s deliveries to Gulf Coast

Expected in service in late 2022*

* 590,000 bbls/d capacity on TMX and 370,000 bbls/d on Line 3 Expansion, including both heavy and light oil capacity; Current aggregate AB export capacity is ~4 mmbbls/d

Maintains optionality; rail is not anticipated to be part of sales strategy in 2021

DILUENT PURCHASES (bbls)

USGC Market: Cost = Mt. Belvieu

Condensate Price + contracted transport

to Edmonton + contracted transport

to Christina Lake Facility

Edmonton Market: Cost = Edmonton Condensate Pool Price + contracted transport to Christina Lake Facility

• Global refinery adds create strong demand pull for North American exports and has supported Gulf Coast differential in 2021

• Decline in heavy supply globally provides opportunity for Canadian crude

• TMX provides additional access to North American exports when completed

12

STRONG DEMAND FOR CANADIAN HEAVY OIL Constructive light / heavy differential outlook with material improvement in Western Canadian egress and continued strong demand for heavy oil globally

2021 YTD, Gulf Coast market has provided US$3.22 / bbl transportation adjusted benefit1

Source: Bloomberg, IIR, MEG

High complexity refinery adds globally expected to increase demand for Canadian heavy oil

REFINERY CAPACITY PLANNED ADDITIONS (2020 – 2025)

• The Alberta light-heavy differential has moderated against a more balanced egress outlook:

• Existing pipeline debottlenecks adding more than 200 kbbls/d since pre-pandemic

• Addition of storage capacity in Alberta• Completion of Enbridge Line 3 expansion in

H2 2021• Rail capacity continues to provide relief

including 50 kbbls/d diluent recovery unit starting up in H2

• Despite significant improvements in Edmonton pricing, Gulf Coast market remains most attractive market for our barrels

MARGINAL EGRESS INFRASTRUCTURE SUPPORTING EDMONTON PRICING

1. See page 16 in Appendix for detailed realized pricing.

$0

$1,000

$2,000

$3,000

$4,000

2016 2017 2018 2019 2020 2021 ProForma

2021 ProForma

Reduction Balance

Runway to Nearest Maturity

2021 2022 2023 2024 2025 2026 2027 2028 2029

13

COMMITTED TO BALANCE SHEET STRENGTH

COMPARABLE PRODUCER DEBT STRUCTURE 4

CAPITAL MARKETS MATURITY STRUCTURE

1. On July 22, MEG issued notice to redeem US$100 mm in second lien notes which is expected to be completed on August 23.2. If drawn in excess of $400 mm, MEG is required to maintain a quarterly first lien net leverage ratio (first lien net debt less cash on hand to last twelve-month EBITDA) of 3.5x or less.3. FX rate as of date reported in respective company financial statements. Net Debt defined as Long-Term Debt less Cash and cash equivalents.4. Comparison based on oil and gas peers with enterprise value greater than $2 billion and gas weighting less than 50%, including Baytex, Canadian Natural, Cenovus, Crescent

Point, Enerplus, Imperial, Suncor, Vermillion and Whitecap.5. Weighted average maturity calculation assumes revolver is fully drawn; excludes accordion features.

Capital Markets Debt MaturitiesUS$ in Millions

2nd lien secured note1

Unsecured noteNew unsecured note C$800

Revolver

Weighted Average Maturity5

$600

@ 5.875%

$1,200

@ 7.125%

~$396

@ 6.500%

4 years to maturity

US$100 mm redemption to be completed in August1

Financial flexibility is a MEG hallmark: balance sheet has a unique combination of covenant structure and runwayLiquidity provided by undrawn C$800 mm credit facility; no financial maintenance covenant unless drawn > $400 mm2

ANNUAL NET DEBT REDUCTION 3

Incremental free cash flow expected to be allocated to debt reduction

11

5.0

10.1

5.54.9

3.7 3.7 3.6 3.6 3.02.4

3.0

0.4 0.3 0.7 0.8 0.4 2.7 0.5 2.9 0.8

--

2

4

6

8

10

12

A B MEG D E F G H I J

Year

s

Only producer that enjoys covenant-lite structure

14

APPENDIX

15

2021 hedges focused on sustaining capital program – 2022 strategy will be focused on similar objectives

COMMODITY HEDGING OVERVIEW

1. Includes WTI fixed price swaps and WTI sold put options. If in any month of 2021 the month average WTI settlement price is US$38.79 per barrel (the sold put option) or better,MEG will receive US$46.18 per barrel (the fixed price swap) on hedged 2021 production in that month. If in any month of 2021 the month average WTI settlement price is lessthan US$38.79 per barrel, MEG will receive the month average WTI settlement price in that month plus US$7.39 per barrel (the swap spread) on each barrel hedged in thatmonth.

2. Includes 3,075 bbls/d of physical forward condensate purchases for the second half of 2021.3. Where applicable, the average % of WTI landed in Edmonton includes estimated net transportation costs to Edmonton.4. Includes 5,000 GJ/d of physical forward natural gas purchases for the second half of 2021 at a fixed AECO price.5. Represents physical forward power sales at a fixed price.

As of July 22, 2021 3Q 2021 4Q 2021 2022 2023

WTI HedgesEnhanced WTI Fixed Price Hedges with Sold Put Options(1)

Volume (bbl/d) 29,000 29,000 - -Weighted average fixed WTI price / Put option strike price(1) (US$/bbl) $46.18 / $38.79 $46.18 / $38.79Light:heavy Differential HedgesWTI:WCS Differential Hedges at EdmontonVolume (bbl/d) 10,000 - - -Weighted average fixed WTI:WCS differential at Edmonton (US$/bbl) ($11.05)Condensate HedgesVolume(2) (bbl/d) 14,028 14,028 200 -Weighted average % of WTI landed in Edmonton (%)(3) 97% 97% 96%Natural Gas HedgesVolume(4) (GJ/d) 42,500 42,500 5,000 5,000Weighted average fixed AECO price (C$/GJ) $2.61 $2.61 $2.50 $2.50Power HedgesQuantity(5) (MW) 35 35 - -Weighted average fixed price (C$/MWh) $62.75 $62.75

Q 2 2 0 2 1 R E S U L T S Edmonton (US$/bbl)

U.S. Gulf Coast (US$/bbl) TOTAL

(US$/bbl)TOTAL

(C$/bbl)4US$/bbl, except as indicated Pipeline Pipeline3

WTI $66.07 $66.07 $66.07 $81.13

Differential – WTI:AWB at sales point ($14.70) ($3.86) ($9.87) ($12.12)

Asset optimization -- $0.46 $0.21 $0.26

Blend Sales Price $51.37 $62.67 $56.41 $69.27

Transportation and storage1 ($2.14) ($11.15) ($6.17) ($7.58)

Transportation and storage from Christina Lake to Edmonton2 $2.14 $2.14 $2.14 $2.63

AWB Sales Price, Net of Transportation $51.37 $53.66 $52.38 $64.32

Average AWB Sales Price by Location, Net of Transportation $51.37 $53.66

Total Blend Sales – mbbls/d 72 58 130

% of Total Sales 55% 45% 100%

16

1. Defined as transportation and storage expenses less transportation revenue, per barrel of blend sales volumes. For reference, total transportation and storage costs per barrel,based on bitumen sales volumes, were C$10.91 per barrel for the three months ended June 30, 2021 compared to C$11.77 per barrel for the three months ended June 30, 2020.

2. Includes all transportation costs associated with moving barrels of blend from Christina Lake to Edmonton sales point.3. Sales from marketing asset optimization activities are recognized in the blend sales price and not as a recovery of transportation and storage costs for consistency with the financial

statements. During the three months ended June 30, 2021 these activities contributed US$0.46 per barrel to the blend sales price at the USGC (pipeline) compared to US$2.56during the same period of 2020. If presented as a transportation and storage cost recovery, transportation and storage costs per barrel at the USGC (pipeline) during the threemonths ended June 30, 2021 would be US$10.69 per barrel compared to US$11.15 per barrel.

4. Results are translated at the average foreign exchange rate of C$1.2280 for the three months ended June 30, 2021.

BLEND SALES BY MARKETStrong demand pull to US Gulf Coast drives narrow differential and improved transportation adjusted pricing relative to Edmonton

2.1x 2.

3x 2.4x 2.

6x 2.7x 2.8x 2.8x

2.8x 2.8x 2.9x 2.9x

3.0x 3.0x

3.3x 3.

5x

4.0x 4.1x

4.6x

6.4x

6.4x

9.2x

13.4

x

2.4x

2020

ISO

R (x

)

Producing in situ Projects

17

TOP TIER OPERATOR IN THE SECTORMEG’s Christina Lake project has leading steam oil ratio (SOR) and operating costs, highlighting asset quality, advantaged economics and efficiency as an operator

1. Average SOR in 2021 up to May 31st per AER. MEG SOR includes the impact of eMVAPEX operations. 2. Based on results for three months ended March 30, 2021.3. MEG operating expense for three months ended March 30, 2021, shown net of power revenue of $3.14/bbl.4. Oil sands peers include Athabasca, Baytex, Cenovus and CNRL; peers selected based on availability of disclosure.

Average 2021 SOR1 Q1 2021 OPERATING EXPENSE2

(C$/bbl)MEG Christina Lake

• Potential for further SOR reduction via eMSAGP & eMVAPEX

3 4

$5.1 $0.8

$0.3

$1.3

18

$5.9 billion of tax pools immediately deductible

1. Refers to an illustrative amount of pools used annually, assuming deductions available, until fully exhausted.2. Tax pool value based on tax rate of 23% (tax pools as at December 31, 2020); Value presented per MEG share, using fully diluted shares outstanding as of December

31, 2020.3. Maximum theoretical value is calculated based on average 2021 tax rate of 23.0% applied to MEG’s total and immediately deductible tax pools, and using fully diluted

shares outstanding as of December 31, 2020.

$7.4 billion of tax pools

$5.9 billion of tax pools are immediately deductible

Non-Capital LossesCEE + SR&ED

CDEOther Pools

MATERIAL UNRECOGNIZED VALUE FROM TAX POOLS

A M O U N T O F P O O L S U T I L I Z E D

B Y Y E A R 1

I L L U S T R A T I V E V A L U E O F T A X P O O L S A T 8 . 0 %

D I S C O U N T R A T E

( C $ M M ) ( C $ B n ) ( C $ / s h ) 2

$500 $1.0 $3.15

$1,000 $1.3 $4.05

$1,500 $1.4 $4.40

$2,000 $1.4 $4.60

M A X I M U M T H E O R E T I C A L V A L U E 3

Total $1.7 Bn $5.50/sh2

Immediately Deductible $1.4 Bn $4.35/sh2

C O M P O S I T I O N O F T A X P O O L S ( C $ B I L L I O N )

Variable Sensitivity Range Impact to Funds Flow

WTI (US$/bbl) +/- $2.50/bbl

WTI:AWB Gulf Coast Diff. (US$/bbl) +/- $0.50/bbl

WTI:WCS Edmonton Diff. (US$/bbl) +/- $1.00/bbl

AECO Gas (C$/GJ) +/- 10%

Condensate (% of WTI) +/- 1%

Exchange Rate (C$/US$) +/- $0.01

Annual Average Apportionment (%) +/- 5%

+/- C$73 mm

+/- C$32 mm

+/- C$25 mm

+/- C$11 mm

+/- C$12 mm

+/- C$11 mm

+/- C$4 mm

19

CASH FLOW SENSITIV ITYUnhedged blend volumes result in significant torque to change in oil prices

Note: Sensitivity assumes base cash flows at US$65/bbl WTI (see page 10 for detailed pricing assumptions) and 92,000 bbls/d production. 1. Each sensitivity above is calculated independently, although changes in one variable may impact other variables.

ILLUSTRATIVE UNHEDGED FUNDS FLOW SENSITIVIT IES1

20

This presentation is not, and under no circumstances is to be construed to be a prospectus, offeringmemorandum, advertisement or public offering of any securities of MEG Energy Corp. (“MEG”). Neither the UnitedStates Securities and Exchange Commission (the “SEC”) nor any other state securities regulator nor anysecurities regulatory authority in Canada or elsewhere has assessed the merits of MEG’s securities or hasreviewed or made any determination as to the truthfulness or completeness of the disclosure in this document.Any representation to the contrary is an offence.

Recipients of this presentation are not to construe the contents of this presentation as legal, tax or investmentadvice and recipients should consult their own advisors in this regard.

MEG has not registered (and has no current intention to register) its securities under the United States SecuritiesAct of 1933, as amended (the “U.S. Securities Act”), or any state securities or “blue sky” laws and MEG is notregistered under the United States Investment Act of 1940, as amended. The securities of MEG may not beoffered or sold in the United States or to U.S. persons unless registered under the U.S. Securities Act andapplicable state securities laws or an exemption from such registration is available. Without limiting the foregoing,please be advised that certain financial information relating to MEG contained in this presentation was prepared inaccordance with International Financial Reporting Standards as issued by the International Accounting StandardsBoard, which differs from generally accepted accounting principles in the United States and elsewhere.Accordingly, financial information included in this document may not be comparable to financial information ofUnited States issuers.

DISCLAIMER

21

Forward-Looking InformationCertain statements contained in this presentation may constitute forward-looking statements within the meaning of applicable Canadian securities laws. These statements relate to futureevents or MEG's future performance. All statements other than statements of historical fact may be forward-looking statements. The use of any of the words "anticipate", “assume”,"continue", "estimate", "expect", "may", "will", "project", "should", "believe", "plan", "intend", “illustrative”, "target", "potential" and similar expressions are intended to identify forward-lookingstatements. Forward-looking statements are often, but not always, identified by such words. These statements involve projects, anticipated GHG known and unknown risks, uncertainties andother factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. In particular, and without limiting the foregoing, thispresentation contains forward-looking statements with respect to our 2021 capital budget, allocation and funding, future indigenous spending, expected free cash flow, marginal cash flow perbarrel, future production capability, demand for heavy oil, turnarounds, anticipated decline rates, steam oil ratio, full year 2021 guidance, including full year 2021 production, non-energyoperating costs, G+A and capital expenditures, the value of tax pools, our focus and strategy, safety protocols including those related to Covid-19, expected sustaining and maintenancecapital and growth capital, the anticipated annualized interest savings from refinancing's, additional debt reduction, our ESG initiatives including future GHG and methane reductions,governance rankings, diversity and inclusion targets, our projections and exposure to commodity prices and anticipated results from hedging activities, capital efficiencies associated withcertain ground water withdrawal intensities, market access and diversification plans, blend sales market exposure, Western Canadian incremental egress capacity, marginal egressinfrastructure, global refinery capacity additions, and plans to improve overall cost efficiencies.

Forward-looking information contained in this presentation is based on management's expectations and assumptions regarding, among other things: future crude oil, bitumen blend, naturalgas, electricity, condensate and other diluent prices, foreign exchange rates and interest rates; the recoverability of MEG's reserves and contingent resources; MEG's ability to produce andmarket production of bitumen blend successfully to customers; future growth, results of operations and production levels; future capital and other expenditures; revenues, expenses and cashflow; operating costs; reliability; anticipated reductions in operating costs as a result of optimization and scalability of certain operations; anticipated sources of funding for operations andcapital investments; plans for and results of drilling activity; the regulatory framework governing royalties, land use, taxes and environmental laws and Federal and Provincial climate changepolicies, and the timing and level of any future government apportionment, in which MEG conducts and will conduct its business; and business prospects and opportunities. By its nature,such forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risksinclude, but are not limited to: risks associated with the oil and gas industry, including the transition to a low carbon environment; the securing of adequate access to markets andtransportation infrastructure and to investment capital; the availability of capacity on the electricity transmission grid; the uncertainty of reserve and resource estimates; the uncertainty ofestimates and projections relating to production, costs and revenues; health, safety and environmental risks, including public health crises, such as the COVID-19 pandemic and relatedactions taken by governments and businesses; risks of legislative and regulatory changes to, amongst other things, tax, land use, royalty, environmental laws, and Federal and Provincialclimate change policies and curtailment of production policies; risks related to increased activism and public opposition to fossil fuel development; assumptions regarding and the volatility ofcommodity prices, interest rates and foreign exchange rates; risks and uncertainties related to commodity price, interest rate and foreign exchange rate swap contracts and/or derivativefinancial instruments that MEG may enter into from time to time to manage its risk related to such prices and rates; risks and uncertainties associated with securing and maintaining thenecessary regulatory approvals and financing to proceed with MEG’s future phases and the expansion and/or operation of MEG’s projects; risks and uncertainties related to the timing ofcompletion, commissioning, and start-up, of MEG’s turnarounds, and of future phases, expansions and projects; the operational risks and delays in the development, exploration, production,and the capacities and performance associated with MEG's projects; and uncertainties arising in connection with any future acquisitions and/or dispositions of assets. Although MEG believesthat the assumptions used in such forward-looking information are reasonable, there can be no assurance that such assumptions will be correct. Accordingly, readers are cautioned that theactual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautioned that the foregoing list ofassumptions, risks and factors is not exhaustive.

Further information regarding the assumptions and risks inherent in the making of forward-looking statements can be found in MEG's most recently filed Annual Information Form ("AIF"),along with MEG's other public disclosure documents. Copies of the AIF and MEG's other public disclosure documents are available through the Company's website atwww.megenergy.com/investors and through the SEDAR website at www.sedar.com. The forward-looking information included in this presentation is expressly qualified in its entirety by theforegoing cautionary statements. Unless otherwise stated, the forward-looking information included in this presentation is made as of the date of this presentation and MEG assumes noobligation to update or revise any forward-looking information to reflect new events orcircumstances, except as required by law.

This presentation contains future-oriented financial information and financial outlook information (collectively, "FOFI") about MEG's prospective results of operations including, withoutlimitation, cash flow and various components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautionedthat the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance shouldnot be placed on FOFI. MEG's actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefitsMEG will derive therefrom. MEG has included the FOFI in order to provide readers with a more complete perspective on MEG's future operations and such information may not be appropriatefor other purposes. MEG disclaims any intention or obligation to update or revise any FOFI statements, whether as a result of new information, future events or otherwise, except as requiredby law.

DISCLOSURE ADVISORIES

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Note: Values are rounded to the nearest million

Non-GAAP MeasuresThis presentation refers to the non-GAAP measure of free cash flow, as well as adjusted funds flow which is defined in Note 17 of the Q2 2021 Financial Statements. These terms may not be comparable to similar measures provided by other companies and are not intended to represent net cash provided by (used in) operating activities. These financial measures should not be considered in isolation or as an alternative to, or more meaningful than, MEG's consolidated statement of cash flow as determined in accordance with IFRS, as an indicator of financial performance.

Free cash flow is presented to assist management and investors in analyzing performance by the Corporation as a measure of the capacity of the business to repay debt, incur discretionary capital or increase returns to shareholders. Free cash flow is calculated as adjusted funds flow less capital expenditures.

DISCLOSURE ADVISORIES

T H R E E M O N T H S E N D E D J U N E 3 0

($mm) 2 0 2 1 2 0 2 0

Net cash provided by (used in) operating activities 180 117

Net change in non-cash operating working capital item (20) (48)

Funds flow from (used in) operations 160 69

Adjustments:

Payments on onerous contracts 6 -

Contract cancellation - 20

Adjusted funds flow 166 89

Capital expenditures (70) (20)

Free Cash Flow 96 69