CREATING SUSTAINABLE

VALUESeptember Investor Presentation

ü

Objectives & Priorities

2

Focus on capital disciplineand free cash flow generation

Debt reduction and balance sheet strength

Improve market access

Existing production capacity, supported by low operating costs and low sustaining capital, generates material free cash flow

Free cash flow will continue to be earmarked for debt reduction

Maximize the pricing received for MEG’s blended barrels through increasing access to world-priced markets and mitigating impact of on-going apportionment

Generated $293 MM free cash flow in 1H19

G&A reductions to support lower levels of capital go-forward

Delivered 33% of sales to USGC in 1H19, realizing ~US$3.70 per bbl premium on average vs Canada

Forecast ~3.00x total net debt to EBITDA at YE19 at strip commodity prices(1)

1. Assumes average WTI price of ~ US$53-54 and WCS differential of US$14-15 per barrel at Hardisty for remainder of 2019

Material debt reduction using free cash flow with C$285 mm repayment of term loan and reduced credit facilities

ü

ü

ü

Disciplined 2019 Capital ProgramCapital budget of $200 million prioritizes financial strength while maintaining flexibility to support production growth beyond 2019

• Budget fully-funded from forecast adjusted funds flow supports 100,000 bbls/d of production capacity

• $40MM supports in development production growth at Christina Lake beyond 2019, including increased central plant facility throughput to 120,000 bbls/d and investment in eMVAPEX pilot

3

$40MM

$115MM

Operational Guidance2019 Guidance

Production – average (bbls/d) 90,000 to 92,000

Non-energy operating costs ($/bbl) $4.75 to $5.25

G&A costs ($/bbl) $1.95 to $2.05

2019 Capital Budget $200MM

Sustaining and Maintenance $115MM

Growth $40MM

Field Infrastructure, Corporate and Other $45MM

Operational guidance assumes the Alberta Government mandated production curtailment remains in place for 2019 while easing over the course of the year. If curtailments were not in place, MEG would have the ability to average 100,000 bbls/d in 2019

$0.00

$0.50

$1.00

$1.50

2019B(3)

Sources Uses

2020F(3)

Sources Uses

2021F(3)

Sources Uses

2022F(3)

Sources Uses

2023F(3)

Sources Uses

Sources & Uses of Funds

Adjusted Funds Flow US$70/bbl WTI(1)

Adjusted Funds Flow US$60/bbl WTI(1)

Adjusted Funds Flow US$50/bbl WTI(1)

Free Cash Flow Capital(2)

100,000 bbls/d Builds Material Free Cash Flow

4

Near-term free cash flow focused on debt reduction; longer-term free cash flow can also be directed to highly economic growth and/or shareholder returns – significant optionality depending on market conditions

Note: Adjusted funds flow and free cash flow as referred to throughout this presentation are non-GAAP measures; please see Disclosure Advisories for further details; see page 17 for key assumptions.1. Adjusted funds flow assumes average WTI price for the full year and includes current hedge book.2. Capital expenditure assumes sustaining and maintenance capital of $6 - 8 / bbl. Forecasted figures from 2020F through 2023F are subject to board approval. 3. Forecast 2019 production is based on production guidance of 90,000 – 92,000 bbls/d. Forecast production assumes a preliminary 90,000-92,000 bbls/d in 2020 due to continued curtailment and 100,000 bbls/d in

each of the years thereafter.

C$ bn

Improving egressincreases funds flow

Sales to higher-priced USGC market increases from approximately one-third to two-thirds of blend volumes

Capital Markets Debt Maturities

$1,000

@ 7.00%

$750

@ 6.50%

$800

@ 6.375%

Debt repayment / refinancing runway

20202019 2021 2022 2023 2024 2025

US$ in Millions

Unsecured notes2nd lien note

USGC Heavy Oil Market Outlook

5

Well-positioned to access strong USGC market with firm commitment on Flanagan/Seaway, increasing from 50,000 bbls/d currently to 100,000 bbls/d starting mid-2020

1. Muse Stancil2. Eight Capital research, “Where is my mind? On the tsunami of petrochemical related oil demand coming on

line this year and beyond”. April 2019.

Growing global demand and forecast shortfall in heavy crude supply at USGC supports attractive continued long-term market outlook for MEG barrels

USGC is expected to be short >500 mbbls/d of heavy sour crude by 2020, with limited prospects for additional supply outside of Canadian heavy oil

The shortfall has significantly increased this year:• Venezuelan medium-term production remains at risk

• Political turmoil, slow-motion debt default, Chinese loans that are repaid with crude, and US sanctions, will limit exports to USGC

• Mexican production at record low

In addition, analysts estimate an incremental ~1.5 mmbbls/d of medium/heavy global demand growth in 2019(2) which will further decrease supply available to the USGC

• Commencement of 400 mbbls/d Jazan Refinery in Saudi Arabia

• Planned start-up of four new crude to chemicals refineries with a combined ~1.0 mmbbls/d medium/heavy demand

USGC Heavy Crude Imports(1)

YTD Venezuelan imports are down from 600 kbbls/d to ~10 kbbls/d in May

Enterprise TE

Enbridge Mainline

Edmonton

Chicago

St. James

Bayou Bridge

Flanagan South / Seaway

Hardisty

Cushing

Beaumont / Mont Belvieu

Bruderheim

Assets to Access High Value Markets

6

100 mbbls/d on Flanagan South/Seaway (2H20)• Direct access to USGC• Supply/demand imbalance provides long-term

pricing support• None of capacity is dependent on Line 3 replacement

1.4 mmbblsU.S. storage • Optimizes Flanagan commitments and exports

Marine export access• From MEG assets at Beaumont and St. James

1.4 mmbblsWestern Canadian Storage • Manages Enbridge apportionment

40-50% condensate purchases from USGC • Access over-supplied USGC market • Reduces exposure to AB market volatility

Strategic marketing assets de-risk the business and enhance net realized bitumen price

Future 20,000 bpdon TMX• Access to tidewater and

delivery to growing Asian heavy oil market

• Construction re-start targeting mid 2022 in service date

30,000 bbls/d rail loading capacity• Secures apportionment-protected sales• Combination of FOB and delivered sales capacity

1. Committed capacity on Flanagan/Seaway pipelines subject to Enbridge Mainline apportionment2. Blend sales volumes assumes blend ratio of 0.45 barrel of diluent per barrel of bitumen produced and a non-curtailed production

environment.

Flanagan South/Seaway

Flanagan South/Seaway

Rail

Rail

-

20

40

60

80

100

120

140

160

2019F 2H20F

Blen

d Sa

les

mbb

ls/d

Western Canada

Western Canada

7

Strategic Market AccessContracted egress capacity in place for up to 90%(1) of volumes post 2H20 with growing exposure to premium USGC market

90 – 92 mbbls/d bitumen production

~100 mbbls/d bitumen production

capacity

~132 mbbls/d blend sales(2)

~145 mbbls/d blend sales capacity(2)

30,000 bbls/d of contracted rail loading capacity

Subject to ENB Mainline apportionment

Flanagan South/Seaway + rail provides access to premium North American marketsYTD 2019 Gulf Coast market pricing, after transportation, at US$3.70 / bbl blend premium to Western Canada

Beyond 2H2020

Actual 1H19 resultsUS$/bbl, except as indicated Pipeline FOB Rail Pipeline Delivered Rail

WTI 57.36$ 57.36$ 57.36$ 57.36$ 57.36$ 76.49$ Differential - WTI:AWB at sales point (14.60) (10.18) 1.19 (2.31) (9.20) (12.27)$

Blend sales price 42.76 47.18 58.55 55.05 48.16 64.22 Transportation and storage(1) (1.72) (4.14) (10.58) (24.50) (5.68) (7.57)$ Transportation and storage Christina Lake to Edmonton (2) 1.72 1.72 1.72 1.72 1.72 2.29$ AWB sales price, net of transportation 42.76$ 44.76$ 49.69$ 32.28$ 44.20$ 58.95$

43.02$ 46.68$ Total blend sales - mbbls/d 77 13 36 8 % of total sales 57% 10% 27% 6%

2019 Full year outlookUS$/bbl, except as indicated Pipeline FOB Rail Pipeline Delivered Rail

AWB sales price(3) WTI less $13 - $15 WTI less $2 - $3 WTI less $10 - $12General transportation (net)(2) ($2) ($2) ($2) ($2)Market specific transportation & storage(2) - ($1 - 2) ($8 - 9) ~($20) NATotal blend sales - mbbls/d(4) remainder 10 - 20 35 5 - 10 132

135 100%

TOTAL(US$/bbl)

TOTAL(C$/bbl)

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

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

8

Blend Sales by Market

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, was C$11.03 per barrel for the six months ended June 30, 2019.

2. Includes all transportation costs associated with moving barrels of blend from Christina Lake to Edmonton sales point.3. Results are translated at the average foreign exchange rate of 1.33354. Based on actual and indicative pricing as of July 30, 2019, Edmonton market pricing assumes WTI: WCS differential of US$13-$14.5. Assumes mid-point of MEG's 2019 production guidance at 91,000 bbls/d, multiplied by estimated blend ratio of 1.45x.6. Actual delivered rail costs of US$24/bbl of blend in 1H19 were impacted by fixed costs associated with underutilized capacity at the Bruderheim Terminal and costs associated with the

change out of leased rail car fleet. MEG anticipates increasing utilization of its 30,000 bbls/d of contracted rail loading capacity later this year. Normalized delivered rail costs from Edmonton to the Gulf Coast are estimated to be in the range of US$18-$20/bbl blend.

(6)

45

55

65

75

2013 2014 2015 2016 2017 2018 *

MEG Industry Average

Focus on Sustainability –Industry Leading Track Record

9

MEG is a leader in lowering Greenhouse Gas (GHG) intensity• Technological innovation, such as eMSAGP,

eMVAPEX and cogeneration have driven MEG’s GHG intensity down by 9% since 2013

• MEG has the second lowest net GHG intensity among the in situ peer group

• MEG uses cogeneration at its facilities with excess power being sold into Alberta Power Market –cogeneration offers a cleaner alternative relative to coal-fired generation which makes up the largest portion of Alberta’s power generation capacity today

Net GHG Intensity (kg CO2e/bbl))

- 0.10 0.20 0.30 0.40 0.50 0.60 0.70

2013 2014 2015 2016 2017 2018

MEG Industry Average

Water Withdrawal Intensity(bbl water per bbl bitumen)

MEG does not use any surface water from streams, rivers or lakes in its operations• In 2018, MEG recycled 90% of water recovered from

the reservoir to generate steam with remainder coming from deep non-potable sub-surface reservoirs

• MEG’s eMSAGP and eMVAPEX processes enables MEG to reduce its total water withdrawal intensity

• MEG’s 2018 withdrawal intensity was 0.18, which is 57% lower than the industry average

• No water used in MEG’s processes is discharged into the environment

More than 20% below in situ industry average

68% decrease since 2013

APPENDIX

10

Strategy focused on protecting capital program while providing flexibility to fund debt reduction and/or growth; targets locking in a realized bitumen price to reduce cash flow volatility

Commodity Price Hedging

11

3Q19 4Q19 2020WTI Fixed Price Hedges

Volume (bbls/d)(1) 52,213 48,079 17,000 Weighted average fixed WTI price (US$/bbl) $ 62.31 $ 62.91 $ 59.56 % of forecast blend sales hedged(2) 40% 36% n/a

WTI:WCS Fixed Differential HedgesVolume (bbls/d)(3) 57,702 57,050 30,150 Weighted average fixed WTI:WCS differential at Edmonton (US$/bbl) $ (21.10) $ (21.15) $ (20.14)% of forecast blend sales hedged(2) 44% 43% n/a

Condensate Hedges(2)

Volume (bbls/d) 15,000 15,000 15,000 Average % of WTI landed in Edmonton(4) 102% 102% 102%% of forecast condensate purchases hedged(2) 37% 37% n/a

Physical Forward Condensate Purchases(5)

Volume (bbls/d) 13,338 13,338 4,127Average % of WTI landed in Edmonton 97% 97% 90%% of forecast condensate purchases hedged(2) 33% 33% n/a

1. In addition, MEG has hedged 2,292bbls/d of incremental 3Q19 blend sales at US$57.04/bbl to lock in economics of purchasing curtailment volumes from other producers.2. Percentage of hedged volumes are based on the mid-point of 2019 annual production guidance of 90,000 - 92,000 bbls/d and assumes a blend ratio of 0.45 barrel of diluent per

barrel of bitumen.3. 2020 includes 13,150 of physical forward rail blend sales at a fixed WTI:AWB differential.4. MEG’s condensate hedges settle against the OPIS Mont Belvieu Non-Tet Natural Gasoline reference price. The average % of WTI landed in Edmonton includes estimated

transportation costs from the Gulf Coast to Edmonton of approximately US$7/bbl.5. Physical forward condensate purchases are all at Edmonton.

As of July 29th, 2019

Base 2B BrownfieldExpansion

Additional Steam(5th and 6th OTSGs)

eMVAPEX 2B4X BrownfieldExpansion

12

Inventory of Highly Economic GrowthOptional growth projects identified to support buildout to 210,000 bbls/d at Christina Lake are execution ready – pace of growth dependent on market conditions

~100,000 bbls/d 2019 production

capacity +13,000 bbls/d

~210,000+ bbls/d

ü Capital efficiency of $20-25k/bbls/d(1)

ü Regulatory approvalü Engineeringü Site preparation ü Equipment

purchased

Note: Capital efficiency includes both central processing facility and well capital on a full-cycle basis; ultimate timing of projects would be determined based on a number of factors including commodity prices and resultant availability of funding and board approval.1. Includes debottleneck capital to support eMVAPEX expansion.2. Included in base capital program in 2019. 3. Production capacity of ~52,000 bbls/d at 2.4 SOR, up to ~60,000 bbls/d at 2.1 SOR; Capital efficiency at a 2.1 SOR.

ü Capital efficiency of ~$21k/bbls/d

ü 60% complete ü ~$110MM of

capital spend remaining

+~52,000+ bbls/d

+~30,000 bbls/d+17,000 bbls/d

ü Complete

ü Capital efficiency of <$20k/bbls/d

ü Pilot results exceeding expectation on lowering SOR

ü Short cycle repeatable execution

ü On-going pilot investment in 2019 budget(2)

ü Capital efficiency of $30-35k/bbls/d(3)

ü Regulatory approvalü Engineeringü Site preparation ü Equipment

purchased

Significant growth options beyond 113,000 bbls/d

$5.1

$0.8

$0.3

$1.5

13

Material Unrecognized Value from Tax Pools$5.9 billion of tax pools immediately deductible

1. Refers to the amount of tax pools utilized while the pools are fully deductible.2. Tax pool value based on step down in tax rate from 27% to 23% over next 4 years; Value presented per MEG share, using fully diluted shares outstanding as of June 30, 2019.3. Maximum theoretical value is calculated based on average 2019 tax rate of 26.5% applied to MEG’s total and immediately deductible tax pools, and using fully diluted shares

outstanding as at of June 30, 2019.

$7.7 billion of tax pools

$5.9 billion of tax pools are immediately deductible

Amount of PoolsUtilized by Year(1)

(C$MM)

Illustrative Value of Tax Poolsat 8.0% Discount Rate

(C$Bn) (C$/sh)(2)

Maximum Theoretical Value(3)

$500 $1.0 $3.95

$1,000 $1.3 $4.40

$1,500 $1.5 $4.90

$2,000 $1.6 $5.20

Total $2.1 Bn $6.65/sh(2)

Immediately Deductible $1.6 Bn $4.95/sh(2)

Non-Capital Losses

CEE + SR&ED

CDE

Other Pools

Composition of Tax Pools (C$ billion)

DisclaimerThis presentation is not, and under no circumstances is to be construed to be a prospectus, offering memorandum, advertisement or public offering of any securities of MEG EnergyCorp. (“MEG”). Neither the United States Securities and Exchange Commission (the “SEC”) nor any other state securities regulator nor any securities regulatory authority in Canada orelsewhere has assessed the merits of MEG’s securities or has reviewed or made any determination as to the truthfulness or completeness of the disclosure in this document. Anyrepresentation to the contrary is an offence.Recipients of this presentation are not to construe the contents of this presentation as legal, tax or investment advice 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 Securities Act of 1933, as amended (the “U.S. Securities Act”), or any statesecurities or “blue sky” laws and MEG is not registered under the United States Investment Act of 1940, as amended. The securities of MEG may not be offered or sold in the UnitedStates or to U.S. persons unless registered under the U.S. Securities Act and applicable state securities laws or an exemption from such registration is available. Without limiting theforegoing, please be advised that certain financial information relating to MEG contained in this presentation was prepared in accordance with International Financial ReportingStandards as issued by the International Accounting Standards Board, 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 of United States issuers.

14

Disclosure AdvisoriesForward-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", "continue","estimate", "expect", "may", "will", "project", "should", "believe", "plan", "intend", “target”, “potential” and similar expressions are intended to identify forward-looking statements. Forward-looking statements are often, but not always, identified by such words. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results orevents to differ materially from those anticipated in such forward-looking statements. In particular, and without limiting the foregoing, this presentation contains forward looking statementswith respect to our forecast base capital budget, allocation and funding, expected 2019 and future funds flow, free cash flow, adjusted funds flow, future production capability, and targetproduction, non-energy operating costs, our focus and strategy, expected sustaining and maintenance capital and growth capital, market access and diversification plans and plans toimprove 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 andcash flow; operating costs; reliability; anticipated reductions in operating costs as a result of optimization and scalability of certain operations; anticipated sources of funding for operationsand capital investments; plans for and results of drilling activity; the regulatory framework governing royalties, land use, taxes and environmental matters, including the timing and level ofgovernment apportionment easing, in which MEG conducts and will conduct its business; and business prospects and opportunities. By its nature, such forward-looking information involvessignificant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated.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 risks include, but are not limited to: risks associated with the oil and gas industry, for example, results securing access to markets and transportation infrastructure and thecommitments and risks therein; extent and timelines of the Alberta Government's mandatory production curtailment program; outlook for regulatory approval timelines for the SurmontProject; availability of capacity on the electricity transmission grid; uncertainty of reserve and resource estimates; uncertainty associated with estimates and projections relating toproduction, costs and revenues; health, safety and environmental risks; risks of legislative and regulatory changes to, amongst other things, tax, land use, royalty and environmental laws;assumptions regarding and the volatility of commodity prices, interest rates and foreign exchange rates, and, risks and uncertainties related to commodity price, interest rate and foreignexchange rate swap contracts and/or derivative financial instruments that the Corporation may enter into from time to time to manage its risk related to such prices and rates; risks anduncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the Corporation's future phases and the expansion and/oroperation of the Corporation's projects; risks and uncertainties related to the timing of completion, commissioning, and start-up, of the Corporation's future phases, expansions and projects;the operational risks and delays in the development, exploration, production, and the capacities and performance associated with the Corporation's projects; and uncertainties arising inconnection with any future disposition of assets.

Although MEG believes that 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 the actual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautionedthat the foregoing list of assumptions, 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 websiteat www.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 the foregoing cautionary statements. Unless otherwise stated, the forward-lookinginformation included in this presentation is made as of the date of this presentation and MEG assumes no obligation to update or revise any forward-looking information to reflect newevents or circumstances, 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 beappropriate for 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 required by law.

15

2019B 2020F 2021F 2022F 2023F

WTI US$/bbl $60.00 $60.00 $60.00 $60.00 $60.00

WTI:WCS Differential US$/bbl $12.50 $15.00 $18.00 $15.00 $15.00

WTI:AWB Gulf Coast Differential US$/bbl $2.25 $6.50 $5.75 $6.50 $6.50

Condensate (% of WTI) % 95% 97% 100% 100% 100%

Delivered Gas Cost C$/mcf $1.95 $2.10 $2.15 $2.20 $2.35

Exchange Rate C$/US$ 1.29 1.29 1.29 1.29 1.29

Mainline Apportionment % 40% 40% 30% 15% 0%

Funds Flow Sensitivities(2)

WTI (US$/bbl) - $1/bbl change C$MM $11

WTI:WCS Diff. (US$/bbl) - $1/bbl change C$MM $18

WTI:AWB Diff. (US$/bbl) - $1/bbl change C$MM $18

Condensate (% of WTI) - 1% change C$MM $6

Gas Cost (C$/mcf) - $0.25/mcf change C$MM $9

Exchange Rate - $0.01 change C$MM $9

Pricing Assumptions(1)

Disclosure Advisories

16

The following table shows the key assumptions used in the cash flow, free cash flow and cash flow yield estimates included in this presentation:

Note: 2019 pricing and 2020 WTI:WCS differential as at August 22, 20191. At US$50/bbl WTI, differentials are narrowed by US$1/bbl and at US$70/bbl WTI, differentials are widened by US$1/bbl.2. Including current hedge position.

Disclosure AdvisoriesNon-GAAP Measures

17

Certain financial measures within this presentation including adjusted funds flow, free cash flow and total net debt to earnings before interest, tax, depreciation and amortization(“Total Net Debt to EBITDA”) are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measuresshould 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 anindicator of financial performance.

Adjusted funds flow is used by management to analyze operating performance and liquidity. The definition and reconciliation of adjusted funds flow is presented in the “Non-GAAPMeasures” section of the Corporation's Management’s Discussion and Analysis for the quarter ended June 30, 2019.

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, incurdiscretionary capital or increase returns to shareholders. Free cash flow is calculated as adjusted funds flow less total cash capital investment.

Total net debt to EBITDA is used to monitor the Corporation’s capital structure and financial position. Net debt is calculated as current and long-term portions of long-term debt, net ofcash and cash equivalents. EBITDA is defined as net earnings (loss) before income tax expense (recovery), net finance expense, depletion and depreciation, gain on assetdispositions, unrealized loss (gain) on commodity risk management, realized/unrealized net loss (gain) on foreign exchange and stock-based compensation calculated on a trailingtwelve-month basis.

1. A gain related to the settlement of forward currency contracts to manage the foreign exchange risk on those Canadian dollar denominated proceeds related to the sale of assets designated for U.S. dollar denominated long-term debt repayment.

($000) 2019 2018 2019 2018

Net cash provided by (used in) operating activities 301,941 65,243 232,212 183,269 Net change in non-cash operating working capital items (75,044) (51,836) 145,243 (59,972)

Funds flow from (used in) operations 226,897 13,407 377,455 123,297 Adjustments:

Realized gain on foreign exchange derivatives (1) - - - (35,362)Payments on onerous contracts - 4,236 - 10,244 Decommissioning expenditures 65 750 441 3,371

Adjusted funds flow 226,962 18,393 377,896 101,550 Total cash capital investment (31,859) (182,567) (85,152) (330,306)Free cash flow 195,103 (164,174) 292,744 (228,756)

Six months ended June 30Three months ended June 30

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Investor RelationsT 403.767.6206E invest@megenergy.com

Media RelationsT 403.767.1485E media@megenergy.com