Investor Presentation January 2017

Disclaimer This 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 Energy Corp. (“MEG”). Neither the United States Securities and Exchange Commission (the “SEC”) nor any other state securities regulator nor any securities regulatory authority in Canada or elsewhere 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. 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 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 state securities 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 United States 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 the foregoing, please be advised that certain financial information relating to MEG contained in this presentation was prepared in accordance with International Financial Reporting Standards 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. The information concerning petroleum reserves and resources appearing in this document was derived from a report of GLJ Petroleum Consultants Ltd. dated effective as of December 31, 2015, which has been prepared in accordance with the Canadian Securities Administrators National Instrument 51-101 entitled Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) at that time. The standards of NI 51-101 differ from the standards of the SEC. The SEC generally permits U.S. reporting oil and gas companies in their filings with the SEC, to disclose only proved, probable and possible reserves, net of royalties and interests of others. NI 51-101, meanwhile, permits disclosure of estimates of contingent resources and reserves on a gross basis. As a consequence, information included in this presentation concerning our reserves and resources may not be comparable to information made by public issuers subject to the reporting and disclosure requirements of the SEC. There are significant differences in the criteria associated with the classification of reserves and contingent resources. Contingent resource estimates involve additional risk, specifically the risk of not achieving commerciality, not applicable to reserves estimates. There is no certainty that it will be commercially viable to produce any portion of the resources. The estimates of reserves, resources and future net revenue from individual properties may not reflect the same confidence level as estimates of reserves, resources and future net revenue for all properties, due to the effects of aggregation. Further information regarding the estimates and classification of MEG’s reserves and resources is contained within the Corporation’s public disclosure documents on file with Canadian Securities regulatory authorities, and in particular, within MEG’s most recently filed annual information form (the “AIF”). MEG’s public disclosure documents, including the AIF, may be accessed through the SEDAR website (www.sedar.com), at MEG’s website (www.megenergy.com), or by contacting MEG’s investor relations department. Anticipated netbacks are calculated by adding anticipated revenues and other income and subtracting anticipated royalties, operating costs, transportation costs and realized commodity risk management gains(losses) from such amount.

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Disclosure Advisories Forward-Looking Information This document may contain forward-looking information including but not limited to: expectations of future production, revenues, expenses, cash flow, operating costs, steam-oil ratios, regulatory approvals, pricing differentials, reliability, profitability and capital investments; estimates of reserves and resources; the anticipated reductions in operating costs as a result of optimization and scalability of certain operations; and the anticipated sources of funding for operations and capital investments. Such forward-looking information is based on management's expectations and assumptions regarding future growth, results of operations, production, future capital and other expenditures, plans for and results of drilling activity, environmental matters, regulatory processes, 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 risks include, but are not limited to: risks associated with the oil and gas industry, for example, the securing of adequate supplies and access to markets and transportation infrastructure; the availability of capacity on the electricity transmission grid; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, 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 foreign exchange rate swap contracts and/or derivative financial 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 the necessary 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 of completion, commissioning, and start-up, of MEG’s 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 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 cautioned that 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 AIF, along with MEG's other public disclosure documents. Copies of the AIF and MEG's other public disclosure documents are available through the SEDAR website which is available at www.sedar.com. The forward-looking information included in this document is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this document is made as of the date of this document and MEG assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.

Market Data This presentation contains statistical data, market research and industry forecasts that were obtained from government or other industry publications and reports or based on estimates derived from such publications and reports and management’s knowledge of, and experience in, the markets in which MEG operates. Government and industry publications and reports generally indicate that they have obtained their information from sources believed to be reliable, but do not guarantee the accuracy and completeness of their information. Often, such information is provided subject to specific terms and conditions limiting the liability of the provider, disclaiming any responsibility for such information, and/or limiting a third party’s ability to rely on such information. None of the authors of such publications and reports has provided any form of consultation, advice or counsel regarding any aspect of, or is in any way whatsoever associated with, MEG. Further, certain of these organizations are advisors to participants in the oil sands industry, and they may present information in a manner that is more favourable to that industry than would be presented by an independent source. Actual outcomes may vary materially from those forecast in such reports or publications, and the prospect for material variation can be expected to increase as the length of the forecast period increases. While management believes this data to be reliable, market and industry data is subject to variations and cannot be verified due to limits on the availability and reliability of data inputs, the voluntary nature of the data gathering process and other limitations and uncertainties inherent in any market or other survey. Accordingly, the accuracy, currency and completeness of this information cannot be guaranteed. None of MEG, its affiliates or the underwriters has independently verified any of the data from third party sources referred to in this presentation or ascertained the underlying assumptions relied upon by such sources.

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Substantial Reserves and Resources Regulatory approval in place or in process for nearly 500,000 bpd of potential resource development

* 2017 production guidance

Proved Probable

Evaluated by GLJ Exploration lands

1,474 1,514

Proved and Probable Reserves

2,988

barrels in millions

Based on GLJ Reserve Report dated effective as of December 31, 2015

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Positioned to Grow Shareholder Value Comprehensive refinancing fully-funds growth to ~100,000 bpd, driving lower costs while significantly de-risking the business

Deliver highly economic growth

Strengthen the balance sheet

2B eMSAGP growth provides clear path to 100 kbpd; 2B brownfield to provide additional upside pending approval

Refinancing provides 5-year window to pursue deleveraging alternatives while growing the business

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Operational Update MEG continues to effectively execute on its operating strategies and has taken required steps to manage its business through the commodity price downturn Continuing use of proprietary eMSAGP technology

Maintaining production for less

Reducing costs, breakevens

•  Achieved near record production in 3Q16 of 83.4 kbpd with record low SOR of 2.2x •  SORs averaging 25% reduction in non-energy opex per barrel, and •  >20% reduction G&A expenses since 2014

Strong environmental performance

•  Net GHG intensity ~30% below average in-situ producer*

Diversifying markets

•  On-going execution of marketing strategies to diversify markets continue to reduce the differential for MEG’s heavy barrels

Active hedging program

•  Hedging program implemented to increase predictability of future cash flows while leaving room to take advantage of improving oil price fundamentals

* In-situ industry average estimate is calculated based on reported data to Environment Canada, Alberta Energy Regulator, and Alberta Electric System Operator

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High-Return, Short-Cycle Growth Near-term opportunities to grow Christina Lake production to >110 kbpd

Fully-funded by equity financing •  eMSAGP is a reservoir enhancement technology involving the injection of a non-condensable gas and the drilling of infills which allows for reduced steam requirement, increase production, reducing SORs. Freed up steam is redirected to new well pairs to further grow production. •  Builds off success of eMSAGP on Phases 1 and 2, to be applied to Phase 2B •  Capital involves drilling of infills/SAGD wells and minor facility debottlenecks •  Tremendous flexibility on pace of growth on a well-by-well basis

Additional upside •  Involves the addition of steam and debottlenecking of the oil processing capability at the central plant and drilling of SAGD well pairs •  Execution time frame of approximately 18 months

* The projects generate sustainable returns through 50-year+ economic lives

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Near-Term Production Growth Fully-funded eMSAGP growth initiative at Christina Lake Phase 2B supports 25% growth in production by early 2019 2B Brownfield growth opportunity to be funded as market conditions permit

MEG’s 2017 annual average production guidance is 80,000 to 82,000 bpd, with production anticipated to exit the year between 86,000 to 89,000 bpd. MEG will commence the 20,000 bpd eMSAGP growth initiative at Christina Lake Phase 2B during 2017, ramping up to full capacity by early 2019.

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Impact of Highly Economic Production Growth Incremental production expected to add minimal operating costs, generates very strong netbacks and is highly accretive to cash flow

Illustrative impact of production growth on netbacks based on 3Q16 operating results. Example assumes a constant WTI:WCS differential of 30%, $0.77 USD/CAD, and WTI of approximately US$45/bbl, as realized in 3Q16.

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Phase 1 eMSAGP Performance Resource recovery on track to exceed 70%, ~10% higher than SAGD Phase 1 single well-pattern performance*

* eMSAGP production data reflects average well performance across A1 to A3 (“SAGD only”) and average well performance across A1 to A3 + average infill (“SAGD + infill”)

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Phase 1 and 2 eMSAGP SOR Comparison eMSAGP deployed across ~30% of MEG’s production base with very consistent results, could be applied to Phase 2B over the next two years

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Implications of Efficiency Gains from eMSAGP Lowers SOR and energy costs

Increased production

Lower capital and operating costs

Other benefits

•  eMSAGP results in SORs being reduced by almost half

•  Enables more production with the same amount of steam •  Production increased via •  Infill wells •  New SAGD well pairs where freed-up steam has been redeployed •  As less steam is required per barrel, less capital is required to grow production •  Operating costs have a high fixed-component. Spreading costs over more barrels dramatically reduces per barrel operating costs

•  Quick investment to cash flow •  Flexibility on timing

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Net GHG Intensity Performance eMSAGP and cogeneration have enabled MEG to lower its GHG intensity 30% below in situ industry average

* Phase start-up: higher steam requirements with low initial production ** Net GHG intensity includes the associated benefits of cogeneration Sources: MEG”s net GHG data from 2010-2015 has been third-party verified. In-situ industry average estimate is calculated based on reported data to Environment Canada, Alberta Energy Regulator, and Alberta Electric System Operator.

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Continued Efficiency Gains Drive Lower Costs Ongoing efficiency gains drive lower operating costs and reduce MEG’s breakeven costs in a low oil price environment C$ per barrel unless specified

* Operating breakevens calculated based on actual data, period FX and differentials ** G&A expense and net finance expense calculated based on production volumes. Net finance expense includes accretion on provisions, unrealized gain/loss on derivative financial liabilities and realized gain/loss on interest rates swaps and is adjusted for capitalized interest

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Focused Cost Management Sustainable cost savings achieved through continued technological advancement and reductions in overall cost base

At current strip prices, MEG anticipates its US$2.5 billion revolver will be undrawn at the end of 2016 * Year to date 2016 data represents costs up to and including 3Q16. Per barrel non-energy operating costs are calculated based on sales volume; per barrel G&A expense are calculated based on production volume.

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2017 Capital and Operational Guidance Capital Investment Plan C$ millions

2B eMSAGP growth

320

Operational Guidance*

$5.75 $6.75

to per barrel

Non-energy operating costs

Marketing, corporate & other

70

80% $5.65

590 Sustaining & maintenance

200

of the total estimated cost of 2B eMSAGP growth initiative to be spent in 2017 sustaining capital per barrel

excluding turnaround costs of approximately $34M

80,000 82,000

to bpd

Average production

86,000 89,000

to bpd

Exit production

*Takes into account a major turnaround at Phase 2 and a minor turnaround at Phase 2B, both during 2Q17

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Debt Maturity Profile Debt refinancing retains covenant-lite structure, extends weighted-average life of debt maturity from 4 to >6 years with minimal increase in interest cost The 5-year undrawn credit facility has no financial maintenance covenants and is not subject to annual borrowing base redetermination

Excludes 1% annual amortization on the 1st lien term loan. Debt maturity profile does not include the EDC-backed letters of credit facility. Revised maturity profile contingent on completion of all proposed refinancing transactions. Refinancing transactions are expected to close by early February, 2017.

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Strong Financial Flexibility MEG has the highest available liquidity

MEG has the longest runway and maturity profile

MEG has a unique structure amongst its peers Sources: Company dislosure, FactSet Note: Weighted average maturity calculation assumes revolver is fully drawn; excludes accordion features and finance lease obligations. Comparison based on oil and gas peers with EVs between $2 bn and $15 bn, including: ARX, BIR, BNP, BTE, CPG, ERF, PEY, PGF, RRX, TOU, VII, VET, WCP.

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Active Hedging Program MEG’s objective is to set a floor price, at or above cash costs, while leaving room to take advantage of improving oil price fundamentals Crude oil hedges in place as of 11th January 2017

* Percentage of hedged volumes are based on the mid-point of 2017 annual production guidance of 80,000 - 82,000 bpd and assumes a ratio of 0.31 barrel of diluent per barrel of blend sales ** Includes certain "physical" hedges where forward sales based on fixed differentials have been contracted

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Notes

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Investor Relations Helen Kelly Director, Investor Relations 403.767.6206 [email protected]

John Rogers VP, Investor Relations and External Communications 403.770.5335 [email protected]

www.megenergy.com/investors