Investor Presentation June 2017 Disclaimer This presentation is - - PowerPoint PPT Presentation

Investor Presentation

June 2017

Disclaimer

2 INVESTOR PRESENTATION 2017

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, 2016, 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

• thers. 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.

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.

Disclosure Advisories

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Non-GAPP Measures

Certain financial measures within this presentation including cash operating netback and corporate netback are non-GAAP measures. These terms are not defined by International Financial Reporting Standards (“IFRS”) and, therefore, may not be comparable to similar measures provided by other companies. These non- GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Cash operating netback is the per-unit calculation of operating cash flow. Operating cash flow is a non-GAAP measure widely used in the oil and gas industry as a supplemental measure of the Corporation’s efficiency and its ability to fund future capital investments. Operating cash flow is calculated by deducting the related diluent expense, transportation expense, operating expenses, royalties and realized commodity risk management gains or losses from petroleum revenue - proprietary and power revenues. The per unit-calculation of operating cash flow, defined as cash operating netback, is calculated by deducting the related diluent expense, transportation expense, operating expenses, royalties and realized commodity risk management gains or losses from petroleum revenue - proprietary and power revenues, on a per barrel of bitumen sales volume basis. Corporate netback is a further measure of the Corporation’s ability to fund future capital investments. Corporate netback is calculated by further deducting general and administrative expense and net finance expense, on a per barrel of bitumen sales volume basis, from cash operating netback.

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.

Disclosure Advisories

4 INVESTOR PRESENTATION 2017

Proved and Probable Reserves

barrels in millions

Substantial Reserves and Resources

Regulatory approval in place or in process for nearly 500,000 bpd

• f potential resource development

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Evaluated by GLJ Exploration lands

Probable

1,517

2,985

Proved

1,468

Based on GLJ Reserve Report dated effective as of December 31, 2016 * 2017 production guidance

Positioned to Grow Shareholder Value

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2B eMSAGP and Brownfield growth provides clear path to 113 kbpd; incremental 10-20 kbpd expansions pave way to 210 kbpd

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

Strengthen the balance sheet Deliver highly economic growth

Growth from 80 to 113 kbpd can be internally funded at ≤US$55 WTI Growth beyond to 210 kbpd can be internally funded at ~US$50 WTI

Operational Update

7 INVESTOR PRESENTATION 2017

• eMSAGP deployed across ~30% of

production base, resulting in low corporate SOR of 2.3x in 2016

• SORs averaging <1.0x in

Phase 1 where eMSAGP has been deployed since late 2011

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 Strong environmental performance Diversifying markets Active hedging program

• Low levels of anticipated 2017

sustaining and maintenance capital of $5.65/bbl and $1.15/ bbl respectively

• >25% reduction in non-energy
• pex per barrel, and
• >20% reduction G&A expenses

since 2014

• On-going execution of marketing

strategies to diversify markets continue to reduce the differential for MEG’s heavy barrels

• Net GHG intensity 25%

below average in-situ producer*

• 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 the most recent reported data to Environment Canada, Alberta Energy Regulator, and Alberta Electric System Operator

Impact of Technology on Business Model

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2B Brownfield Growth eMSAGP Growth (fully-funded)

corner corner

High-Return, Short-Cycle Growth

Near-term opportunities to grow Christina Lake production to ~113 kbpd

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

• 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

Reduces cash costs by ~$4-5/bbl

• 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

Reduces cash costs by a further ~$2/bbl

~13,000 bpd @ <$30,000 flowing bbl >25% IRR @ US$55 WTI ~20,000 bpd $400M cost >50% IRR @ US$55 WTI

Profitable Production Growth

eMSAGP and brownfield expansions capable of delivering ~10% CAGR at Christina Lake at ≤ US$55 WTI

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• The fully-funded 20,000 bpd eMSAGP growth initiative at Christina Lake Phase 2B

commences during 2017, ramping up to full capacity by early 2019, taking production to ~100,000 bpd

• Subject to market conditions, MEG could commence the 13,000 bpd

2B Brownfield expansion in 2H18, with completion timeframe

• f ~18 months. Production could reach

~113,000 bpd in 2020

Impact of Highly Economic Production Growth

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Illustrative impact of production growth on netbacks based on 4Q16 operating results. Example assumes a constant WTI:WCS differential of 29%, $0.75 USD/CAD, and WTI of approximately US$49/bbl, as realized in 4Q16.

Incremental production expected to add minimal operating costs, generates very strong netbacks and is highly accretive to cash flow

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Implementation of 2B eMSAGP and Brownfield expansion contribute to higher margins and cash flow to organically de-lever the company

Impact of Production Growth on Leverage

*Forecast assumes: constant WTI price of US$55/bbl, C/US FX of 1.30 for 2017 and 1.275 from 2018-20, the full ramp-up of 2B eMSAGP to 20,000 bpd by early 2019 and the completion of the 13,000 bpd 2B brownfield project by early 2020

D/EBITDA could reach 3-4x at ~113 kbpd independent of further deleveraging initiatives

Based on US$55 WTI*

eMSAGP* Conceptual Model

13

A Modification of SAGD

Inject non-condensable gas (NCG) to maintain reservoir pressure, reducing steam injection by >50% via scavenging heat from hot reservoir rocks, while sustaining production in the

• riginal SAGD wells. The net amount of

gas injected is significantly less than the amount saved through SOR reduction.

* enhanced Modified Steam and Gas Push, Canadian Patent 2,776,704 ** Steam and Gas Push (SAGP) is an invention by Dr. Roger Butler

1 2 3

Warmed bitumen is pushed toward infill well by pressure difference and gravity. Freed-up steam is re-diverted to new SAGD well pairs to increase production.

INVESTOR PRESENTATION 2017

Phase 1 and 2 eMSAGP Performance

• Phase 1 observed a SOR reduction of 50%

during the period which eMSAGP has been applied with an estimated 10% increase in recovery as compared to SAGD

• Phase 2, which is ~10x the size of Phase 1,

has demonstrated similar success

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eMSAGP increases recovery at lower SORs

Phases 1 and 2 Overall Performance Recovery to Date Average SOR Initial SAGD Phase 30% 2.6 eMSAGP Phase (in progress) 30% 1.7 Cumulative Progress 60% 2.1

Net GHG Intensity Performance

eMSAGP and cogeneration have enabled MEG to lower its GHG intensity 25% below in situ industry average

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Sources: MEG’s net GHG data from 2010-2015 has been third-party verified. 2016 data is preliminary. In-situ industry average estimate is calculated based on the most recent reported data to Environment Canada, Alberta Energy Regulator, and Alberta Electric System Operator. * Phase start-up: higher steam requirements with low initial production ** Net GHG intensity includes the associated benefits of cogeneration

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

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* Per barrel costs and netbacks are calculated based on sales volume ** Net finance expense includes accretion on provisions, unrealized gain/loss on derivative financial liabilities and realized gain/loss on interest rates swaps

590

2017 Capital and Operational Guidance

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Non-energy operating costs

Operational Guidance*

80,000 to 82,000 bpd $5.75 to $6.75 per barrel

Average production

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

Capital Investment Plan

Cash and cash equivalents as of March 31st fully-funds the remainder of the 2017 capital investment plan $549 million

C$ millions

Total cash capital invested year-to-date $78 million

eMVAPEX, marketing, & other

70

2B eMSAGP growth

80% of total estimated cost

320

Sustaining & maintenance

200

86,000 to 89,000 bpd

Exit production

Debt Maturity and Ratings

Debt refinancing retains covenant-lite structure, extends weighted-average life of debt maturity from 4 to >6 years with minimal increase in interest cost

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Excludes 1% annual amortization on the 1st lien term loan. Debt maturity profile does not include the EDC-backed letters of credit facility. The maturity of the 5-year undrawn credit facility has been extended by 2 years. It has no financial maintenance covenants and is not subject to annual borrowing base redetermination.

Credit Ratings

S&P BB- stable Fitch B negative Moody’s B3 stable

as of May 1st, 2017

MEG’s objective is to set a floor price, at or above cash costs, while leaving room to take advantage of improving oil prices

Active Hedging Program

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Crude oil hedges in place as of May 1st, 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 blend ratio of 0.45 bbl of diluent per barrel of bitumen ** Includes certain contracted forward sales where the WTI:WCS differential has been fixed

Notes

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Investor Relations

www.megenergy.com/investors Helen Kelly

Director, Investor Relations 403.767.6206 helen.kelly@megenergy.com

John Rogers

VP, Investor Relations and External Communications 403.770.5335 john.rogers@megenergy.com