Investor Presentation February 2018

Transcription

1 Investor Presentation February 2018

2 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, 2016, which has been prepared in accordance with the Canadian Securities Administrators National Instrument entitled Standards of Disclosure for Oil and Gas Activities ( NI ) at that time. The standards of NI 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 , 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 ( at MEG s website ( 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. 2

3 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, emission intensity 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 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 forwardlooking information to reflect new events or circumstances, except as required by law. 3

4 Disclosure Advisories Non-GAAP 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, transportation, 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, operating costs, royalties and realized commodity risk management gains or losses from petroleum revenue proprietary, transportation, 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. 4

5 Impact of Technology on Business Model 5

6 Unlocking the Value of MEG s Midstream Assets MEG entered into an agreement with Wolf Midstream for the sale of its 50% interest in Access Pipeline and 100% interest in Stonefell Terminal for $1.61 billion Details of the transaction: The Transaction comprises the sale Access Pipeline for total consideration of $1.4B, and the sale of Stonefell for $210M MEG will receive $1.52B in cash at closing and a credit of $90M toward future expansions of Access Pipeline Implied value of 13.4x EBITDA Agreements securing MEG s access for its Christina Lake production and condensate transport for initial term of 30 years, access to Access Pipeline s unutilized 16 pipe upon conversion to transport NGLs on a long-term basis to support emvapex, and a 30-year arrangement for operational control and exclusive use of Stonefell Terminal s 900,000 bbls blend and condensate storage facility Annualized 2018 cash flow impact of the transaction $ millions Increase in transportation and storage costs Reduction in interest costs Net increase in cash costs $120 ($70) $50 MEG expects to more than offset incremental cash costs related to the transaction as additional barrels are brought on stream over time 6

7 Sources & Uses of Proceeds from Divestiture The transaction allows MEG to substantially pay down debt, pursue highly-economic growth projects, ensure future transportation/storage needs are met, while protecting the company s competitive cost position Figures in C$M Divestiture proceeds Sources $1,610 Uses Future expansion of the Access Pipeline (credit) Term loan repayment Transaction fees 2B Brownfield Expansion capital $90 $1,225 $20 $275 $1,610 $1, F 2019F $190 $85 7

8 Pro Forma Maturity Profile Divestiture of the Access Pipeline significantly improves MEG s financial position 8

9 2018 Capital and Operational Guidance Capital Investment Plan $ millions emsagp growth capital emvapex and future growth capital Sustaining and maintenance Field infrastructure, corporate & other. Original 2018 Capital Investment. Phase 2B Brownfield expansion. Revised 2018 Capital Investment. $120 $100 $220 $70 $510 $190 $700 Fully-funded through strong cash position, proceeds from Access Pipeline sale, and 2018 cash flow Operational Guidance $4.75 to $5.25 per barrel Non-energy operating costs 85,000 to 88,000 bpd Average production reflects 35-day turnaround during 2Q18 with 5-6 kbpd impact on annual production 95,000 to 100,000 bpd Exit production 9

10 High-Return, Short-Cycle Growth Fully funded near-term opportunities to grow Christina Lake production to 113 kbpd Phase 2B emsagp Growth 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. corner 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 20,000 bpd $350MM cost ~55% US$55 WTI Production expected to reach full capacity by early 2019 Phase 2B Brownfield Expansion Involves the addition of steam capacity and the addition of two well pads corner Production anticipated to begin ramp up in 2H19 to reach full capacity in ,000 bpd $275MM cost ~35% US$55 WTI * The projects generate sustainable returns through 50-year+ economic lives 10

11 Impact of Growth on Leverage Growth to 113,000 bpd by early 2020 contribute to higher margins, along with proceeds from divestiture of midstream assets, significantly improves the company s leverage position Based on US$60 WTI*, pro forma with Access Pipeline proceeds paying down debt *Forecast assumes: constant WTI price of US$60/bbl, C/US FX of 1.22 from , 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

12 emsagp* Model 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 original SAGD wells. The net amount of gas injected is significantly less than the amount saved through SOR reduction. 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. * enhanced Modified Steam and Gas Push, Canadian Patent 2,776,704 ** Steam and Gas Push (SAGP) is an invention by Dr. Roger Butler 12

13 Phase 1 and 2 emsagp Performance emsagp increases recovery at lower SORs 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 Phases 1 and 2 Overall Performance Recovery to Date Average SOR Initial SAGD Phase 28% 2.6 emsagp Phase (in progress) 34% 1.7 Cumulative Progress 62%

14 emvapex Conceptual Model A Modification of emsagp Inject condensable gas (CG) to: Maintain reservoir pressure, reducing steam injection to near zero Dilute the warm bitumen to further improve viscosity Partly de-asphalt the bitumen improving API gravity and value of product Warmed bitumen mixed with light hydrocarbon is pushed toward infill well by pressure difference and gravity. Freed-up steam is re-diverted to new SAGD well pairs to increase production. 14

15 Potential emvapex Benefits Further reduction of SOR over emsagp Lower capital requirements to grow $ Lower operating costs Lower carbon emission intensity Lower steam requirement per barrel reduces steam and water handling capacity necessary at the central plant facility to support future growth Reduced energy costs per barrel Growth results in fixed cost amortization across larger number of barrels, contributing to increased cash margin per barrel Significantly lower steam requirement per barrel directly translate into lower GHG intensity per barrel 15

16 emvapex Pilot 16

17 Net GHG Intensity Performance emsagp and cogeneration have enabled MEG to lower its GHG intensity 25% 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 has been third-party verified 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. 17

18 Continued Efficiency Gains Drive Lower Costs Highly-economic growth expected to further reduce cash costs by C$1 per barrel with every 10kbpd of new production coming on stream * 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 18

19 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 prices Crude oil hedges in place as of February 8, 2018 in US$ * Percentage of hedged volumes are based on the mid-point of 2018 annual production guidance of 85,000-88,000 bpd and assumes a blend ratio of 0.45 barrel of diluent per barrel of bitumen 19

20 Substantial Reserves and Resources Regulatory approval in place or in process for nearly 500,000 bpd of potential resource development * 2018 production guidance Evaluated by GLJ Exploration lands Proved and Probable Reserves barrels in millions Proved 1,468 Probable 1,517 2,985 Based on GLJ Reserve Report dated effective as of December 31,

21 Notes 21

22 Investor Relations Helen Kelly Director, Investor Relations John Rogers VP, Investor Relations and External Communications