docthe 2015 Q4 Suncor Investor
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the 2015 Q4 Suncor Investor
Suncor Investor Information Updated March 2016 Cover photograph is Suncor’s #2 Upgrader at the Oil Sands base plant Canada’s leading integrated energy company Growing oil sands business with complementary upstream & downstream operations $63B 578 mboe/d 35 years 462 mb/d $6.8B $6.2B $11B A /Baa1 — low 2 enterprise value1 Dec 31, 2015 Fort Hills* Oil Sands St. John’s Firebag* 99% oil production Edmonton 2015 Actuals MacKay River* Syncrude Denver Mississauga Base Plant & Mine* as at December 31, 2014 refining capacity cash flow from operations3 North Sea Stavanger Aberdeen 2015 Actuals London capital expenditures 2015 Actuals excluding capitalized interest Hibernia Terra Nova* Hebron White Rose Houston Fort McMurray East Coast Sarnia Calgary 2P reserve life index2 Montreal Golden Eagle Buzzard Head office Regional office Upstream facility *operated liquidity Downstream facility cash & cash equivalents ($4.0B) plus available credit facilities as at Dec. 31, 2015 investment grade credit rating Moody’s Corp. (Baa1) Stable DBRS Rating Limited (A Low) Negative Trend Standard and Poors Investment Advisory Services, LLC. (A-) Credit Watch 1, 2, 3 See Slide Notes and Advisories. Does not include COS transaction. Circles are scaled to relative net capacities in boe/d Profitable growth with a significant reserves base Production Low decline long-life reserves base Outlook1 800 mb/d Pre-sanction 35 600 Offshore existing and in flight 400 year Reserve Life Index4 as at December 31, 2014 Oil Sands existing and in flight 4.7 200 U2 U1 2011 2013 U2 0 3 includes Canada’s largest oil sands reserves5 Major Oil Sands Maintenance Turnaround3 2015 2016 Guidance Midpoint & Top Range 2020 Planned 1, 2, 3, 4, 5 See Slide Notes and Advisories. Does not include COS transaction. 37 An industry leader in cash generation Free cash flow (US$/boe)1 Cash flow from operations (US$/boe)1 $140 Brent Oil Price (US$/bbl) Rankings based on 23 Global Peers2 $120 $100 $80 1 1 $60 3 1 2 2 4 3 5 3 6 $40 $20 1 4 1 1 1 11 1 1 5 5 3 2 3 7 $0 1 4 1 12 5 Q4 Q1 5 18 Q3 Q4 -$20 Q1 Q2 Q3 2012 Q4 Q1 Q2 Q3 2013 Q4 Q1 Q2 Q3 2014 4 1, 2 See Slide Notes and Advisories. Q2 2015 Financial resilience Pre-funding major growth projects $11.0B Living within our means $1.45B Balance sheet cash $6.80B CFOPs1 $1.25B Cash and Cash Equivalents ($4.0B) Liquidity Growth Capital2 $2.75B Fort Hills / Hebron Capital $2.60B Sustaining Capital $1.65B Available Credit Facilities ($7.0B)3 Committed Spend ($4.25B) $4.0B Remaining spend on FH and Hebron4 to first oil Dividend 2015 Actuals 5 As at Dec 31, 2015 1, 2, 3, 4 See Slide Notes and Advisories. Suncor value proposition Capital Discipline • Rigorous capital allocation process • Competitive, sustainable, history of growing dividends • Opportunistic share buy backs Operational Excellence • Optimizing the base business • Disciplined cost management • Focus on safety, reliability and sustainability Profitable Growth • Vast portfolio of quality undeveloped reserves • Investing in high return threshold projects • Execution of low capital intensity, high return projects 6 Returning cash to shareholders 29¢ quarterly dividend per share (+4% in Q3 2015) Top quartile in global peer group2 Five year dividend growth (Q4 2010 - Q4 2015) 200% >20% 5-year dividend CAGR1 13 years consecutive dividend increases $5.3B shares repurchased 190% 2011-2015 100% 0% -100% 2011-2015 1.12 10% $250M shares outstanding cancelled authorized July 31 2015 suspended due to COS offer Dividends per share3 0.73 0.43 Repurchases per share3,4 0.50 0.32 2011 7 1.14 1.07 0.94 2011-2015 share repurchase 1.14 1, 2, 3, 4 See Slide Notes and Advisories. 2012 2013 2014 2015 Disciplined capital and operating cost management Suncor Capex & cash flow from operations1 Oil Sands Prices and cash operating costs1 C$ billions C$/bbl 100 Oil Sands Average3 CFOPs1 9.7 Sales Price 9.7 9.4 9.1 75 Capital Expenditures2 6.8 6.3 6.4 6.4 6.5 6.2 50 Cash Operating Costs1 per barrel 39.05 39.05 37.05 37.05 37.00 37.00 25 33.80 33.80 28.20 27.85 0 2011 8 2012 2013 2014 2015 2011 1, 2, 3 See Slide Notes and Advisories. 2012 2013 2014 2015 Financial strength in a challenging economic environment Net debt to CFOPs2 Total debt to capitalization1 strong balance sheet Under 3x Target 20%-30% Target ample liquidity 1.7x 24% 0.9x 28% conservative debt structure — low A /Baa1 investment grade rating 2014 2015 0.9x 1.7x 2014 2015 credit watch / negative trend / stable 4.0 $4.0B $7.0B Debt Maturity Profile4 cash & cash equivalents $billions as at Dec 31, 2015 3.3 7.0 available credit facilities 1.2 as at Dec 31, 20153 1.0 0.4 2015 2018 3 years 9 2.8 1, 2, 3, 4 See Slide Notes and Advisories. 2021 0.3 2024 2026 2028 0.7 0.8 0.4 0.7 2032 0.6 1.0 2035 2037 2039 Oil Sands production up to 600 mb/d before the end of the decade1 Debottlenecks, expansions and growth projects expected to raise total Oil Sands production from 463 mb/d (2015) up to 600mb/d. Firebag • 23 mb/d debottleneck completed in Q4 2015 • Capacity2: 203 mb/d bitumen Base Mine Extraction • Extraction debottleneck complete • Notional3 Capacity2: 325 to 350 mb/d bitumen Syncrude • 12% SU WI • Capacity2: 42 mb/d (SU WI) SCO MacKay River • 8 mb/d debottleneck reached in Q4 2015 • Capacity2: 38 mb/d bitumen Base Upgrading Operations • > 10 mb/d in potential reliability improvements • Capacity2: 350 mb/d SCO • 22% shrinkage factor Logistics Fort Hills • Increased SU WI to 50.8% • Under construction • Capacity2: 91 mb/d (SU WI) PFT bitumen 10 1, 2, 3 See Slide Notes and Advisories. Future growth projects will be integrated with existing logistics infrastructure SCO, diesel and bitumen to market Fort Hills development continuing to track key milestones Illustrative annual cash flow profile for peak production of 91 mb/d1 50.8% Suncor working interest 91mb/d production capacity 96% engineering complete 51% construction complete $6.5B capital cost estimate 21M+ construction hours 11 additional 10% working interest as at November 2015 net to Suncor as at December 31, 2015 as at December 31, 2015 net to Suncor from project sanction to first oil without environmental or regulatory enforcement action 1 See Slide Notes and Advisories. Firebag production exceeding expectations Cost effective debottleneck supported 23 kbpd plant capacity expansion 203mb/d Firebag plant capacity rerate Scope • debottleneck of produced water cooling facilities • rerate of de-oiling and steam generation units <$5k/bbl 3 Years 2.8 debottleneck cost1 current field wide SOR • sub-surface: alignment of well pad development timing with increased nameplate capacity 95% expected plant reliability • surface: facility investment planned near 2020 to maintain production capacity at increasing SORs • reduced field wide SOR acceleration of debottleneck • infill wells continue to outperform Forward sustaining capital requirement Repurpose of Voyageur equipment Firebag debottleneck - Produced water cooling unit 12 1 See Slide Notes and Advisories. Technology innovation & development • Investing ~$200 million per year in R&D1 • Targeting increased production and profitability while reducing environmental footprint Firebag Infill Wells – enabling capital and sustaining cost reductions 4 Years Production and average SOR performance above expectations proven results SOR trend without infill wells 36 20% producing infill wells >10% near term field SOR reduction >10% >50% 2 $/bbl reduction in GHG2 13 3.2 3.15 2.8 SOR trend with infill wells ~187 kbpd proportion of Firebag production capital savings on well pairs 20% Firebag infill wells production 80% Firebag production (excluding infill wells) ~54 kbpd reduction in cash costs2 2010 1, 2 See Slide Notes and Advisories. 2011 2012 2013 2014 2015 Operational excellence metrics Improving environmental, safety and operational performance Environment Reported environmental & regulatory non-compliances Safety Reliability Recordable injury incidents per 200,000 work hours Upgrader reliability, based on 350 kbpd capacity 1.00 95% 0.80 90% 0.60 85% 0.40 80% 0.20 75% 200 150 100 50 0 14 70% 0.00 2011 2013 2015 2011 2013 2015 2011 2013 2015 Long-term resilience in a future low-carbon Oil Sands economy Strong history of reducing Oil Sands GHG intensity1 Provincial climate framework 0.19t/bbl >55% reduction in Oil Sands GHG intensity1 since 1990 100Mt emissions limit Allows for continued production growth enabled by technology improvements to reduce GHG intensity and optimize operations $30/t commencing in 2018 0.08t/bbl Performance standards will be based on top quartile performance. Current estimated2 impact less than $0.50/bbl, increasing over time 1990 Carbon Intensity New technology developments to improve energy efficiency3 NCG CoGens offset higheremission power sources noncondensable gas injection PFT surfactants lower steam use 6 Canada’s largest biofuels plant NsolvTM Fort Hills bitumen GHG emissions comparable to conventional crude SAGD LITE windfarms5 solvents replace steam AHS better vehicle efficiencies DCSG novel steam generation process 15 Bitumen Yield CoGen 2014 Carbon Intensity ~320 mb/d350.0 ~40% increase in Oil 70 Sands SCO production 300.0 60 mb/d ~225 250.0 50 ESEIEH electromagnetic heating replaces steam Industry Collaboration on Environmental Technologies Evok, COSIA Steam Significant decrease in water usage (2008 - 2015)4 80 Renewables Process Water 40 200.0 ~46 ~65% decrease in Mm3/y 150.0 annual water usage 30 100.0 20 ~16 10 50.0 Mm3/y 0 2008 1, 2, 3, 4, 5 See Slide Notes and Advisories. 2009 2010 2011 2012 2013 2014 2015 0.0 Appendix 16 2016 Capital and production guidance1 2016 Capital2 Growth Capital3 Upstream Production4 $ millions Percent boe/d Upstream5 Downstream Corporate 5,250 – 5,600 700 – 800 50 – 100 65% 5% 5% 400,000 – 425,000 30,000 – 35,000 95,000 – 105,000 420,000 – 440,000 Total $6,000 - $6,500 55% 525,000 - 565,000 Upstream Oil Sands Operations Syncrude6 E&P Refinery Thruput 2016 Planned maintenance for Suncor operated assets7 Upstream U1 U2 Terra Nova U1 MacKay River U1 Timing Q1 Q2 Q2 Q3 Q3 Q4 Impact on Quarter ~9 kb/d* ~132 kb/d* ~4 kb/d ~23 bb/d* ~3 kb/d ~3 kb/d* R&M Denver Denver Montreal Sarnia Sarnia * A portion of the SCO volume impact will be supplemented by increasing bitumen sales 17 1, 2, 3, 4, 5, 6, 7 See Slide Notes and Advisories. Timing Q1 Q2 Q2 Q2 Q3 Impact on Quarter ~12 kb/d ~13 kb/d ~8 kb/d ~26 kb/d ~2 kb/d Refining & Marketing – optimizing the value of integration R&M Net Earnings1 Suncor Peers1 High Average Low US$/bbl of capacity 15 2015 prices and crude costs2 C$/bbl Brent 10 103 49 5 72 58 - Oil Sands realization Inland crude cost Montreal crude cost R&M realization 0 2011 2012 2013 2014 2015 YTD Q3 Refinery utilization vs. US average Percent of refining capacity Refinery feedstock Percent of refining capacity % Inland 32% 30% 68% 2011 30% Suncor % Offshore 29% % Suncor Crude 20% 100% US Average3 21% 90% 38% 41% 41% 37% 70% 2012 71% 2013 80% 2014 79% 2015 80% 18 1, 2, 3 See Slide Notes and Advisories. 2010 2011 2012 2013 2014 2015 Market access strategy for inland oil production Suncor has over 600 mb/d of near-term access to globally priced markets1 Upgrader Diesel Current1 Edmonton Montreal Sarnia Denver 19 1 See Slide Notes and Advisories. • Existing pipelines and hubs • 80+ mb/d rail loading and offloading • Suncor Refinery • Marine opportunities for inland oil • Line 9 to Montreal High quality mining, in situ and upgrading oil sands portfolio1 Base Plant Syncrude 350,000 b/d capacity Syncrude operated Suncor working interest 100% 42,000 b/d capacity (SU WI) 1,766 mmbbls 2P reserves Suncor working interest 12% 525 mmbbls 2P reserves (SU WI) Firebag Fort Hills 203,000 b/d capacity Suncor operated Suncor working interest 100% 91,000 b/d capacity (planned, SU WI)2 2,634 mmbbls 2P reserves Suncor working interest 50.8%2 1,253 mmbbls 2P reserves (SU WI)3 MacKay River Future opportunities 38,000 b/d capacity Lewis (SU WI 100%) Suncor working interest 100% Meadow Creek (SU WI 75%) 542 mmbbls 2P reserves 20 1, 2, 3 See Slide Notes and Advisories. Offshore oil projects with ~470 million barrels of 2P reserves1 Terra Nova Hibernia Suncor Energy operated ExxonMobil operated Suncor working interest 37.675% Suncor working interest 19.55%2 48 mmboe 2P reserves (SU WI) 104 mmboe 2P reserves (SU WI)3 White Rose Buzzard Husky Energy operated Nexen Petroleum UK operated Suncor working interest 27.5% Suncor working interest 29.89% 34 mmboe 2P reserves (SU WI) 64.5 kboe/d net capacity 89 mmboe 2P reserves (SU WI) Hebron Golden Eagle ExxonMobil operated Suncor working interest Nexen Petroleum UK operated 21%4 Suncor working interest 26.69% First oil expected in 2017 First oil achieved Q4 2014 31.6 kboe/d planned net capacity4 154 mmboe 2P reserves (SU WI)3 Construction activities are continuing at deepwater site 21 1, 2, 3, 4 See Slide Notes and Advisories. 18.5 kboe/d planned net capacity 41 mmboe 2P reserves (SU WI) Development drilling to be complete in 2016 Canada’s largest refining & marketing business1 Edmonton Refinery Sarnia Refinery 142,000 b/d capacity 85,000 b/d capacity 100% oil sands feedstock ~75% oil sands feedstock Commerce City Refinery Montreal Refinery 98,000 b/d capacity 137,000 b/d capacity ~20% oil sands feedstock Rail offloading capacity of 30-40 mb/d Receiving crude volume from Line 9 as of December 2015 ~30% oil sands feedstock Marketing Other Over 500,000 b/d in product sales • 6 wind farms2 (287 MW) 1484 retail sites with largest urban market share in Canada1 • St. Clair Ethanol plant (400 ML/yr) • Mississauga Lubricants plant (870 ML/yr, 350+ specialty products) • 51% interest in Parachem • Global sulphur and petroleum coke marketing 280 wholesale sites 22 1, 2 See Slide Notes and Advisories. Comparing typical attributes of North American oil plays1 Tight Oil SAGD Mining Offshore Initial Capital Low Medium High High Reinvestment Cycle Short Medium Ultra long Medium Operating Costs Low Medium High Medium Production Light oil Bitumen Bitumen Light oil Reservoir Risk Medium Medium Low High Low High Very High Medium Very high Medium Low High Land acquisition costs Cyclical pad development No longer need on-site upgrading Exploration risk 0% ~35% ~45% ~20% Recovery Factor Decline Rate Other Considerations Suncor Exposure 23 1 See Slide Notes and Advisories. Suncor’s acquisition of Canadian Oil Sands Limited Fort Hills Firebag Syncrude Mackay River Voyageur South Millennium & Steepbank Mine Lewis Syncrude properties Suncor & other JV properties The Offer Suncor’s acquisition of COS was completed on March 21st, 2016. The transaction was valued at ~$6.9 B, of which $2.6 B was assumed debt. Financial 24% net debt to capitalization1 on a pro-forma basis as at February 28th, 2016. Suncor to issue ~136 M shares. Operating Suncor has increased it’s working interest in Syncrude (capacity 350 mb/d SCO) from 12% to 48.74%. 20% increase in 2P reserves to 9.1 billion barrels. Synergies Suncor along with the partners will explore regional synergies and efficiencies with respect to operations, capital investment and technology. 24 1 See Slide Notes and Advisories. Advisories Forward-Looking Statements – This presentation contains certain “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 and “forward-looking information” within the meaning of applicable Canadian securities legislation (collectively, “forward-looking statements”), including statements about Suncor’s growth strategy, expected future production and operating and financial results and expectations with respect to dividends and share re-purchases, that are based on Suncor’s current expectations, estimates, projections and assumptions that were made by Suncor in light of its experience and its perception of historical trends. Some of the forward-looking statements may be identified by words such as “estimates”, “plans”, “goal”, “strategy”, “expects”, “continue”, “may", "will”, “outlook”, and similar expressions. Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Users of this information are cautioned that actual results may differ materially as a result of, among other things, assumptions regarding expected synergies and reduced operating expenditures; volatility of and assumptions regarding oil and gas prices; assumptions regarding timing of commissioning and start-up of capital projects; assumptions contained in or relevant to Suncor’s 2016 Corporate Guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in marketing operations (including credit risks); imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from Suncor’s properties; the ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; assumptions regarding the timely receipt of regulatory and other approvals; the ability to secure adequate product transportation; changes in royalty, tax, environmental and other laws or regulations or the interpretations of such laws or regulations; applicable political and economic conditions; the risk of war, hostilities, civil insurrection, political instability and terrorist threats; assumptions regarding OPEC production quotas; and risks associated with existing and potential future lawsuits and regulatory actions. Although Suncor believes that the expectations represented 25 by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Suncor’s quarterly report for the quarter ended December 31, 2015 and dated February 3, 2016 (the Quarterly Report), Annual Report and its most recently filed Annual Information Form/Form 40-F and other documents it files from time to time with securities regulatory authorities describe the risks, uncertainties, material assumptions and other factors that could influence actual results and such factors are incorporated herein by reference. Copies of these documents are available without charge from Suncor at 150 6th Avenue S.W., Calgary, Alberta T2P 3Y7, by calling 1-800558-9071, or by email request to [email protected] or by referring to the company’s profile on SEDAR at www.sedar.com or EDGAR at www.sec.gov. Except as required by applicable securities laws, Suncor disclaims any intention or obligation to publicly update or revise any forwardlooking statements, whether as a result of new information, future events or otherwise. Suncor’s actual results may differ materially from those expressed or implied by its forward looking statements, so readers are cautioned not to place undue reliance on them. Suncor’s corporate guidance includes a planned production range, planned maintenance, capital expenditures and other information, based on our current expectations, estimates, projections and assumptions (collectively, the “Factors”), including those outlined in our 2016 Corporate Guidance available on www.suncor.com/guidance, which Factors are incorporated herein by reference. Suncor includes forward looking information to assist readers in understanding the company’s future plans and expectations and the use of such information for other purposes may not be appropriate. Non-GAAP Measures – Certain financial measures in this presentation – namely cash flow from operations, free cash flow, and Oil Sands cash operating costs – are not prescribed by GAAP. All non-GAAP measures presented herein do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. Therefore, these non-GAAP measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. All nonGAAP measures are included because management uses the information to analyze business performance, leverage and liquidity and therefore may be considered useful information by investors. Annual cash flow from operations, free cash flow and Oil Sands cash operating costs per barrel for 2012, 2013 and 2014 are defined and reconciled to GAAP measures in Suncor’s management’s discussion and analysis for the year ended December 31, 2014; figures for 2011 are defined and reconciled in Suncor’s management’s discussion and analysis for the year ended December 31, 2013 (except in the case of free cash flow, which equals cash flow from operations less capital and exploration expenditures for 2011); figures for 2015 are reconciled in the Quarterly Report. Reserves— Unless noted otherwise, reserves information presented herein for Suncor is presented as Suncor’s working interest (operating and non-operating) before deduction of royalties, and without including any royalty interests of Suncor, and is at December 31, 2014. For more information on Suncor’s reserves, including definitions of proved and probable reserves, Suncor’s interest, location of the reserves and the product types reasonably expected please see Suncor’s most recent Annual Information Form/Form 40-F dated February 26, 2015 available at www.sedar.com and www.sec.gov. BOE — (Barrels of oil equivalent) Certain natural gas volumes have been converted to barrels of oil on the basis of six thousand cubic feet to one boe. This industry convention is not indicative of relative market values, and thus may be misleading. Slide Notes Slide 2---------------------------------------------------------------(1) Market capitalization + debt - cash and cash equivalents. (2) As at December 31 2014 and assumes that approximately 7.5 billion barrels of oil equivalent (boe) of proved and probable reserves (2P) are produced at a rate of 577.8 mboe/d, Suncor’s average daily production rate in 2015. Reserves are working interest before royalties. See Reserves in the Advisories. (3) Cash Flow from Operations (CFOPs) is a non-GAAP measure. See Non-GAAP Measures in the Advisories. Slide 3---------------------------------------------------------------(1) Pre-sanction includes potential offshore and oil sands projects that are subject to sanction and Board of Directors’ approval. Offshore includes East Coast Canada and UK North Sea. Oil Sands includes Suncor’s 12% share of Syncrude. Production estimates provided may vary materially from actual production in the future. See Forward-Looking Statements in the Advisories. (2) Compound annual growth rates (CAGR) are calculated using combined Offshore and Oil Sands 2015 full year production and planned volumes for 2020. See ForwardLooking Statements in the Advisories. (3) U1 (Upgrader 1) and U2 (Upgrader 2). See 2016 Planned Maintenance for Suncor Operated Assets on Slide 17. Subject to change. Estimated impacts of maintenance have been factored into annual guidance. (4) See note 2 above for Slide 2. (5) Source: Sproule, “2014 Canadian Oil & Gas Reserves Chart” published June 2015. Slide 4---------------------------------------------------------------(1) Cash flow from operations and free cash flow are nonGAAP measures. See Non-GAAP measures in the Advisories section. Cash flow from operations is calculated as cash flow from operating activities excluding changes in non-cash working capital. Free cash flow is calculated as cash flow from operations less capital and exploration expenditures. See Non-GAAP Measures in the Advisories. Both metrics are converted to USD at the average exchange rate for the applicable quarter. Data for peers sources from FACTSET. Data for certain peers has not been based on information prepared in accordance with IFRS, and may not be comparable and should not be considered as a substitute for measures prepared in accordance with IFRS. (2) Global peers in alphabetical order, not necessarily as they appear in the chart: Anadarko Petroleum Corporation, Apache Corporation, British Petroleum Plc, Canadian Oil Sands Ltd., Cenovus Energy Inc., 26 Chesapeake Energy Corporation, Chevron Corporation, Canadian Natural Resources Limited, ConocoPhillips Co., Devon Energy Corporation, Encana Corporation, Enersis S.A., EOG Resources Inc., Exxon Mobil Corporation, Hess Corporation, Husky Energy Inc., Imperial Oil Limited, Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Royal Dutch Shell P.L.C. and Total S.A. Slide 5---------------------------------------------------------------(1) CFOPs is a non-GAAP measure. See Non-GAAP Measures in the Advisories. (2) The figure for growth capital includes capitalized interest and excludes amounts shown in the figure below for Fort Hills and Hebron capital. (3) US dollar facility converted at 1.384 US$ to C$, the exchange rate as at December 31, 2015. (4) Figure represents total post sanction capital for Fort Hills and Hebron less actual spend to date as of December 31, 2015. See Forward-Looking Statements in the Advisories. Slide 7---------------------------------------------------------------(1) Compound annual growth rate (CAGR). (2) Global peers in alphabetical order, not necessarily as they appear in the chart: Anadarko Petroleum Corporation, Apache Corporation, Canadian Oil Sands Ltd., Cenovus Energy Inc., Chesapeake Energy Corporation, Chevron Corporation, Canadian Natural Resources Limited, ConocoPhillips Co., Devon Energy Corporation, Encana Corporation, Enersis S.A., EOG Resources Inc., Exxon Mobil Corporation, Hess Corporation, Husky Energy Inc., Imperial Oil Limited, Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Royal Dutch Shell P.L.C. and Total S.A. (3) Based on the average of shares outstanding in each year for 2011 to 2014 and as at December 31, 2015 in the case of 2015. (4) Figure does not include the $43 million worth of shares repurchased in the twelve months ended December 31, 2015 ($0.03/share repurchased in 2015). Slide 8---------------------------------------------------------------(1) CFOPs and cash operating costs per barrel, which excludes Syncrude, are non-GAAP measures. See NonGAAP Measures in the Advisories. (2) Excludes capitalized interest. (3) Average sales price excludes Syncrude, is before royalties, and is net of transportation costs. Slide 9---------------------------------------------------------------(1) Capitalization is defined as total debt + (book) equity. (2) CFOPs is a non-GAAP measure. See Non-GAAP Measures in the Advisories. (3) US dollar facility converted at 1.384 US$ to C$, the exchange rate as at December 31, 2015. (4) US dollar long-term debt converted at 1.384 US$ to C$, the exchange rate as at December 31, 2015. Slide 10-------------------------------------------------------------(1) Includes base plant operation projects that are subject to sanction and Board of Directors’ approval. See ForwardLooking Statements in the Advisories. (2) Capacity numbers represent stream day volumes. (3) Bitumen capacity of the mine is dependent on ore grade, which is variable. Slide 11-------------------------------------------------------------(1) Annual cash flow profiles are based on representative project economics (development capital, operating and sustaining costs) using consistent assumptions for future oil prices (including adjustments for quality, transportation and marketing costs), tax and royalty rates. Slide 12-------------------------------------------------------------(1) Debottleneck cost is the result of increasing production (strong infill well performance and advanced reservoir management) and the completion of a minor debottleneck project. The debottleneck project involved the repurposing of cooling equipment originally intended for the Voyageur upgrader project. Slide 13-------------------------------------------------------------(1) In 2015, Suncor spent over $200 million to support research and development of technology across the corporation, through both internal and external pathways. (2) The 2015 GHG and cash cost reduction metrics are a result of reduced SOR’s and are applicable to Firebag operations only. continued … Slide Notes (continued) Slide 15 ----------------------------------------------------------------------(1) Figures include both direct and indirect CO2e emissions. No credit is taken for GHG reductions due to cogen export or purchased offsets. See Suncor’s 2015 Report on Sustainability for further details on the methodologies used to calculated GHG emission intensities. (2) Based on internal GHG future pricing model and forward looking production forecasts. Results may vary materially. See Forward-Looking Statements in the Advisories. (3) Natural gas co-generation (CoGens), Non-Condensable Gas injection (NCG), Direct Contact Steam generation (DCSG), Paraffinic Froth Treatment (PFT), warm solvent extraction (N-SolvTM), Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH), Steam-Assisted Gravity Drainage Less Intensive Technology Enhanced (SAGD LITE), Automated Hauling System (AHS), Canadian Oil Sands Innovation Alliance (COSIA). (4) Water usage for 2015 is based on actual numbers to Oct 31, 2015 prorated forward. (5) Includes working interests in six operating wind farms with gross installed capacity of 287 MW. Slide 17----------------------------------------------------------------------(1) Full guidance is available at suncor.com/guidance. See Forward-looking Statements of the Advisories. (2) Capital expenditures exclude capitalized interest of $600 million - $700 million. (3) Balance of capital expenditures represents sustaining capital. For definitions of growth and sustaining capital expenditures, see the Capital Investment Update section of the “Quarterly Report”. (4) At the time of publication, production in Libya continues to be affected by political unrest and therefore guidance is not being provided. Suncor Total Production excludes Libya production. (5) The upstream capital spending outlook includes approximately $100 million of sustaining capital for Suncor’s 12% share of Syncrude. (6) Reflects Suncor’s 12% share of production from Syncrude operations, based on Suncor’s view of Syncrude’s preliminary 2016 operating plan. (7) Subject to change. Estimated impacts have been factored into annual guidance. 27 Slide 18 -----------------------------------------------------------------(1) Net earnings per barrel of capacity. Peers include: Alon, CVR Refining, the US downstream divisions of Chevron and ExxonMobil, HollyFrontier, the downstream divisions of Imperial oil and Husky, Marathon Petroleum, PBF Energy, Phillips 66, Tesoro, United Refining, Valero, and Western Refining. Suncor, CVR Refining and Husky report net earnings on a FIFO inventory valuation basis, while other peers report on a LIFO basis, and therefore Suncor’s net earnings in a given period may not be comparable to those peers. (2) OS realization is the average sales price for Oil Sands (excludes Syncrude), before royalties and net of transportation costs. Inland crude cost is the average crude oil purchase price including transportation costs for Suncor’s Edmonton, Denver and Sarnia refineries. Montreal crude cost is the average crude oil purchase price including transportation costs for Suncor’s Montreal refinery. R&M realization is Suncor’s average refined product sales price. (3) Source: U.S. Energy Information Administration. Slide 19 -----------------------------------------------------------------(1) Based on inland crude oil sold to coastal markets by pipeline and rail or processed at Suncor’s refineries. Slide 20------------------------------------------------------------------(1) Reserves are working interest before royalties. See Reserves in the Advisories. The estimates of reserves for individual properties provided herein may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. Suncor’s 2P Reserves (gross) on a working interest basis for Oil Sands Mining, In Situ and total Canada respectively are 3,543 mmbbls, 3,177 mmbbls, and 7,071 mmboe. Suncor’s 2P Reserves (gross) on a working interest for East Coast Canada, total Canada, and North Sea UK respectively are 340 mmboe, 7071 mmboe and 129 mmboe. (2) Suncor working interest update effective as at November 9, 2015. (3) The 2P reserves number is as at December 31, 2014, and therefore does not reflect the additional reserves associated with Suncor’s purchase of an additional 10% of Fort Hills from Total E&P Canada Ltd. Slide 21------------------------------------------------------------------(1) Reserves are working interest before royalties. See Reserves in the Advisories. The estimates of reserves for individual properties provided herein may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. Suncor’s 2P Reserves (gross) on a working interest basis for Oil Sands Mining, In Situ and total Canada respectively are 3,543 mmbbls, 3,177 mmbbls, and 7,071 mmboe. Suncor’s 2P Reserves (gross) on a working interest for East Coast Canada, total Canada, and North Sea UK respectively are 340 mmboe, 7071 mmboe and 129 mmboe. (2) Weighted average of Suncor’s 20.0% working interest in the Hibernia base project and, effective December 1 2015, the updated Suncor working interest in Hibernia Southern Extension Unit (HSEU) to 19.13%. (3) The 2P reserves number is as at December 31, 2014, and therefore does not reflect the modified Suncor WI. (4) Suncor Hebron working interest update effective as at January 1, 2015. Slide 22 -----------------------------------------------------------------(1) Retail urban market share from The Kent Group Ltd. Wind farm capacities are gross. (2) Includes working interests in six operating wind farms with gross installed capacity of 287 MW. Slide 23 -----------------------------------------------------------------(1) Attributes are generalizations based on Suncor’s analysis of its own projects and industry data. Slide 24---------------------------------------------------------(1) Net debt is defined as total debt less cash and cash equivalents. Capitalization is defined as total debt plus the book value of shareholders’ equity. Pro forma as at February 28th, 2016. Investor Relations Contacts Steve Douglas David Burdziuk Leigh MacComb Samantha Enns Vice President IR Manager IR Analyst IR Associate IR Visit us at the Investor Centre on suncor.com 1-800-558-9071 [email protected]
