Suncor Energy Investor Information Published October 25, 2017 Fort - - PowerPoint PPT Presentation
Suncor Energy Investor Information Published October 25, 2017 Fort Hills haul trucks 2 Canadas leading integrated energy company $86B 35+ years Enterprise value 1 2P Reserve life index 2 September 30, 2017 as at Dec. 31, 2016 668 mboepd 99%
Fort Hills haul trucks
2
1, 2 See Slide Notes and Advisories.
Enterprise value1
September 30, 2017
YTD 2017
Refining capacity
2P Reserve life index2
as at Dec. 31, 2016
Product sales
YTD 2017
Retail sites
In North America
Oda
$0 $2 $4 $6 $8 $10 $12 $14 $49 $55 $60 $65 $70 0.94 1.12 1.14 0.60 0.50 0.73 1.02 1.14 1.16 1.28 2012 2013 2014 2015 2016 2017E 3 400 500 600 700 800 2012 2016 2019
Strong production1 increase from projects in flight
Significant upside FFO3 sensitivity to WTI, based on TTM4 actuals US$49 WTI, 0.76 C$/US$, US$16.39 NYH crack spread
Commitment to dividends with >156% five year growth (2012-2017)
Managing the balance sheet as a strategic asset
CAGR2 per share
(2012-16)
Planned CAGR2 per share (2016-19)
Credit rating
Investment grade
DBRS (A Low) Stable, S&P(A-) stable outlook , Moody’s (Baa1) Stable
low
Liquidity
$2.8B cash and $5.5B in available lines of credit
As at September 30, 2017
Dividend per share5 Buyback per share5,6,7 TTM 1, 2, 3, 4, 5, 6, 7, 8 See Slide Notes and Advisories.
Planned
2017 WTI FFO Break-Even
Sustaining capital + dividend8
(C$ billion) (mbpd)
79% 81% 83% 91% 74% 90% 90% 2012 2013 2014 2015 2016 YTD 2017
Excluding Alberta forest fire impact1
4
1 See Slide Notes and Advisories.
Optimizing the base business
Rigorous capital allocation process
Suncor’s upgrader reliability journey
Multi year journey to reach >90% reliability
Firebag 23 mbpd plant capacity expansion for < $5k/bpd Additional 41.74% Syncrude WI for ~ $55k/bpd Divestiture of Petro-Canada Lubricants Inc. for $1.125B Annual dividend increases for 15 consecutive years Launched $2B share buyback in May 2017
100 200 300 400 500 600 700 800 2015 2016 2017 2018 2019
5
(mbpd) Base Mine Base In situ Fort Hills Syncrude E&P Hebron
Guidance midpoint Planned Planned
2016-2019 planned CAGR3 per share
1, 2, 3,4 See Slide Notes and Advisories.
U2 U1 FB
Planned major maintenance4
$37.05 $37.00 $33.80 $27.85 $26.50 $23.65 $9.92 $8.59 $10.03 $9.67 $8.32 $7.30 $5.20 $5.30 $6.00 $5.10 $5.10 $5.00 2012 2013 2014 2015 2016 YTD 2017
>65% of savings attributed to controllable cost Operational Improved reliability, increased scale, maintenance planning, energy inputs Productivity Workforce reduction, technology application Business process Elimination of low-value added work, streamlined processes, lower fly in fly out Supply chain Sole sourcing, vendor contract concessions
1, 2, 3, 4 See Slide Notes and Advisories.
Pol R Pol E Pol Oi
Oil Sands2 E&P3 R&M4
Consistent reductions in operating costs
C$/bbl
0% 10% 20% 30% 40% 2014 2015 2016 2017E $9.75B 535 mbpd Production1 OS&G1
6
Q3 2017 $21.60 $8.57 $4.50
Company OS&G below 2014 levels while production increases ~30%
$6.8 $6.0 $0 $2 $4 $6 $8 2015 2016 2017 E
Sustaining capital5
7
Dividend FFO2 Illustrative 2017 FFO2,7 2017 Estimated sustaining capital5 + dividends6
1, 2, 3, 4, 5, 6, 7, 8 See Slide Notes and Advisories.
WTI US$3 $48.75 $43.35 $19.70 $14.05 $50.00 $17.50 NYH 3-2-1 US$4
FFO2 consistently exceeds sustaining capital, associated capitalized interest and dividends (C$ billions) 2017 sustaining capital and dividend break-even8
~US$ 40.00 WTI Break-even
2017 Estimated dividends $2.1B6 2017 Estimated sustaining capital $2.7B5
$2.7 $2.3 $1.6 $1.9
Focused on near-term production and dividend, while discretionary capital investments and share buybacks are tailored to the business environment
8
1, 2, 3 See Slide Notes and Advisories.
Capital1 Production growth to 20192 Production growth post 2019 Balance sheet leverage metrics Dividend3 Buybacks3 $40 WTI
USD
$4.0B 10% CAGR per share Defer
debottlenecking and pre-engineering on replication
Upper range Grow with production None $50-$55 WTI
USD
$5.0B Invest in
debottlenecking and pre-engineering on replication
Mid range $1-$2B Annually $65 WTI
USD
$5.5B Advance
debottlenecking and development on replication
Low range Extend buyback program
$0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $0 $20 $40 $60 $80 $100 $120 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E 2018
Reinvestment into base business Grew production >70% Increasing dividend Petro-Canada transaction and a focus on reducing debt Increasing dividend Invest in Hebron & Fort Hills and building cash reserve Increasing dividend & buying back shares Focus on shareholder returns consolidate/integrate growth4 Opportunity to increase dividends & buy back shares4
Inflight growth and
Increasing dividend
Dividends expected to grow in line with production4
9 Forward
(US$/bbl) (C$/share)
1, 2, 3, 4, 5 See Slide Notes and Advisories.
Buyback per share1,2,3,5 Dividend per share1 WTI US$ Actual buybacks/share
as at September 30, 20175
0% 100% 200% 10
1, 2, 3, 4, 5, 6, 7 See Slide Notes and Advisories.
Five year dividend growth relative to global peers1 (Q3 2012 – Q3 2017)
Dividend growth since 2010
Dividend increase YTD 2017
Compared to YTD 2016
Dividend per share
Q3 2017
years
Consecutive annual dividend increases2
2003 to 2017
Dividend CAGR6
Q3 2012 – Q3 2017
Dividend yield7
As at September 30, 2017
5-year total shareholder return
Including reinvested dividends 2012-2016 $79.50 $94.90 $94.20 $97.95 $93.00 $48.75 $43.35
20 40 60 80 100 120
0% 100% 200% 2010 2011 2012 2013 2014 2015 2016
Suncor
WTI US$ Suncor Canadian Peers3 Large Integrateds4 E&Ps5
1, 2 See Slide Notes and Advisories.
<3x Net debt to FFO1 20-30% Total debt to capitalization
DBRS Rating Limited (A Low) Stable Standard and Poor’s Rating Services (A-) Stable Outlook Moody’s Corp (Baa1) Stable
low
1.6x Net debt to FFO1 26% Total debt to capitalization $8.3B Liquidity
Cash & cash equivalents ($2.8B) plus available credit facilities ($5.5B)2
(C$ billion)
$0.5 $4.8 $1.6 $1.4 $2.6 $1.7 2040-2046 2035-2039 2029-2034 2025-2028 2021-2024 2018-2020
11
6% 9% 7% 10% 9% 14%
0% 20% 40% 60% 2012 2013 2014 2015 2016 2017E Cimarex, Concho, Continental, Pioneer, EOG Suncor
Sustainable production growth through the downturn
Year-over-year change, oil sands only for Suncor
12
Capital discipline allowed Suncor to consistently grow production through the crude price cycle Weak oil prices limit the ability for tight oil production to grow Suncor’s production growth exceeded the supermajors in 4 of the 5 recent years Supermajors’ growth limited by their scale and natural production declines
6% 9% 7% 10% 9% 14%
0% 10% 20% 30% 2012 2013 2014 2015 2016 2017E BP, Chevron, ConocoPhillips, Exxon, Shell, Total Suncor
1, 2 See Slide Notes and Advisories.
1
2 2
$11 $13 $15 $6 $6
$- $5 $10 $15 $20 $25 2012 2013 2014 2015 2016 BP, Chevron, ConocoPhillips, Exxon, Shell, Total Suncor
13
Balance sheet strength allows for sustainable dividend, while buyback programs offer flexibility Cash returns to shareholders in line with the supermajors
1 See Slide Notes and Advisories.
$11 $13 $15 $6 $6
$- $4 $8 $12 $16 $20 2012 2013 2014 2015 2016 Cimarex, Concho, Continental, Pioneer, EOG Suncor
Total cash (dividends + buybacks) returned to shareholders
US$/bbl
Continued focus on capital discipline allows sustainable cash returns for shareholders through the crude price cycle Scarce cash returns to shareholders amongst tight oil leaders
1
14
1, 2 See Slide Notes and Advisories.
Illustrative annual cash flow profiles2
Initial capital Decline rate Sustaining costs Operating cost Reservoir risk Recovery factor High Very low Very low Medium Very low Very high Medium Low Low Low Low High High High Medium Very low Medium Medium Low Very high High Medium High Low
50 Years
Firebag In Situ
Fort Hills
Fort McMurray Joslyn
Syncrude
MacKay River In Situ
T C T C
Syncrude
T
Base Mine
U
15
Regional synergy opportunities1
Upgrader feedstock optionality Turnaround planning optimization Unplanned outage impact mitigations Process and technology sharing Sparing, warehousing and supply chain management Regional contracts (lodging, busing, flights, etc.) Lease development optimization
Base mine upgrader and terminal
U
Syncrude upgrader
C
In situ central processing facility
T
Terminal Pipelines Proposed bi-directional pipelines
100% WI Joint ownership
1 See Slide Notes and Advisories.
16
90% Fewer manual valves Reduced
Maintenance & opex
70%
Less piping
Shorter
Project execution cycle
50%
Less construction hours
60%
Smaller footprint Simplified sustaining well pads, at existing assets, designed with increased automation
Engineering hours per well pair Manual valves per well pair Number of modules per well pair
9100 230 3 625 25 0.7
Previous design New lean pad design
15%
Less equipment
Reduced
Maintenance & opex
20%
Less piping
Reduced
Fugitive emissions
20%
Fewer pumps
45%
Smaller footprint Complete redesign of Central Processing Facility (CPF) for green field in situ replication New in situ CPF compared to industry leading designs expected1:
New in situ well pad compared to previous Suncor designs:
Replication phase 1&2 Meadow Creek 235 750 m2 Expected: 50% smaller than Firebag 3&4 45% smaller than industry best built 20% smaller than best announced Best Announced 290 000 m2 Best built 420 000 m2 Firebag equivalency 470 000 m2
1 See Slide Notes and Advisories.
360+
Mbpd production growth plans2 Potential first oil from first phase Phases of 40 mbpd next generation in situ facilities (replication)
~10
Locations for replication Months between phases
2023 5+ 12 to 15
17
1, 2 See Slide Notes and Advisories.
Phases in regulatory process - 2 approved, 1 submitted and an additional 4 to be submitted
7
Regulator approved replication facilities Replication facility application submitted October 3, 2017
Suncor secondee, Doreen Cole, appointed as Managing Director replacing the CEO/President Fire learnings addressed with enhanced winterization processes >$125M/year (gross) expected savings 2018 forward1
Operations optimization Application of best practices
Pending Syncrude Calgary office relocation to Suncor Energy Center to capture lease efficiencies >$30M/year (gross) expected savings 2018 forward1
Lodging and busing service optimizations Turnaround and project execution collaboration Materials & support equipment warehousing/distribution
Working towards two bi-directional pipelines connecting Syncrude and Suncor’s base mine by 2020 ~$200M (gross) expected cost for the <15km distance2
Transfer opportunities include sour synthetic and bitumen, ~3.5 mmbbl/yr and ~1.5 mmbbl/yr respectively Asset optimizations during interruptions
18
1, 2 See Slide Notes and Advisories.
First oil1
Suncor working interest
Suncor working interest nameplate capacity1,2
Suncor capital intensity1,3
Suncor working interest project capital1,4
Construction complete Secondary extraction is the only remaining area in construction
Major project areas operating
Staff hired
Secondary extraction turned over to operations
Mining & primary extraction assets proven
Froth production trials complete
19
Fort Hills separation cells
1, 2, 3, 4 See Slide Notes and Advisories.
Tailings thickeners (~$50M) Energy intensity & opex reduction 6-months pre-stripping (~$120M) Ramp-up acceleration Spare ore sizer (~$50M) Reliability improvement Administration building & operations lodge (~$370M) Attraction and retention of quality workforce 3-train PFT system (~$200M) Reliability improvement Second ore preparation train (~$400M) Reliability improvement Power and steam cogeneration (~$360M) Energy intensity & opex reduction
Post-sanction enhancements with associated capex1 Investments included in pre-sanction design with associated capex1
Based on regional benchmarking, Suncor has invested significant capital to meet or exceed ramp-up and performance targets
1, 2 See Slide Notes and Advisories
20
PFT2 enhancements (~$400M) Process safety & technology development
5 of 6 major project areas transitioned to operations
Early commissioning of mine, primary extraction and utilities plants Froth production test runs began in September Shipment by truck to Suncor’s base plant for further processing Multiple planned commissioning runs prior to first oil No major issues during initial froth runs
Fort Hills froth production
Fort Hills froth loading facilities
21
Accelerating technology development and commercialization by leveraging external expertise and solutions
Evok Innovations - cofounder with $100M of available capital Emerald Technology Ventures - 10 years of investing equity in a cleantech portfolio
LanzaTech - developing a proprietary process to convert CO2 waste gas to renewable fuels Benefuel - testing proprietary technology using low cost feedstock to produce high quality biodiesel
NSolv, Harris Controls, and others - partnerships and investments on novel in situ non-aqueous recovery processes
NSERC - research chairs and other program work at leading Canadian Universities; long-term financial supporter
COSIA - 5 year track record of sharing over $1B in Oil Sands environmental technologies among 10 members CRIN - leading the launch with over 50 companies/institutes, investing in clean technology and economic performance themes
NRG/COSIA Carbon Xprize - Suncor led creation aimed at converting SAGD flue gas GHG emissions into valuable carbon based product; five finalists will compete for a $10M prize in 2018/19
22
Advancing relations with Aboriginal Peoples
$500 million equity partnership with First Nations on East Tank Farm Development1 $445 million spend with Aboriginal businesses in 2016; total spend of almost $3.9 billion since 1999
Leading governance
10 of 11 independent Board members Executive compensation linked to financial,
Strength in diversity
1, 2, 3 See Slide Notes and Advisories
Board diversity: 36% Female, 64% Male CEO Steve Williams is a member of Canada’s 30% Club $6 billion capital and exploration spend $418 million Government royalties & taxes 4,800+ vendors spanning 10 provinces 12,800+ Suncor employees
2016 Economic contribution Resilience through strategy
Stress test carbon strategy against three energy futures scenarios Each scenario points to long-term resilience as a function of cost and carbon competitiveness throughout the value chain
GHG reduction
>60% reduction in Oil Sands GHG intensity since 1990 with a goal to reduce GHG intensity by an additional 30% by 20302 Estimated cost impact of carbon tax legislation on upstream production 2018-27: $0.60/bbl3
23
24
25
Oil Sands operations Syncrude E&P Refinery throughput 420,000 – 450,000 130,000 – 145,000 115,000 – 125,000 425,000 – 445,000 Upstream5 Downstream Corporate 4,735 – 625 – 40 – 4,875 675 50 60% 0% 0% 2017 Capital2
$ millions
Production4
boepd
Growth capital3
percent
1, 2, 3, 4, 5, 6, 7, 8 See Slide Notes and Advisories.
2017 Planned maintenance for Suncor operated assets and Syncrude6,7 Upstream Timing Impact on quarter
MacKay River Q4 ~8 mbpd*
* Third-party extension of Cogen maintenance
680,000 – 720,000 Upstream production
Total
$5,400 – $5,600 50%
2017 Sensitivities8 +1/bbl Brent +$1/bbl NYH 3-2-1 +$0.01 FX +$1/GJ AECO +$1L/H Diff
(US$) (US$) (US$/C$) (C$) (US$) FFO (C$ MM)
205 120 (170) (180) 2 Brent, Sollum Voe WTI, Cushing WCS, Hardisty NY Harbor 3-2-1 crack AECO – C Spot Exchange rate (US$/bbl)
(US$/bbl) (US$/bbl) (US$/bbl) (C$/GJ) (C$/US$)
53 50 38 17.50 2.50 0.77
2017 Business Environment
26
1, 2, 3, 4 See Slide Notes and Advisories.
Other purchases ( ) / divestments ( )
East Tank Farm2
$
Lubricants3
$
Wind Facilities4
$
$100
WTI US$/bbl
$20 $40 $60 $80 $10 $20 $30 $40
Total E&P Canada 10% Fort Hills WI
$0 $0 $2 $4 $6 $8 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
NYH 3-2-1 US$/bbl AECO US$/gj
Conoco Commerce City refinery Petro-Canada Non-core UK offshore Pioneer retail network Canadian Oil Sands 37% Syncrude WI Canadian gas assets Valero Commerce City refinery Colorado, Canadian & Trinidad & Tobago gas assets Petro-Canada Petro-Canada Murphy Oil 5% Syncrude WI
2017E1
Rosebank 30% WI
In situ Mining Upgrading/Refining E&P
Growth,
debottlenecks
extraction
beyond 90%
Cost reduction & synergies
between Firebag phases
bitumen integration, lease development optimization
integration
management across east coast assets
synergies
Margin generation
facilities (Pads/CPF)
generation
extensions
project
27
1 See Slide Notes and Advisories.
28
Future opportunities
Lewis (SU WI 100%) Meadow Creek (SU WI 75%)
MacKay River
38,000 bpd capacity Suncor working interest 100% 528 mmbbls 2P reserves
Base Plant
350,000 bpd capacity Suncor working interest 100% 1,619 mmbbls 2P reserves
Syncrude
Syncrude operated 188,000 bpd coking capacity (SU WI) Suncor working interest 53.74% 1,316 mmbbls 2P reserves (SU WI)
Firebag
203,000 bpd capacity Suncor working interest 100% 2,622 mmbbls 2P reserves
Fort Hills
Suncor operated 98,500 bpd capacity (planned, SU WI) Suncor working interest 50.8% 1,455 mmbbls 2P reserves (SU WI) First oil expected in late 2017
1 See Slide Notes and Advisories.
Cushing Fort McMurray Hardisty Superior Denver Chicago Houston/Texas City San Francisco Los Angeles Vancouver Edmonton Sarnia Cromer Quebec City
Patoka Regina Montreal mbpd
142 98 137
Rail 30+ Rail 40+
mbpd
Suncor refinery capacity Suncor rail loading capacity Gathering lines TMPL
300 mbpd capacity2
Express, Platte and Rocky Mountain
280 mbpd capacity2
TransCanada Keystone
590 mbpd capacity2
Enbridge Mainline
2600 mbpd capacity2
Marine opportunities Enbridge Line 9
300 mbpd capacity2
Flanagan South Pipeline
585 mbpd capacity2 Rail 40+
Pipeline
Current and forecasted gross pipeline capacity2
29 TMEP (Proposed)
+590 mbpd capacity3
Keystone XL (Proposed)
+830 mbpd capacity3
Steele City
Enbridge Line 3 (Proposed)
+370 mbpd capacity3
85
1, 2, 3 See Slide Notes and Advisories.
30
Other
4 wind farms3 (111 MW)
51% interest in Parachem Global sulphur and petroleum coke marketing
Edmonton refinery
142,000 bpd capacity 100% oil sands feedstock1
Sarnia refinery
85,000 bpd capacity ~75% oil sands feedstock1
Commerce City refinery
98,000 bpd capacity ~20% oil sands feedstock1
Marketing
Over 500,000 bpd in product sales 1537 North American retail sites (~55%
in Canada2 275+ wholesale sites
1, 2, 3 See Slide Notes and Advisories.
Montreal refinery
137,000 bpd capacity ~30% oil sands feedstock1
22.35 27.95 24.25 23.80
Benchmark crack Benchmark crack Crude differential Product mix & location differential Yield/ feedstock/
Realized GM (LIFO) FIFO impact Realized GM (FIFO)
53 60 100 $0 $20 $40 $60 $80 $100 $120 OS realization Feedstock cost R&M realization $0 $5 $10 $15 2012 2013 2014 2015 2016
Price realizations & refinery crude costs3
31
R&M annual net earnings1
US$/bbl of capacity
1, 2, 3, 4, 5, 6, 7 See Slide Notes and Advisories.
High Average Low
peers1 Suncor
Refinery utilization vs. US average
Percent of refining capacity
Suncor US Average2
Realized GM6/bbl vs. NYH 3-2-1 benchmark
All Suncor refineries Q3 2017 All Suncor refineries YTD Q3 2017, 38% equity feedstock4
Brent C$ 67.405
80% 90% 100% 2012 2013 2014 2015 2016 YTD 2017
7
NYH 3-2-1 US$ NYH 3-2-1 C$
32
Golden Eagle
Nexen Petroleum UK operated Suncor working interest 26.69% 23 mmboe 2P reserves (SU WI)
Hebron
ExxonMobil operated Suncor working interest 21% First oil expected in late 2017 31.6 mboepd planned net capacity 151 mmboe 2P reserves (SU WI) Drilling of first production well began in Q3
Terra Nova
Suncor Energy operated Suncor working interest 37.675% 43 mmboe 2P reserves (SU WI)
Hibernia
ExxonMobil operated Suncor working interest 20.0%2 88 mmboe 2P reserves (SU WI)
White Rose
Husky Energy operated Suncor working interest 27.5%3 28 mmboe 2P reserves (SU WI)
Buzzard
Nexen Petroleum UK operated Suncor working interest 29.89% 68 mmboe 2P reserves (SU WI)
1, 2, 3 See Slide Notes and Advisories.
Future opportunities: Oda-Norway (30% SU WI) and Rosebank-UK (30% SU WI)
$0 $10 $20 $30 $40
Owner in all regional assets
Lowest opex among oil producing peers
YTD 2017 operating cost3
2016 East Coast oil production2
mboe/d 10 20 30 40 50 60 Suncor Energy ExxonMobil Chevron Husky Energy Statoil Murphy Oil
2016 UK oil producer operating costs2
US$/boe 33
1, 2, 3,4 See Slide Notes and Advisories.
34
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: future production, compound annual growth rate, funds from
break even and operating and financial results; expectations for dividends, share re-purchases, production growth and balance sheet position; Suncor’s emissions intensity reduction goal; estimated impact of carbon taxes; anticipated proceeds of divestment; Suncor’s strategy, business plans and growth and margin opportunities; expectations, targets and potential
to growth projects, including Fort Hills, Meadow Creek East, Hebron and debottlenecks, including planned capacity, cost and timing; expectations regarding the East Tank Farm Development; anticipated benefits of the next generation SAGD
technologies under development; planned maintenance; expectations for renewable energy development; planned technology investment; capital and production guidance; business environment assumptions; and potential future pipelines 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
identified by words such as “planned”, “estimated”, “target”, “goal”, “illustrative”, “strategy”, “expected”, “focused”, “opportunities”, “may”, “will”, “outlook”, “anticipated”, “potential”, “guidance”, “predicts”, “aims”, “proposed” and similar
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: commodity prices; timing of commissioning and start-up, cost, characteristics, and capacity of capital projects; assumptions contained in or relevant to Suncor’s 2017 Corporate Guidance; fluctuations in foreign exchange and interest rates; product supply and demand; market competition; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; 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; expected synergies and the ability to sustain reductions in costs; the ability to access external sources
pipeline construction; the timely receipt of regulatory and other approvals; the timing of sanction decisions and Board of Directors’ approval; the availability and cost of labour and services; the satisfaction by third parties of their obligations to Suncor; changes in royalty, tax, environmental and other laws or regulations or the interpretations of such laws or regulations; applicable political and economic conditions; risks associated with existing and potential future lawsuits and regulatory actions; the timing and completion of divestments; improvements in performance of assets; and the timing and impact of technology development. Although Suncor believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Suncor’s Management Discussion and Analysis for the quarter ended September 30, 2017 and dated October 25, 2017 (the MD&A), 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 3E3, by calling 1-800-558-9071, or by email request to invest@suncor.com 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 forward- looking 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 2017 Corporate Guidance available on www.suncor.com/guidance, which Factors are incorporated herein by reference. Suncor includes forward- looking statements 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 funds from operations, operating earnings, Oil Sands operations cash operating costs, cash
refining operating expense, discretionary free cash flow, free cash flow and last in, first out (LIFO) – are not prescribed by
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 non-GAAP 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 funds from operations (previously referred to as cash flow from operations) for 2015 and 2016 are defined and reconciled to GAAP measures in Suncor’s management’s discussion and analysis for the year ended December 31, 2016 (2016 MD&A); annual Oil Sands operations cash operating costs (previously referred to as Oil Sands cash operating costs) for 2011, 2012 and 2013 are defined and reconciled to GAAP measures in Suncor’s management’s discussion and analysis for the year ended December 31, 2013 (2013 MD&A), and for 2014, 2015 and 2016 are defined and reconciled in the 2016 MD&A; funds from operations and Oil Sands operations cash operating costs for the nine months ended September 30, 2017 are defined and reconciled to GAAP measures in the MD&A; refining
2012 to 2016 is reconciled to GAAP measures in the Operating Metrics Reconciliation in the Supplemental Financial and Operating Information in Suncor’s annual report for the year ended December 31, 2016, and for the three and nine months ended September 30, 2017 is reconciled to GAAP measures in the Quarterly Operating Metrics reconciliation in Suncor’s report to shareholders for the third quarter of 2017; discretionary free cash flow for 2015 and 2016 is defined and reconciled in the 2016 MD&A; operating earnings for the nine months ended September 30, 2017 are defined and reconciled to GAAP measures in the MD&A; and the estimated impact of the LIFO method for the third quarter of 2017 is defined and reconciled in the MD&A. 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, 2016. 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 March 1, 2017 available at www.sedar.com and www.sec.gov. Reserves data is based upon evaluations conducted by independent qualified reserves evaluators as defined in NI 51-101. 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.
35
Slide 2------------------------------------------------------------- (1) Market capitalization + debt - cash and cash equivalents. (2) As at December 31, 2016 and assumes that approximately 7.96 billion barrels of oil equivalent (boe) of proved and probable reserves (2P) are produced at a rate of 622.8 mboe/d, Suncor’s average daily production rate in 2016. Reserves are working interest before royalties. See Reserves in the Advisories. Slide 3-------------------------------------------------------------- (1) Production excludes North America onshore, Libya and Syria for all years including 2019 Planned and includes pre-sanction
Directors’ approval. Production estimate 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 2012 full year production and 2016 full year production and planned volumes for 2019. Actual production may vary materially. See Forward-Looking Statements in the Advisories. (3) Funds from operations (FFO) is a non-GAAP financial measure. See Non-GAAP Measures in the Advisories. Funds from
activities excluding changes in non-cash working capital. (4) Refers to Trailing Twelve Month average value as at September 30, 2017. (5) Based on the average number of shares outstanding in each year for 2012 to 2015 and as at December 31, 2016 in the case
in the case of 2017. 2017 dividend amount assumes $0.32/share dividend for each quarter. All dividends are at the discretion of Suncor’s Board of Directors. See Forward-Looking Statements in the Advisories. (6) 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). (7) 2017 buyback per share assumes $1 billion of annual spend under the normal course issuer bid (NCIB). Under its NCIB, Suncor may purchase up to $2 billion worth of its common shares beginning May 2, 2017 and ending May 1, 2018. The NCIB is opportunistic. The actual number of shares that will be purchased under the NCIB and the timing of any such purchases will be determined by Suncor and will depend on market conditions, cash flow and other factors, and could differ materially from this assumption. See Forward-Looking Statements in the Advisories. (8) Refers to estimated average WTI crude oil price for 2017 in US dollars required for funds from operations for 2017 to equal anticipated 2017 sustaining capital expenditures inclusive of associated capitalized interest and dividends. Assumes production, sustaining capital and business environment at the midpoint of 2017 guidance released on October 25, 2017 and a $0.32/share dividend for each quarter in 2017. All dividends are at the discretion of Suncor’s Board of Directors. Actual results may differ materially. See Forward-Looking Statements in the Advisories. Slide 4--------------------------------------------------------------- (1) Excludes the impact of operations being shut-in due to forest fires in the Fort McMurray region. Slide 5--------------------------------------------------------------- (1) E&P includes East Coast Canada (ex-Hebron), North Sea and includes pre-sanction offshore projects that are subject to sanction and Board of Directors’ approval. Production excludes North America onshore, Libya, and Syria for all years. Syncrude includes the 36.74% interest in Syncrude acquired on February 5, 2016 and the 5% interest of Syncrude acquired on June 23,
production in the future. See Forward-Looking Statements in the Advisories. (2) Bitumen production from Oil Sands Base operations is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor’s own
process are approximately 79% of bitumen feedstock input. All of the bitumen produced at Syncrude is upgraded to sweet SCO. (3) Compound annual growth rates (CAGR) are calculated using combined Offshore and Oil Sands 2016 full year production, mid- point of combined offshore and Oil Sands production guidance for full year 2017, and planned volumes for 2018 - 2019. Planned CAGR may vary materially from actual CAGR in the
(4) U1 (Upgrader 1) and U2 (Upgrader 2) and FB (Firebag). See 2017 Planned Maintenance for Suncor Operated Assets and Syncrude on Slide 25. Subject to change. Estimated impacts of maintenance have been factored into annual guidance. Slide 6-------------------------------------------------------------- (1) 2017E Represents expected 2017 production based on the mid- point of guidance and expected 2017 operating, selling and general (OS&G) expenses. Actual production and OS&G expenses may differ materially. See Forward-Looking Statements in the Advisories. (2) Refers to Oil Sands operations cash operating costs per barrel, which excludes Syncrude and which is a non-GAAP measure. See Non-GAAP Measures in the Advisories. (3) Refers to cash operating costs for United Kingdom and East Coast Canada, which is a non-GAAP measure and is calculated by taking the sum of OS&G expenses (a GAAP measure) for the United Kingdom and East Coast Canada, subtracting non- production costs for United Kingdom and East Coast Canada and dividing the resulting figure by the sum of the sales volumes for United Kingdom and East Coast Canada, all as indicated for the applicable year and for the three and nine months ended September 30, 2017 in the Exploration and Production Netbacks section of the Operating Metrics Reconciliation in the Supplemental Financial and Operating Information in Suncor’s Q3 2017 Quarterly Report to Shareholders and Annual Report for the year ended December 31, 2016. See Non-GAAP Measures in the Advisories. (4) Refers to refining operating expense, which is a non-GAAP
GAAP Measures in the Advisories. Slide 7-------------------------------------------------------------- (1) Discretionary free cash flow is calculated by taking funds from
associated capitalized interest, and dividends. Discretionary free cash flow is a non-GAAP measure. See Non-GAAP Measures in the Advisories. (2) Funds from operations (FFO) is defined as cash flow provided by
(3) WTI pricing for 2015-2016 are actual averages for each respective year. The WTI pricing for 2017 is based on 2017 guidance. (4) The NYH 3-2-1 benchmark numbers for 2015-2016 are actual averages for each respective year. The 2017 numbers are based on Suncor’s 2017 guidance numbers. (5) Represents anticipated sustaining capital expenditures (inclusive
current business plans. Actual capital expenditures and associated capitalized interest along with the company’s business plans may differ materially from those anticipated and are subject to Board of Directors’ approval. For the definition of sustaining capital expenditures see the Capital Investment Update section of the MD&A. See Forward-Looking Statements in the Advisories. (6) Assumes 2017 quarterly dividend of $0.32/share. All dividends are at the discretion of Suncor’s Board of Directors. See Forward-Looking Statements in the Advisories. (7) Illustrative FFO is not intended to be a forecast of Suncor’s FFO. It is indicative of FFO based on the midpoint of 2017 guidance released on October 25, 2017. Also based on continued industry growth fundamentals. Actual results may differ materially. See Forward-Looking Statements in the Advisories. (8) Refers to estimated average WTI crude oil price for 2017 in US dollars required for funds from operations for 2017 to equal anticipated 2017 sustaining capital expenditures inclusive of associated capitalized interest and dividends. Assumes production, sustaining capital and business environment at the midpoint of 2017 guidance released on October 25, 2017 and a $0.32/share dividend for each quarter in 2017. All dividends are at the discretion of Suncor’s Board of Directors. Actual results may differ materially. See Forward-Looking Statements in the Advisories. continued …
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Slide 8-------------------------------------------------------------- (1) Based on current business plans, which are subject to change. See Forward-Looking Statements in the Advisories. (2) Based on 2016 full year production and planned volumes for
Looking Statements in the Advisories. (3) Dividends and future normal course issuer bids are at the discretion of Suncor’s Board of Directors. See Forward-Looking Statements in the Advisories. Slide 9------------------------------------------------------------- (1) Based on the average of shares outstanding in each year for 2002 to 2015 and as at December 31, 2016 in the case of 2016 and closing number of shares as at September 30, 2017 in the case of 2017. 2017 dividend amount assumes $0.32/share dividend for each quarter. All dividends are at the discretion of Suncor’s Board of Directors. See Forward-Looking Statements in the Advisories. (2) 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). (3) 2017 buyback per share assumes $1 billion of annual spend under the normal course issuer bid (NCIB). Under its NCIB, Suncor may purchase up to $2 billion worth of its common shares beginning May 2, 2017 and ending May 1, 2018. The NCIB is opportunistic. The actual number of shares that will be purchased under the NCIB and the timing of any such purchases will be determined by Suncor and will depend on market conditions, cash flow and other factors, and could differ materially from this assumption. See Forward-Looking Statements in the Advisories. (4) Based on the company’s current business plans, which are subject to change. All dividends are at the discretion of Suncor’s Board of Directors. See Forward-Looking Statements in the Advisories. (5) Current amount of NCIB spent YTD is $578M. Slide 10------------------------------------------------------------ (1) Global peers in alphabetical order, not necessarily as they appear in the chart: Anadarko Petroleum Corporation, Apache Corporation, BP plc, Cenovus Energy Inc., Chesapeake Energy Corporation, Chevron Corporation, Canadian Natural Resources Limited, ConocoPhillips Co., Devon Energy Corporation, Encana Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Husky Energy Inc., Imperial Oil Limited, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation, Royal Dutch Shell plc, and Total S.A. (2) Assumes an expected 2017 quarterly dividend of $0.32/share. All dividends are at the discretion of Suncor’s Board of Directors. See Forward-Looking Statements in the Advisories. (3) Canadian peers in alphabetical order: Canadian Natural Resources Ltd., Cenovus Energy Inc., Husky Energy Inc., Imperial Oil Limited. (4) Large integrated peers in alphabetical order: BP plc., Chevron Corporation, ExxonMobil Corporation, Royal Dutch Shell plc., Total S.A. (5) E&P peer group in alphabetical order: Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, ConocoPhillips Co., Devon Energy Corporation, Encana Corporation, EOG Resources Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Occidental Petroleum Corporation. (6) Compound annual growth rate (CAGR) is calculated using Q3 2012 dividend and Q3 2017 dividend. (7) Dividend yield is calculated as annual dividend per share divided by Suncor closing share price on September 30, 2017. Slide 11--------------------------------------------------------------- (1) Funds from operations is a non-GAAP financial measure. See Non-GAAP Measures in the Advisories. Funds from operations is calculated as cash flow provided by operating activities excluding changes in non-cash working capital. (2) All figures are in billions of CAD. U.S dollar facilities converted at a rate of $1.2480, the Bank of Canada Day Daily Rate as at September 29, 2017. Slide 12------------------------------------------------------------- (1) Peer group chosen to consist of liquids-weighted and basin- concentrated U.S. E&P companies. (2) Represents expected 2017 production growth. Actual production growth may vary materially. See Forward-Looking Statements in the Advisories. Slide 13------------------------------------------------------------- (1) Peer group chosen to consist of liquids-weighted and basin- concentrated U.S. E&P companies. Slide 14------------------------------------------------------------- (1) Attributes are generalizations based on Suncor’s analysis of its
(2) 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. Actual cash flows may differ materially. See Forward-Looking Statements in the Advisories. Slide 15------------------------------------------------------------- (1) Represents possible future opportunities currently being
be pursued. See Forward-Looking Statements in the Advisories. Slide 16------------------------------------------------------------- (1) Expected benefits based on design specifications. Actual performance may differ materially. See Forward Looking Statements in the Advisories. Slide 17------------------------------------------------------------- (1) Based on current plans which are subject to change. See Forward-looking Statements in the Advisories. (2) Gross project volume including Nexen’s interest Slide 18------------------------------------------------------------- (1) Represents current estimates of potential benefits over life of
looking Statements in the Advisories. (2) Represents current estimate of cost to build pipeline. Actual results may differ materially. See Forward-looking Statements in the Advisories. Slide 19------------------------------------------------------------- (1) First oil, capital intensity, project capital and nameplate capacity based on current expectations. See Forward-Looking Statements in the Advisories. (2) Nameplate production capacity, actual results may vary. See Forward-looking Statements in the Advisories. (3) Suncor’s capital intensity includes the impact of acquiring an additional 10% working interest in 2015 and may differ from that
(4) The capital ranges exclude the impact of foreign exchange due to the weakness in the Canadian dollar. F/X is dealt with at the individual owner level and not at the project level due to individual hedging programs. Suncor did not hedge the US Canadian dollar exchange rate which has resulted in approximately $180M net impact to Suncor. Slide 20------------------------------------------------------------- (1) Represents current estimates of potential improvements. Actual results may differ materially. See Forward-looking Statements in the Advisories. (2) PFT refers to Paraphinic Froth Treatment Slide 23 ------------------------------------------------------------- (1) Refers to estimated proceeds from the sale of a combined 49% interest in the East Tank Farm development to the Fort McKay First Nation and the Mikisew Cree First Nation. The transactions are subject to closing conditions, including financing. See Forward-looking Statements in the Advisories. (2) See Suncor’s 2017 Report on Sustainability for further details on the methodologies used to calculate GHG emission intensities. (3) Actual cost impact may differ materially. See Forward-looking Statements in the Advisories. continued …
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Slide 25------------------------------------------------------------ (1) Full guidance is available at suncor.com/guidance. See Forward- Looking Statements in the Advisories. (2) Capital expenditures exclude capitalized interest of approximately $750 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 MD&A. (4) At the time of publication, production in Libya continues to be affected by political unrest and therefore no forward looking production for Libya is factored into the Exploration and Production and Suncor Total Production guidance. Production ranges for Oil Sands operations, Syncrude and Exploration and Production (E&P) are not intended to add to equal Suncor total production. (5) The upstream capital spending outlook includes approximately $335 million of sustaining capital for Suncor’s 53.74% share of Syncrude. (6) Subject to change. Estimated impacts have been factored into annual guidance. (7) Syncrude is operated by Syncrude Canada Limited. (8) Baseline FFO has been derived from midpoint of 2017 guidance and the associated business environment. Sensitivities are based
the rest constant. Funds from operations is a non-GAAP financial
from operations is calculated as cash flow provided by operating activities excluding changes in non-cash working capital. Slide 26------------------------------------------------------------- (1) Full year pricing assumptions taken from Suncor’s 2017
(2) Refers to estimated proceeds from the sale of a combined 49% interest in the East Tank Farm development to the Fort McKay First Nation and the Mikisew Cree First Nation. The transactions are subject to closing conditions, including financing. See Forward-looking Statements in the Advisories. (3) Refers to sale of Suncor lubricants business to a subsidiary of HollyFrontier Corporation, which closed on February 1, 2017. (4) As at September 30, 2016, Suncor reclassified certain assets and liabilities related to its renewable energy business as assets held for sale. The sale of Suncor’s interest in the Cedar Point wind facility closed on January 24, 2017 and sale of Suncor’s interest in the Ripley wind facility closed on July 10, 2017. Slide 27------------------------------------------------------------ (1) Represents potential opportunities being evaluated. Actual results may differ materially. See Forward-Looking Statements in the Advisories. Slide 28------------------------------------------------------------ (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
are 7,855 mmboe as at Dec. 31, 2016. Slide 29------------------------------------------------------------ (1) Based on inland crude oil sold to markets based on pipeline and rail logistics or processed at Suncor’s refineries. (2) Approximate total pipeline capacities based on publically sourced information available at www.capp.ca and www.enbridge.com (3) Proposed future pipeline. There can be no assurance this pipeline will be built with the capacity indicated or at all. See Forward-Looking Statements in the Advisories. Slide 30----------------------------------------------------------- (1) Percentages indicate processing capabilities (2) Based on Kent survey results for year-end 2016. (3) Wind farm capacities are gross. Includes working interests in five operating wind farms with gross installed capacity of 111
assets and liabilities related to its renewable energy business as assets held for sale. The sale of Suncor’s interest in the Cedar Point wind facility closed on January 24, 2017. The sale of Suncor’s interest in the Ripley wind facility closed on July 10,
Slide 31------------------------------------------------------------ (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 Last in, first out (LIFO) basis, and therefore Suncor’s net earnings in a given period may not be comparable to those peers. Net earnings converted to USD at the average exchange rate for the applicable year. (2) Source: US Energy Information Administration (3) OS realization is the average sales price for Oil Sands (includes Syncrude), before royalties and net of transportation costs. Feedstock cost is the average crude oil purchase price including transportation costs for Suncor’s Edmonton, Denver, Sarnia and Montreal refineries. R&M realization price represents revenue for all products across all channels for full year 2016. (4) Equity feedstock refers to refinery feedstock derived from Suncor’s upstream production. (5) Brent averaged $51.90 USD for the period ended September 30, 2017 and was converted at $1.30 USD/CAD, the average exchange rate for the period. (6) Gross Margins (GM) per barrel is defined as difference between the total value of petroleum products produced at a refinery less the cost of the feedstock, divided by total throughput. (7) Last in first out (LIFO) refers to the non-GAAP method of inventory accounting, while Suncor reports on a first in first out (FIFO) basis consistent with IFRS accounting policy. See Non- GAAP Measures in the Advisories. Slide 32----------------------------------------------------------- (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
North Sea UK and Norway North Sea, respectively are 7,855 mmboe, 91 mmboe and 11 mmboe as at Dec. 31, 2016. (2) Suncor’s 20.0% working interest is for the Hibernia base project. Effective May 1, 2017, Suncor’s working interest in Hibernia Southern Extension Unit (HSEU) increased by 0.058% to 19.19%. (3) Suncor’s 27.5% working interest is for the White Rose base
lands is 26.125%. Slide 33----------------------------------------------------------- (1) Funds from operations (FFO) and operating earnings are non- GAAP financial measures. See Non-GAAP Measures in the Advisories. (2) Data was sourced from the Upstream Data ToolTM, a product of Wood Mackenzie. Cash operating costs as calculated by Suncor may not be comparable to similar measures presented by other
(3) Refers to cash operating costs, which is a non-GAAP measure and is calculated by taking operating, selling and general expenses (a GAAP measure), subtracting non-production costs and dividing the resulting figure by the sales volumes for each region, all as indicated for the nine months ended September 30, 2017 in the Exploration and Production Netbacks section of the Operating Metrics Reconciliation in the Supplemental Financial and Operating Information in Suncor’s Q3 2017 Quarterly Report to Shareholders. See Non-GAAP Measures in the Advisories. (4) Netbacks are non-GAAP measures that are used by management to measure asset profitability by location on a sales barrel basis and are derived from net earnings after adjusting for items not directly attributable to the costs associated with production and delivery. Netbacks are reconciled to GAAP measures in the Operating Metrics Reconciliation section of the Q3 2017 Quarterly Report to Shareholders. See Non-GAAP Measures in the Advisories.
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