the 2015 Q4 Suncor Investor

Transcription

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 info@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 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
invest@suncor.com