Barclays CEO Energy-Power Conference
Rich Kruger | September 13, 2013
—
Cautionary statement
This presentation contains forward-looking information on future production, project start-ups and future capital spending. Actual results could differ materially due to changes in project schedules, operating performance, demand for oil and gas, commercial negotiations or other technical and economic factors.
Oil-equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB conversion ratio of 6,000 cubic feet to one barrel is based on an energy-equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.
Proved reserves are calculated under United States Securities and Exchange Commission (SEC) requirements, as shown in Form 10-K dated December 31, 2012.
Pursuant to National Instrument 51-101 disclosure guidelines, and using Canadian Oil and Gas Evaluation Handbook definitions, Imperial’s non-proved resources are classified as a “contingent resource.” Such resources are a best estimate of the company’s net interest after royalties at year-end 2012, as determined by Imperial’s internal qualified reserves evaluator. Contingent resources are considered to be potentially recoverable from known accumulations, using established technology or technology under development, but are currently not considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be economically viable or technically feasible to produce any portion of the resource.
The term “project” as used in these materials does not necessarily have the same meaning as under Securities and Exchange Commission (“SEC”) Rule 13q-1 relating to government payment reporting. For example, a single project for purposes of the rule may encompass numerous properties, agreements, investments, developments, phases, work efforts, activities and components, each of which we may also informally describe as a “project”.
Financials in Canadian dollars.
2
Imperial Oil’s business model 3
Deliver superior, long-term shareholder value
1.Long-life, advantaged assets
2.Value chain integration and synergies
3.Disciplined investment, cost management
4.High-impact technologies and innovation
5.Operational excellence, responsible growth
ExxonMobil relationship
4
Chemical
Upstream
Downstream Integration & synergies
Delivering value and competitive advantage across the business chain World-class producing assets
Largest petroleum refiner in Canada
Leading polyethylene market share
5
0
10
20
30
IMO
HSE
CVE
CNRL
SU
Source: Bloomberg, company publications
ROCE 5-year average
%
0
5
10
15
IMO
HSE
SU
CNRL
CVE
Shareholder distributions 2003-2012
$ billions
Dividends Share reductions
Industry-leading return on capital employed
Unmatched shareholder distributions
Strong competitive performance
Industry-leading upstream profitability and record downstream earnings
6
0
5
10
15
20
25
IMO
Competitors
0
3
6
9
12
15
IMO
Competitors
Source: Barclays Research; Competitors is a volume-weighted average and includes CVE, HSE, SU
2012 upstream profitability
$/bbl 2012 downstream profitability $/bbl
7
Long-life, high-quality proved reserves
3.6 billion oil-equivalent barrels, concentrated in world-class assets
0
1
2
3
4
Syncrude
Cold Lake
Kearl
Other YE 2012 proved reserves billion oeb*
* after royalties
Cold Lake
Kearl
Syncrude
8
Executing plans to achieve profitable growth
Investing about $40 billion this decade focused on upstream projects Average capex per year* $ billions
0
1
2
3
4
5
2000-2009
2010-2019
* Upstream, Downstream, Chemical & Corporate
2010
2013
2016
0
200
400
600
New opportunities
Oil sands—mining
Oil sands—in-situ
Conventional
9
* before royalties
Production volumes to double by about 2020
Nearly 200 kbd of additional liquids in funded projects
Production outlook*
kboed
Existing Under construction
To be funded
Starting up
~2020
0
10
20
30
40
2012
2014
2016
2018
2020
2022
Financial strength to support growth plans
Strong balance sheet maintained under a wide range of scenarios 10
S&P AAA rating
Resiliency to crude prices
Flexibility for new opportunities
* Projected at May 31, 2013, includes Celtic acquisition
$55/bbl WTI
$95/bbl WTI
Debt to capital*
%
Cold Lake: a world-class in-situ operation 11 Ownership: 100% Imperial Oil Commercial start-up: 1985 Current production: 150+ kbd gross Active wells: ~ 4,500 Cumulative production: 1.2 billion bbls Proved reserves: 1.1 billion bbls* Non-proved resource: 2.9 billion bbls*
* after royalties
Consistently delivering nameplate capacity at low unit costs
Industry-leading operating performance
12
Reliability 3-year average1
% of capacity 2010-2012
1 Peters & Co. Limited, geoSCOUT
2 FirstEnergy Capital Corp., FirstFacts May 21, 2013; figures include cash G&A and stock-based compensation expense per boe * Industry averages are volume weighted
0
20
40
60
80
100
IMO
Cold Lake
Industry
average2012 in-situ cash operating costs2 $/bbl
0
5
10
15
20
IMO
Cold Lake
Industry
average
0
20
40
60
Significantly increasing resource recovery
Leveraging high-impact technologies and operational best practices
13
Cold Lake demonstrated recovery
%
1970’s 1980’s
1990’s
2000’s
2010+
Megarow steaming
3D seismic analysis
Commercialization
of cyclic steam
stimulation
Liquid addition to steam
Steamflood
Limited entry perforations
Infill recovery processes Thermal Pilots First horizontal well
Expansion via “design one, build multiple” approach
Over 1.2 billion barrels produced, continued growth planned Cold Lake production* kbd
14
0
50
100
150
200
1980
1990
2000
Maskwa
Mahihkan
Nabiye
Mahkeses
Pilots
2012 2015
* before royalties
Cold Lake Nabiye project 56% complete
15
Funded in 2012 for $2 billion, 40 kbd additional production
“Design one, build multiple” replicates Mahkeses
On schedule and on budget for late 2014 start-up
15
Kearl: a next generation mining development
16
Ownership: 71% Imperial Oil
29% ExxonMobil
Commercial start-up: 2013
Gross production: 110 kbd (initial)*
345 kbd (ultimate)*
Recoverable resource: 4.6 billion bbls*
* Gross, before royalties
17 Kearl’s competitive advantages
Proprietary froth treatment
Competitive cost structure
High-quality resource
Environmental performance
Adding value and establishing new performance standards
18 Initial development update Bitumen production
kbd, gross
0
10
20
30
40
50
2Q13
July
August
Current rates greater than 80 kbd
First sales occurred in 3Q
?Crude runs at Joliet in August, Sarnia in September
?4Q deliveries to 3rd parties
110 kbd expected in late 2013
?Addressing equipment issues
Production ramp-up continues, all three trains operational
Increasing Mining Efficiency 9.5
10.0
10.5
11.0
11.5
12.0
7
8
9
10
11
12
Total volume to bitumen in place ratio Top-tier resource quality
Increasing
Processing
Efficiency A definitive, long-term unit cost advantage
Athabasca undeveloped mining resources
ore grade, % bitumen
19 Kearl
Source: development plan applications
Onsite upgrader
“Naphthenic”
Froth Treatment
Refinery Refinery
“Paraffinic” Froth Treatment
Asphaltenes
Bitumen
Sediment and water
Bitumen
Sediment and water
20 Producing pipeline-quality crude without an on-site upgrader
Existing mines
Kearl
Synthetic crude
Proprietary froth treatment
Dilbit
Diluent
21
0
200
400
600Wells-to-wheels GHG Emissions kgCO2/bbl of refined products
Improved environmental performance
Kearl emissions comparable to average barrel of crude refined in U.S.
Source: IHS CERA Oil Sands, Greenhouse Gases, and U.S. Oil supply Getting the Numbers Right – 2012 Update
12005 2Canadian oil sands
Average barrel refined in U.S.1
Kearl
Mexico / Maya Venezuela / Bachaquero
Mining synthetic crude oil²
CSS diluted bitumen²
California / Midway / Sunset
0
10
20
30
40
Realization (vs. Kearl)
CO2 tax
Sustaining capital
Initial development
Opex—natural gas
Opex—other
Average SAGD 3.0 SOR
Top-tier SAGD 2.5 SOR
Cost structure competitive with SAGD
Profitable across a wide range of oil prices 22
Source: FirstEnergy Capital Corp., FirstFacts, February 14, 2013; costs include G&A
Cost structure*
$/bbl
Kearl
23
Kearl development plan
kbd, gross
40+ year asset life Gross production plateau of 345 kbd, Imperial Oil share 71%
0
100
200
300
400
2013
2050
Initial Development
Expansion Project
Third Ore Preparation Plant
Plant Debottleneck
110 kbd 110 kbd
80 kbd
45 kbd
Funded
24 Kearl expansion project 52% complete
On schedule and on budget for late 2015 start-up
Funded in 2011 for $8.9 billion, 110 kbd additional production
Contractor continuity with KID, constructing full-size modules in Edmonton
25
Market access strategy
0
100
200
300
400
2014
2016
2018
Commitments to new pipeline capacity
kbd
Currently transporting 400 kbd from Alberta by pipeline
?Secured 390 kbd of additional capacity
?Keystone, Gulf Coast Access, Keystone XL, Trans Mountain, Energy East
Advancing rail options to mitigate pipeline uncertainties
Pursuing a portfolio of options, recognizing uncertainties
A history of success, commitment to further innovate 26
Advancing game-changing technologies
SA-SAGD
Solvent-assisted SAGD
CIMA Chemically induced
micro agglomeration CSP Cyclic solvent process NAE Non-aqueous extraction
in-situ mining
Now Future Time to commercialization
Large, non-proved resource base
13 billion oil-equivalent barrels to support further growth 27
YE 2012 resource base
billion oeb, excludes 2013 acquisitions (Celtic and Clyden)*
* after royalties
0
5
10
15
In-situ Mining Other
Liquids
Gas Growth opportunities
Progressing
28
New in-situ opportunities Resource potential 295,000 net acres 3+ billion barrels Top-tier quality Enabling technology SAGD/SA-SAGD Potential scope 9+ phases 35-45 kbd per phase Commercial start-up Post-2020 Forward plans Regulatory applications starting in 2013/14 Development planning on-going, production potential of 300+ kbd
Unconventional gas opportunities
Large acreage position, development optionality Resource potential Enabling technology Potential scope Forward plans
29
50:50 Imperial Oil, ExxonMobil
495,000 net acres
15+ TCF
Liquids-rich Montney
Horizontal drilling
Hydraulic fracturing
Large-scale LNG project
Favourable Montney economics
Continue Horn River pilot
Progress potential LNG
Montney development
30 * before royalties 0
200
400
600
800
1000
2010
~2020
~2030
New technologies/opportunities
Oil sands—mining
Oil sands—in-situ
Conventional
Production outlook*
kboed
Long-term growth Potential of 1+ million barrels per day by about 2030
For more information
www.imperialoil.ca
For more detailed investor information, or to receive annual and interim reports, please contact:
John A. Charlton
Manager, Investor Relations
Imperial Oil Limited
237 Fourth Avenue SW
Calgary, Alberta T2P 3M9
Email: john.a.charlton@esso.ca
Phone: (403) 237-4537 31