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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. Disciplined investment and cost management
3. Integration and synergies
4. High-impact technologies and innovation
5. Operational excellence and responsible growth
ExxonMobil relationship
Strong financial performance
Record earnings per share in 2012
2012 1Q13Earnings - $ billions 3.77 0.80Earnings - $ per share1 4.42 0.94
ROCE - % 23 20
Gross production2 - koebd 282 284Refining throughput - kbd 435 430Cash flow - $ billions 4.68 0.60
Investments - $ billions 5.68 2.98
2 before royalties
1 diluted basis
-1
0
1
2
3
4
2009 2010 2011 2012
Chemical
Downstream
Upstream
Corporate
Imperial net income $ billions
4
Industry-leading return on capital employed
Maximizing investment value and life-cycle asset performance
5
0
5
10
15
20
25
30
IMO HSE CVE SU CNRL
Source: Bloomberg, company publications
ROCE%
2012
5-yr. average
Unmatched shareholder distributions
6
0
5
10
15
IMO HSE SU CNRL CVE
Shareholder distributions 2003-2012$ billions
Dividends
Share reductions
Nearly $14 billion returned to shareholders in last 10 years
Source: company publications
Increased ownership per share
2-3 times ownership increase in the last 20 years
7
0
100
200
300
400
Crudeproduction
Refinerythroughput
Chemicalsales
Provedreserves
RepurchasedOutstanding
Share repurchases* 1994–2012
Indexed ownership per share2012 vs. 1994 metrics, %
848 million 902 million
* shares outstanding at year-end and adjusted for 3:1 share splits in 1998 and 2006
8
Long-life, high-quality proved reserves
3.6 billion oil-equivalent barrels, concentrated in world-class assets
0
1
2
3
4
Year-end 2012
Syncrude
Cold Lake
Kearl
Other
2012 proved reservesbillion oeb*
* after royalties
9
Executing plans to achieve significant growth
Investing about $40 billion this decade focused on upstream growth
Average capex per year*$ billions
0
1
2
3
4
5
2000-2009 2010-2019
* Upstream, Downstream, Chemical & Corporate
10* before royalties
0
200
400
600
2010 2013 2016 2020 2020
New OpportunitiesOil Sands - miningOil Sands - in-situConventional
Production volumes to double by 2020
Nearly 200 kbd of additional liquids in funded projects
Production outlook*kboed
2020
Existing
Under construction
To be funded
Starting up
Financial strength to support growth plans
Strong balance sheet maintained under a wide range of scenarios
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• S&P AAA rating
• Flexibility for new opportunities
* Projected at May 31, 2013, includes Celtic acquisition
0%
10%
20%
30%
40%
50%
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
$55/bbl WTI
$95/bbl WTI
Debt to capital*%
12
ChemicalProduction Refining
Petroleum products Commoditiesand specialties
Business segment integration & synergies
Delivering competitive advantage across the full value chain
Crude and natural gas
Leveraging ExxonMobil relationship
Refineries capturing crude price differentials
13
0
40
80
120
160
200
Strathcona Sarnia Nanticoke Dartmouth
2012 throughput kbd
Advantaged crudes
• Strathcona/Sarnia – 100% advantaged
• Expanding access to Nanticoke
• Dartmouth – converting to a terminal
80% of capacity accesses advantaged mid-continent crudes
Cold Lake
A flagship in-situ operation
15
Ownership: 100% Imperial
Commercial start-up: 1985
Gross production: 150 kbd
Active wells: ~ 4,500
Cumulative production: > 1 billion bbls
Proved reserves: 1.1 billion bbls*
Non-proved resource: 2.9 billion bbls*
* after royalties
Consistently delivering nameplate capacity
Industry-leading reliability
16
Production – 3 year average 2010-2012*% of capacity
0 20 40 60 80 100
HSE TuckerShell Orion
CNOOC Long LakeJACOS Hangingstone
CLL Great DivideShell Peace River
COP SurmontSU Firebag
CNQ PrimroseCVE Christina Lake
DVN JackfishSU MacKay RiverCVE Foster Creek
MEG Christina LakeIMO Cold Lake
* note: data for DVN Jackfish is for Phase 1 only and CVE Christina Lake is for Phases A & B only Source: Peters & Co. Limited, geoSCOUT
Highly competitive cost structure
Achieved through operational excellence and cost discipline
In-situ cash operating costs*C$/bbl
17
0 10 20 30
CNQ Thermal
HSE Sask. Thermal
CVE Foster Creek
IMO Cold Lake
CVE Christina Lake
MEG Christina Lake
DVN Jackfish
SU Thermal
STP Thermal
HSE Tucker
CLL Great Divide
* Source: FirstEnergy Capital Corp., FirstFacts May 21, 2013
Increasing recovery through innovation
Leveraging technology and operational best practices
Cold Lake demonstrated recovery%
18
0
20
40
60
1970's 1980's 1990's 2000's 2010+
Phased expansion via “design one, build many”
Over 1 billion barrels produced, continued growth planned
Cold Lake production*kbd
19
0
50
100
150
200
1980 1990 2000 2010
Maskwa
Mahihkan
Nabiye
Mahkeses
Pilots
2012 2015
* before royalties
Nabiye project
On schedule and on budget for 2014 start-up
20
• Funded in 2012 for $2B
‒ 40 kbd production‒ 140 kbd steam generation‒ 170 MW cogeneration‒ 7 pads of 24 wells each
• More than 40% complete
• “Design one, build many” replicates Mahkeses
Kearl
Next generation oil sands development
21
Ownership: 71% Imperial29% ExxonMobil
Commercial start-up: 2013
Gross production: 110 kbd (initial)*345 kbd (final)*
Development cost: $6.80/bbl
Recoverable resource: 4.6 billion bbls*
* Gross, before royalties
The Kearl value advantage
Large resource, long-life production
22
Proprietary froth treatment
Competitive cost structure
Resource quality
Environmental performance
Reliability enhancements
Top-tier resource quality
10.0
10.5
11.0
11.5
12.0
12.5
789101112Total Volume: Bitumen in Place
Incr
easi
ngPr
oces
sing
Effic
ienc
y
Kearl
Increasing MiningEfficiency
A lasting unit cost advantage
Athabasca undeveloped mining resourcesore grade, % bitumen
23
Onsiteupgrader
Naphthenic Froth Treatment
Bitumen Froth
Refinery
3.5%
96.5%
Refinery
Paraffinic Froth Treatment
Diluent
0.1%
8%
92%
X Asphaltenes
Bitumen
Sedimentand water
Bitumen
Sedimentand water
24
Pipeline-quality and refinery-ready crude without an upgrader
Existing mines
Kearl
Synthetic crude
Dilbit
Proprietary froth treatment
Sale
Sale
25
Reliability enhancements
Investments to reduce life-cycle unit operating costs
Oversizedcrusher
Dual slurry prep plantsDual hydro transport
lines to main plant site
Oversized surge bin
Dual surge bin feed conveyors
26
0 200 400 600
US–Midway–Sunset (California)
Venezuela–Petrozuata (upgraded)
Canadian oil sands: CSS dilbit
Canadian oil sands: Mining SCO
Nigeria–Bonny Light
Canadian oil sands: SAGD dilbit
Venezuela–Bachaquero
Mexico–Maya
Canadian oil sands: Mining dilbit (PFT)
Average barrel refined in the US (2005)
Saudi Arabia–Arab Light
Kearl
Wells-to-wheels GHG Emissions*kgCO2/bbl of refined products
Environmental performance
Kearl full-cycle GHGs about the same as average crude refined in U.S.
* Source: IHS CERA Oil Sands, Greenhouse Gases, and U.S. Oil supply Getting the Numbers Right – 2012 Update
0
10
20
30
40
SAGD 1 Kearl SAGD 2
Realization (vs. Kearl) CO2 taxSustaining capital Initial developmentOpex - 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
27* Source: FirstEnergy Capital Corp., FirstFacts, February 14, 2013; costs include G&A
Cost structure*$/bbl
28
Kearl development plan*kbd
40+ year asset life
Gross production plateau of 345 kbd, Imperial share 71%
0
100
200
300
400
* before royalties
2013 2050
Initial Development
Expansion Project
Third Ore Preparation Plant
Plant Debottleneck
110 kbd
110 kbd
80 kbd
45 kbd
Funded
29
Kearl Expansion Project
On schedule and on budget for start-up late 2015
• Funded in 2011 for $8.9B− Initial production 110 kbd
• About one-third complete
• All full-size modules being constructed in Edmonton
• Same contractors as Kearl Initial Development
30
Market access strategy
• Optimize use of existing systems to maximize value
• Participate in multiple new pipeline opportunities
• Use rail options to bridge and provide insurance
• Mitigate any future surplus via portfolio optimizations
Ensure take-away capacity for all equity crude
31
• “Imperial & ExxonMobil refineries can run all initial Kearl production”*
• Access to global marketing expertise
• Portfolio of processing options
• Industry-leading modelling tools for value maximization
Refining capacity to maximize Kearl value
Unique level of technical, operational and commercial support
Refinery* Grosscap. kbd*
Cokingcap. kbd*
Nanticoke 118 0
Sarnia 127 25
Joliet 248 59
Billings 62 10
Beaumont 359 48
Baton Rouge 523 124
Chalmette 195 30
Baytown 584 96
Torrance 156 53
Total 2,372 445
*Source: Wood Mackenzie Upstream Insight April 2013
• Long-term, unmatched commitment
• Systematic research process
• $200 million invested in 2012
• Integrated with ExxonMobil’s research
• Founding member of Canada’s Oil Sands Innovation Alliance (COSIA)
32
Selective value-driven development, industry-leading capabilities
Technology & innovation
A history of success, commitment to further innovate
33
Potential game-changing technologies
SA-SAGDSolvent-assisted SAGD
CIMAChemically induced micro agglomeration
CSPCyclic solvent process
NAENon-aqueous extraction
Deliver business improvements and long-term value
Cold Lake/Grand Rapids
Aspen
Firebag
Horn River
Celtic
Corner
in-situ
2012 non-proved resource base – billion oeb*
0
5
10
15
1 2 3
In-situ
Mining
Other
Liquids
Gas
Growth opportunities
Progressing
gas
mining
Significant growth potential beyond current plans
Future opportunities
34 * after royalties
35 * before royalties
0
200
400
600
800
1000
2010 2020 2030
New technologies/opportunitiesOil Sands - miningOil Sands - in-situConventional
Production outlook*kboed
Long-term growth
Potential of 1+ million barrels per day by 2030
For more informationwww.imperialoil.ca
For more detailed investor information, or to receive annual and interim reports, please contact:
John A. CharltonManager, Investor RelationsImperial Oil Limited237 Fourth Avenue SWCalgary, Alberta T2P 3M9Email: [email protected]: (403) 237-4537
36