2013 TD Calgary Energy ConferenceJuly 10, 2013

Rich Kruger

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

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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

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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

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KearlSyncrude Cold Lake

World-class upstream assets

A distinct competitive advantage

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

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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

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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

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• 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

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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

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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

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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

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Pipeline-quality and refinery-ready crude without an upgrader

Existing mines

Kearl

Synthetic crude

Dilbit

Proprietary froth treatment

Sale

Sale

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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

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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

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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

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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

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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

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• “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)

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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: john.a.charlton@esso.caPhone: (403) 237-4537

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