2014 TD SecuritiesCalgary Energy Conference

July 8, 2014

Rob DawsonChief Financial Officer

Forward-looking InformationIn the interest of providing you with information regarding Canadian Oil Sands Limited (the “Corporation”), including management’s assessment of the Corporation’s future plans and operations, certain statements and graphs throughout this presentation contain forward-looking information and forward-looking statements (collectively referred to as “forward-looking statements”) under applicable securities laws. Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “believe”, “plan”, “intend” or similar words suggesting future outcomes. Forward-looking statements in this presentation include, but are not limited to, statements and graphs with respect to: the estimated value and amount of reserves recoverable and the time frame to recover such reserves; the estimated resources; plans regarding crude oil hedges in the future; the expected impact on cash flow from operations and cash flow from operations per share from increasing/decreasing crude oil prices; future dividends and any increase or decrease from current payment amounts; the expected sales volume in 2014; the expected operating expenses in 2014; the expected cash flow from operations and cash flow from operations per share in 2014; the expected realized selling price for the Corporation’s product in 2014; all expectations regarding net debt; the belief that Syncrude production can grow from demonstrated levels through improved reliability initiatives, while at the same time reducing maintenance and repair costs; the expected impact on cash flow from operations from increasing Syncrude production; the anticipated benefits of wet crushing technology; the belief that retrofitting Syncrude’s centrifuges should improve bitumen quality and extraction capacity; the plans to improve the run length of the hydrotreaters; the views on future additional utilities at Syncrude; the expected amount of total major project costs, anticipated target in-service dates and estimated completion percentages for the Mildred Lake mine train replacements and the centrifuge plant at the Mildred Lake mine; the expectation that capital expenditures will significantly decline post 2014; the anticipated reliability improvements resulting from the Mildred Lake mine train replacements; the expectations regarding the timing of planned/announced market access pipelines; the Corporation’s views on future oil prices; the views on future demand for oil and global energy use; all expectations regarding the synthetic crude oil (“SCO”) and West Texas Intermediate (“WTI”) and Brent differentials; the expectations regarding the 2014 annual Syncrude forecasted production range of 95 million barrels to 105 million barrels and the single-point Syncrudeproduction estimate of 100 million barrels (36.7 million barrels net to the Corporation); the timing and duration of the Coker 8-2 turnaround; the expectations regarding the maintenance on Coker 8-1; the expected benefits of the management services agreement with Imperial Oil; and Crown royalties payable in the future. You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Corporation believes that the assumptions and expectations represented by such forward-looking statements are reasonable and reflect the current views of the Corporation with respect to future events, there can be no assurance that such assumptions and expectations will prove to be correct. The factors or assumptions on which the forward-looking statements are based include, but are not limited to: the assumptions outlined in the Corporation’s guidance document as posted on the Corporation’s website at www.cdnoilsands.com as of the date hereof and as subsequently amended or replaced from time to time, including without limitation, the assumptions as to production, operating expenses and oil prices; the successful and timely implementation of capital projects; Syncrude’s major project spending plans; the ability to obtain regulatory and joint venture owner approval; our ability to either generate sufficient cash flow from operations to meet our current and future obligations or obtain external sources of debt and equity capital; the continuation of assumed tax, royalty and regulatory regimes and the accuracy of the estimates of our reserves and resources volumes. Some of the risks and other factors which could cause actual results or events to differ materially from current expectations expressed in the forward-looking statements contained in this presentation include, but are not limited to: volatility of crude oil prices; volatility of the SCO to WTI differential; the impact that pipeline capacity and apportionment and refinery demand have on prices for SCO; the impacts of regulatory changes especially those which relate to royalties, taxation, tailings, water and the environment; the impact of new technologies on the cost of oil sands mining; the impacts of rising costs associated with tailings and water management; the inability of Syncrude to obtain required consents, permits or approvals, including without limitation, the inability of Syncrude to obtain approval to release water from its operations; the impact of Syncrude being unable to meet the conditions of its approval for its tailings management plan under Directive 074; various events which could disrupt operations including fires, equipment failures and severe weather; unsuccessful or untimely implementation of capital or maintenance projects; the impact of technology on operations and processes and how new complex technology may not perform as expected; the obtaining of required joint venture owner approvals from the Syncrude owners for expansions, operational issues and contractual issues; labour turnover and shortages and the productivity achieved from labour in the Fort McMurray area; uncertainty of estimates with respect to reserves and resources; the supply and demand metrics for oil and natural gas; the variances of stock market activities generally; currency and interest rate fluctuations; volatility of natural gas prices; the Corporation’s inability to either generate sufficient cash flow from operations to meet our current and future obligations or obtain external sources of debt and equity capital; general economic, business and market conditions and such other risks and uncertainties described in the Corporation’s Annual Information Form dated February 20, 2014 and in the reports and filings made with securities regulatory authorities from time to time by the Corporation which are available on the Corporation’s profile on SEDAR at www.sedar.com and on the Corporation’s website at www.cdnoilsands.com. You are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation and unless required by law, the Corporation does not undertake any obligation to update publicly or revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this presentation are expressly qualified by this cautionary statement.In this presentation we refer to additional GAAP and non-GAAP financial measures that do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”). We refer to additional GAAP financial measures such as cash flow from operations, cash flow from operations on a per share basis and net debt. For more information on additional GAAP financial measures please refer to our 2014 First Quarter Report which is available on the Corporation’s profile on SEDAR at www.sedar.com and on the Corporation’s website at www.cdnoilsands.com. In this presentation we also refer to non-GAAP financial measures such as free cash flow, return on equity, enterprise value and earnings before interest and taxes. For more information on free cash flow and return on equity (referred to as return on average shareholders’ equity in our 2013 Annual Report) please refer to our 2013 Annual Report, which is available on the Corporation’s profile on SEDAR at www.sedar.com and on the Corporation’s website at www.cdnoilsands.com. Enterprise value and earnings before interest and taxes are discussed in this presentation.Third party information: To the extent that information contained in this presentation, forward-looking or otherwise, has been derived from third party sources such as First Energy, Bloomberg, the International Energy Agency, and IHS CERA, the Corporation makes no representations or warranties, express or implied, as to the quality, accuracy and completeness of such information.

Syncrude: A High Quality Resource

• Established production base

• Long-life reserves

• Fully upgraded light, sweet crude oil

• Proven operator and proven technology

• Predictable reservoir recovery – over 90%

Highly Leveraged to Increasing Crude Oil Prices1

0.00

1.00

2.00

3.00

4.00

$70 $80 $90 $100 $110

Illustrative cash flow from operations ($/share)2

WTI (US$/bbl)

2014 estimate

All figures in Canadian dollars unless otherwise noted.1. Every US $1.00/bbl WTI increase/decrease in crude oil price increases/reduces cash flow from operations/share by $0.05 after tax; see April 30/14 Guidance

for other sensitivities; this assumes no other changes to operating expenses or other assumptions from the April 30/14 Guidance; see the risk factors outlined in our Annual Information Form dated Feb. 20/14 as to other risks; for illustrative purposes only – COS is not expressing a particular view on crude oil prices.

2. Additional GAAP measure; assumes April 30/14 Guidance of: $0.92 US$/Cdn$ FX, $4/bbl SCO discount to Cdn$WTI, $46.08/bbl operating expenses and sales of approximately 100,700 bbl/d net to COS.

COS Demonstrates Compelling Valuation Relative to New Mining Projects

Per flowing bbl of capacity

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

Cost of Mine Infrastructure COS

COS enterprise value reflects mine infrastructure PLUS:• Upgrader producing light,

sweet crude oil• All of our reserves and

resources • Production today, generating

a high dividend payout

1. COS’ value per flowing bbl of capacity represents enterprise value based on market cap as at June 19/14 and net debt at March 31/14, divided by production design capacity of 128,000 bbl/d; enterprise value is a non-GAAP measure.

2. Cost of Mine Infrastructure reflects range of costs and production capacities based on company estimates for the Fort Hills project (Suncor/Total/Teck) and Kearl Lake (Imperial).

Dividends Reflect Free Cash Flow Over Time (1,2)

1. Includes distributions on trust units prior to Dec. 31/102. Free cash flow (FCF) is cash flow from operations less capital expenditures and is a non-GAAP measure

Cumulative Dividends/FCFAnnual Total Dividends$ millions

$(1,000)

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$(300)

$-

$300

$600

$900

$1,200

$1,500

$1,800

$2,100

$2,400

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Dividends

Cumulative Dividends

Cumulative FCF

Operating Leverage

0

50

100

150

200

250

300

350

400

2007 2008 2009 2010 2011 2012 2013 2014F

Syncrude production Thousand barrels per day

2014F based on April 30/14 Outlook.

Average production of 287,000 bbl/d since 2007

Every 2 million bbl change in 2014 Syncrude production impacts cash flow from operations by $44 million

Froth Production

Issues with crushers and conveyors contributed to approximately

3 MBbl production restriction in 2013

Actions taken include:

• Aurora Mine Relocation in 2013

– Comprehensive rebuild of trains 2 and 3

• Mildred Lake Mine Train Replacement

– New design includes wet crushers for increased recovery

– Increases unit capacity by 20%

Froth Treatment and Distillation

High solids in the bitumen feed causing furnace tube leaks downstream in distillation units contributed to approximately 2 - 4 MBbl production restriction.

Actions taken include:

• Improved product quality of feed to upgrader

• Reconfigured centrifuge process design to increase feed capacity

• Retrofitting bitumen centrifuges

Hydro Processing

Fouled hydrogen plant exchangerReliability issues in hydro processing have led to as much as 5 MBbls/yr of lost production

Actions taken include:

• Program to replace the waste heat recovery exchangers in all four hydrogen plants planned to be completed in the Q2 2014 turnaround

• Plan to improve run length of hydrotreaters

Utilities

Additional steam and power utilities planned in 2017

Gas Turbine Generator

0

100

200

300

400

500

600

700

800

900

1000

2011 2012 2013 2014 2015

Centrifuge Tailings Management

Mildred Lake Mine Train Replacement

Aurora North Tailings Management

Aurora North Mine Relocation

Major Projects Capital Expenditure Profile$ millions, net to Canadian Oil Sands

Capital costs only; excludes capitalized interest and certain development costs.

Mildred Lake Mine Train Replacements (MLMR)

Currently 85% complete

Expected in-service date of Q4 2014

Cost estimates revised downward to $3.9 billion from $4.2 billion (gross to Syncrude)

Tightened range around cost estimate to +5% / -10%

(1) Total project costs are net COS’ 36.74% working interest and include both capital and certain development expenses; costs exclude capitalized interest.

(2) The estimated percentage complete is based on hours spent as a percentage of total forecasted hours to project completion.

Centrifuge Tailings Management Project

Currently 75% complete

Expected in-service date of first half of 2015

Cost estimate remains at $1.9 billion (gross to Syncrude)

Range around the cost estimate remains at +15% / -15%

(1) Total project costs are net COS’ 36.74% working interest and include both capital and certain development expenses; costs exclude capitalized interest.

(2) The estimated percentage complete is based on hours spent as a percentage of total forecasted hours to project completion.

Quality and Location Differentials

$40

$50

$60

$70

$80

$90

$100

$110

$120

$130Trailing 3-Month Average

Brent

SCO

WTI

WCS

Bitumen

Cdn $/bbl

Kitimat

Hardisty

Edmonton

Burnaby

Cushing

Montreal

Houston

Sarnia

Patoka

Quebec City

Markets for COS’ Syncrude Production

Chicago

Syncrude

Current synthetic crude oil markets

Potential new markets

World Energy Demand by Fuel Type

Source: International Energy Agency, World Energy Outlook 2013

Global energy needs expected to increase by 30%Oil use is expected to increase 13% to 101 million barrels per day

COS Investment Catalysts

1. Production growth through improved reliability

2. Completion of remaining major projects

• Mildred Lake Mine Replacement (MLMR)

• Tailings Centrifuge Project

3. Market access

• Narrowing of SCO-WTI-Brent differentials

4. Market view of long-term oil prices

These four catalysts represent potential to improve total shareholder return

Plus, COS offers:

Ø Solid finance plan and a strong balance sheet

Ø Currently, approximately 6% yield

Appendix

Follow us:

Twitter @cdnoilsandswww.cdnoilsands.com/blog

1.6

5.1

2.2

2.3

Prospective resources

Contingent resources

Probable - Undeveloped

Proved plus Probable - Producing

Large Syncrude Reserve and Resource Base Supports Decades of ProductionBillions of Synthetic Crude Oil Barrels

1. All amounts gross to Syncrude. Canadian Oil Sands Limited, through its wholly-owned partnership, holds a 36.74% interest in the Syncrude Project. Based on independent reserves and resources estimates by GLJ Petroleum Consultants, Ltd. as of Dec. 31/13. See reserves and resources cautionary advisory in Canadian Oil Sands’ Annual Information Form dated Feb. 20/14 and the definitions and forward-looking information advisory.

2. Calculated as Proved Developed Producing Reserves of 2.0 billion barrels plus Probable Producing Reserves of 0.3 billion barrels. Probable Producing Reserves calculated as Total Probable Reserves of 923 million barrels (net to COS) less Probable Undeveloped Reserves of 812 million barrels (net to COS) equals 111 million barrels (net to COS) or 0.3 billion barrels (100% Syncrude).

3. Calculated as 812 million barrels (net to COS) grossed up to reflect 100% Syncrude.4. Reserve Life Index (RLI) based on COS April 30, 2014 Guidance of approximately 100 million barrels per year of Syncrude production (36.7 million barrels net to COS).

• Mildred Lake Extension

• Other leases

• Other leases

•Aurora South

• Mildred Lake• Aurora North

RLI= 23 years 42

3

1

RLI= 22 years 4

Pure Play Oil Sands Investment

0% 20% 40% 60% 80% 100%

COS

Canadian Natural

Cenovus

Imperial

MEG

Suncor

Oil sands as % of total production

Source: FirstEnergy Capital Nov. 8/13 report

Our production is 100% light, sweet crude oil

Syncrude Upgrader Delivers Significant Value

$0

$20

$40

$60

$80

$100

$120

COS Mining Peer Mining &SAGD Peer

TypicalSAGD Peer

Operating expenses, G&A, Royaltiesand otherDepreciation

Earnings before interest and taxes

per bbl

1. Data for the year ended December 31, 2013 for COS, CNRL Horizon Cash Production Costs, Cenovus Operating, MEG Net Operating Costs, Suncor Total Cash Operating Costs

2. SAGD based on volume-weighted average of Cenovus (Christina Lake and Foster Creek), MEG and Suncor In-situ3. “Other” for COS and Suncor refers to non-prod. or dev. costs, MEG is share-based comp and R&D, CNRL is share-based comp and Cenovus is research4. COS operating expenses include Syncrude G&A5. Earnings before interest and taxes is a non-GAAP financial measure. Calculated as net income plus tax and net finance expenses plus FX gain (loss)

COS EBIT~ $35/bbl

1, 41

1, 2

3

5

1

Sales volume (bbl/d)2 100,700

Realized selling price ($/bbl) 96.00

Operating expenses ($/bbl) 46.08

Cash flow from operations ($millions)3 1,194

Cash flow from operations ($/share)3 2.46

2014 Outlook

20141

1. 2014 Outlook as at April 30/14.2. Sales after crude oil purchases and transportation expense.

3. Additional GAAP measure.

Managing a Strong, Efficient Balance Sheet

1. Non-GAAP measure

Net debt1, $ millions

0

500

1000

1500

2000

2005 2006 2007 2008 2009 2010 2011 2012 2013

Targeting net debt level of $1 to $2 billion

Syncrude Supported by Management Services Agreement with ExxonMobil and Imperial Oil

Canadian Oil Sands(COS)

25%

Suncor

Sinopec

36.74%

12%

Nexen(CNOOC)

7.23%

Murphy Oil

Mocal

5%

Imperial Oil

XOM/IMO provide global best practices, proprietary systems and staff expertise

JV ownership structure

COS: a Premier Pure-play Oil Sands Investment

• Ticker: COS on Toronto Stock Exchange

• Shares outstanding: 484.6 million

• 52 week high / low / close1: $24.68/ $18.85 / $24.27

• Market cap: $11.8 billion1

• Enterprise value: $13.1 billion2

• Quarterly dividend amount: $0.35 per share3

• High dividend payout: 5.8%4

All figures in Canadian dollars1. As at June 19/14.2. As at June 19/14 and net debt at March 31/14; non-GAAP measure.3. Paid on May 30/14 to shareholders of record on May 23/14.4. Based on close price as at June 19/14 and dividend announced on April 30/14, annualized.

COS has Significantly Outperformed the Market Over the Long-term

Source: Bloomberg

Average compound annual return

14%

10%

8%

-100%

0%

100%

200%

300%

400%

500%

600%

700%

Dec

-03

Apr

-04

Aug

-04

Dec

-04

Apr

-05

Aug

-05

Dec

-05

Apr

-06

Aug

-06

Dec

-06

Apr

-07

Aug

-07

Dec

-07

Apr

-08

Aug

-08

Dec

-08

Apr

-09

Aug

-09

Dec

-09

Apr

-10

Aug

-10

Dec

-10

Apr

-11

Aug

-11

Dec

-11

Apr

-12

Aug

-12

Dec

-12

Apr

-13

Aug

-13

Dec

-13

10 Year Cumulative Return as of December 31, 2013

Canadian Oil Sands

S&P/TSX Oil & Gas

S&P/TSX Composite

Demonstrating Strong Return on Shareholders’ Equity

Average ROE of 24% since 2001

Return on Equity calculated as net income divided by average shareholders’ equity; Net income as per COS’ financial statements

Return on shareholders’ equity is a non-GAAP measure.

$-

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Perc

enta

ge R

etur

n

Canadian Oil Sands' ROE

Return on Equity

Average ROE of 24%

Average Share Price

Syncrude is a Leader in Sustainable Oil Sands Development

Recognition

Reflects industry best practices• Mining Association – Toward Sustainable Mining

• Canadian Association of Petroleum Producers – Responsible Canadian Energy Program

• Canadian Council for Aboriginal Business – Progress Aboriginal Relations Program

• Canadian Business for Social Responsibility

• Canadian Industry Program for Energy Conservation

Leading Research and Development• Syncrude operates the industry’s only dedicated R&D centre

• Syncrude spends $60 million on R&D each year; one of Top 50 spenders in Canada

• Syncrude is a founding member of Canadian Oil Sands Network for Research and Development (CONRAD) and the Oil Sands Tailings Consortium (OSTC), which will be managed under the recently formed Canadian Oil Sands Industry Alliance (COSIA)

CSR Reporting• Syncrude publishes a bi-annual sustainability report

www.syncrudesustainability.com• Also publishes an annual Aboriginal Review

Production Declines Dramatically Without Further Investment

Source: International Energy Agency, World Energy Outlook 2013; Production declines from all currently producing fields in the absence of further investment.

“Wells-to-wheels” CO2 Emissions

Source: IHS CERA Special Report – Oil Sands Dialogue: Oil Sands, Greenhouse Gases, and US Oil Supply: Getting the Numbers Right, November 2012

Average oil sands is only 9% more GHG intensive than average U.S. barrel

Environmental Regulations• GHG

– Provincial regulations require 12% reduction in emission intensity over 2003 - 2005 average for large emitters

• If not met, the emitter may: – Pay $15/tonne levy into Climate Change and Emissions Management Fund– Purchase Alberta based offset credits – Purchase emission performance credits from a different Alberta facility.

– Federal government targeting 17% reduction by 2020 from 2005 levels

• Land– Alberta law requires land reclamation to productivity equal to or better than original – Directive 074 - requirements to reduce tailings and accelerate reclamation

• Water– All existing and approved oil sands projects restricted to withdraw less than 3% of average

annual flow of Athabasca River – Further restrictions during low flow periods; actual usage by industry less than 1% of average

annual flow

Syncrude Crown Royalty Terms*

• Greater of 25% net bitumen revenue less capital and operating costs, or 1% of gross bitumen revenue*

– Previously based on Synthetic Crude Oil (upgraded from bitumen) revenues and costs

• Repay $1.25 billion plus interest over 25 years for previously deducted upgrader growth capital

– Payments deferred during 1% royalty periods

• Pay an additional $975 million in royalties as per schedule:

– Amount will be prorated to extent Syncrude daily average bitumen production over 6-year period less than 345 KBPD

* Terms and rates effective Jan. 1/09 to Dec. 31/15. The royalty agreements are available on the Corporation’s profile at www.sedar.com. Effective Jan. 1/16 New Royalty Framework rates apply.

2010 2011 2012 2013 2014 2015 Total

$75 mm $75 mm $100 mm $150 mm $225 mm $350 mm $975 mm

All figures gross to Syncrude

2014 Crown Royalty Calculation

1. Bitumen revenue is based on an SCO yield of 87% and a bitumen price equal to 60% of C$WTI.2. Royalty rate is the greater of 25% of net revenue or 1% of revenue.3. As part of the transition to the generic royalty regime, Syncrude is obligated to pay additional Crown Royalties of $975 million over 2010-

2015. The $54 million shown above is COS’ share of the 2014 expense based on accrual accounting; actual cash payments are per the schedule on previous slide. In any given year, the difference will be reflected as a change in Crown royalty payable.

See COS’ 2013 Annual MD&A dated Feb. 20/14 for further discussion on Crown royalties.

Based on 2014 Outlook provided Apr. 30/14

SCO % Mining Bitumen

Revenue1 3,528 2,534Operating expenses (1,693) 80% (1,354)Non-production costs (176) 80% (141) Capital expenditures (842) 85% (716) Net revenue 323

Crown royalty2 81Upgrader growth capital recapture payment 25Additional Crown royalty expense3 54Total Crown royalty 160

Crown royalty (per bbl) $4.35