1

Oil sands – key to building value

Harbir Chhina

Executive Vice-President, Oil Sands

Investor Day | Calgary | December 7, 2011

Oil sands ─ key to building value

• Maximizing value at producing properties• improving cost, schedule &

production

• Recognizing value at emerging properties• proving up resource &

advancing development

• Adding value through innovation• developing technology &

enhancing processesCenovus land at Dec. 31, 2009.

ALBERTA

BorealisGreater Pelican

RegionBorealis Region

Christina Lake Region

Foster Creek Region

Cenovus land at Dec. 31, 2010

ALBERTA

SASKTACHEWAN

2

• Top quality reservoirs

• Manufacturing approach & project execution

• Operational excellence

• Experienced team

• Technological innovations

• Stakeholder relationships & environmental track record

Why we’re successful

0

2

4

6

8

10

Land

Exp

lora

tion

/pilo

ting

Del

inea

tion

Prep

are

/file

applic

atio

n

Applic

ation

appro

val

Engin

eeri

ng,

pro

cure

men

t &

con

stru

ctio

n Production

30+ years

Net assetvalue

Sustainable, predictable development

Full field developmentExpansion phasesInitial development

Pre development

Pelican Lake WabiskawTelephone LakeSteepbank

Christina LakeGrand RapidsEast McMurray

Foster CreekNarrows LakeWinifred Lake

5 years 5 – 7 years

FC-A-E, CL-A-C

FC - FGH

CL - E

CL - D

More than half of our oil sands leases have zero wells per section

1 – 3 years

3

Building NAV by converting resources

Discovered BIIP56 Bbbls

Undiscovered BIIP*82 Bbbls

1P

2P

2C 6.1 Bbbls

7.8 Bbbls137 Bbbls

*Undiscovered BIIP is unrisked. Volumes are shown before royalties and on a net basis.

Foster Creek – improving on a top tier reservoir

2012

2011

Milestones

Test secondary pay

Expand Wedge WellTM

technology use

Pilot CO2 co-injection

Ramp up to full construction

Exceed nameplate production

Conduct May turnaround

Convert first well pairs to blowdown

Commercialized blowdown boiler

Tested liner design

Progressed phase F (30% complete)

Produced at 95% of nameplate

Completed turnaround

Technology developmentPhase F, G & H expansionPerformance

4

0

20

40

60

80

100

120

1-Dec-10 1-Mar-11 1-Jun-11 1-Sep-11 1-Dec-11

Operational excellence – Foster Creek

Mbbls/d

Volumes are shown on a 100% basis.

Tu

rnaro

un

d

Record production122 Mbbls/d July 1, 2011

Technology increases capacity at Foster Creek

• Overall production capacity increased by 20,000 bbls/d resulting from:

• success of Wedge WellTM technology

• plant optimization

45,000 – 65,0002017F+Future phases

40,00035,0002016FH

120,000A - E

NewPriorFoster Creek

290,000 – 310,000270,000 – 290,000Total capacity

40,00035,0002015FG

45,00035,0002014FF

Expected production capacity (bbls/d) grossProject phase First production target

5

0

20

40

60

80

100

120

Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-111.6

1.9

2.2

2.5

2.8

3.1

3.4

Total production Wedge Well production ISOR

Technology improved performance

Wedge WellTM

technology reduced SOR:

2.5 to 2.2

Mbbls/d ISOR

TM

Christina Lake – top tier reservoir

2012

2011

Milestones

Pilot CondenSAP

Drill downspacing wells

Achieve first oil at phase D (Q4)

Ramp to full capacity (Q2)

Tested improved start-up technique

Implemented Wedge WellTM technology

Accelerated project timing

Achieved first production

Improved schedule & cost

Technology development

Phase D & E expansionPhase C expansion

6

0

10

20

30

40

50

1-Dec-10 1-Mar-11 1-Jun-11 1-Sep-11 1-Dec-11

Operational excellence – Christina Lake

Volumes are shown on a 100% basis.

Record production45 Mbbls/d Nov. 27, 2011

Tu

rnaro

un

d

Mbbls/d

Advancing timing at Christina Lake

• Strong execution drives improved schedule for Christina Lake phases D & E

58,000A - C

NewPriorChristina Lake

40,0002017FQ4-2009G

40,000Q4-2013F2014FQ4-2009E

2019F

Q4-2012F

258,000

40,000

40,000

40,000

Expected production capacity (bbls/d) gross

2013FH

2016FQ4-2009F

Q1-2013F

Total capacity

D

Project phase

Q3-2007

First production targetRegulatory application filings

7

Leading capital efficiency

Foster Creek$/bbl/d $/bbl/d

Christina Lake

Capital efficiency is calculated based on production design capacity for each phase.*Foster Creek F,G&H expectations reflect greenfield expansion and design enhancement initiatives.

0

10,000

20,000

30,000

A 20Mbbls/d

B 10Mbbls/d

C 30Mbbls/d

D&E 60Mbbls/d

FG&H*125Mbbls/d

Actual costs Projected costs

0

10,000

20,000

30,000

A&B 18Mbbls/d

CD&E 120Mbbls/d

FG&H 120 Mbbls/d

Actual costs Projected costs

2012

2011

Milestones

Continue to expand polymer flood

Add 4th drilling rig Q1

Commence new battery construction

Begin field pipeline upgrade

Achieve production growth

Expanded polymer flood

Commenced infill drilling with 2 rigs, added a 3rd in July

Drilled 70 infill wells

Maintained production

Technology development

ExpansionPerformance

Pelican Lake – our lowest risk growth opportunity

8

Volumes are shown before royalties. 2011F based on commodity price assumptions as outlined in the October 27, 2011 guidance document. 2012F based on midpoints of December 7, 2011 guidance document. 2013F through 2020F based on future price assumptions as noted in the advisory.

0

20

40

60

80

100

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

Grand Rapids + hot water flood

Polymer/infill

Waterflood

Primary

Opportunity to apply technology to grow

production

Pelican Lake – tremendous growth opportunity

Mbbls/d

F FF FF

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Telephone Lake*

Grand Rapids

Narrows Lake

Advancing our emerging projectsRegulatory approval Construction Steam & production

*Timeline subject to change; production not currently included in 10-year plan.Steam and production includes ~6 months initial steaming with no production followed by 12 - 18 month production ramp up. Timing subject to regulatory approval and project sanction.

65,000

180,000

90,000

Productioncapacity

bbls/d net

335,000

Forecast

9

Adding value through innovation

• Successfully developing technology through:

• culture of innovation

• portfolio of projects to minimize risk

• financial capacity to support field testing (60/40 rule)

• emphasis on pilot testing

• collaboration opportunities

• Protecting our intellectual property rights

“Status quo is unacceptable” – Harbir Chhina

Blowdown boiler commercialized in 2011• Utilizes boiler water (blowdown)

as feed water for second boiler

• Generates more steam from the same water

• Improves heat recovery

• Lowers operating costs & emissions

• Improves steam quality from ~77% to ~92%

OTSGSAGDsteam77%

Blowdown23%

Blowdownboiler

SAGD steam15%

Blowdown8%

BFW 1st BD 2nd BD

10

Commercializing one technology per year

2004 2006 2008 2010 2012 2014 2016

ESP (phase 2)

New drilling method

Combust ion (AIDROH)

Conf ident ial project

Conf ident ial project

Conf ident ial project

Warm Lime Softening

Conf ident ial project

Conf ident ial project

Blowdown boiler

Chemical Looping Combust ion

Accelerated start-up

Wedge WellTM technology

ESP (phase 1)

Solvent processes

Develop Pilo t Commercial demonstration *

*Commercial demonstration may take up to 4 years to become part of mainstream process.

Developing technology to build value

1. ESP (phase 2) – early stage enhancement of pump technology

2. CondenSAP – a condensate based Solvent Aided Process

3. SAP – butane based, being piloted at Christina Lake, commercial plans for Narrows Lake

4. Blowdown boiler – part of all future template designs, makes more steam per mcf of gas used

5. Wedge WellTM technology – commercialized at Foster Creek

CommercialPilotDevelop

Value

2

34

5

Stage

1

58% 10%32%

ESP (phase 2)

Blowdown boiler

CondenSAP

SAP

Wedge WellTM

technology

11

• Maximizing value at producing properties

• improving cost, schedule and production

• Recognizing value at emerging properties

• proving up resource and advancing development

• Adding value through innovation

• developing technology and enhancing processes

Cenovus land at Dec. 31, 2009.

ALBERTA

BorealisGreater Pelican

RegionBorealis Region

Christina Lake Region

Foster Creek Region

Cenovus land at Dec. 31, 2010

ALBERTA

Oil sands – a key to building value

SASKTACHEWAN

Supplemental information

12

Oil sands project comparison

36,48052,48012,96012,48070,720Land position (net acres)

0 – 161 – 811 – 268 – 408 – 26Core area well density (wps)

55 – 6555 – 6545 – 5545 – 5530 – 40Supply cost (US$/bbl WTI)

1.3

3.0 – 3.5

180

100%

Grand Rapids

1.2

2.1

90

100%

Telephone Lake

0.50.40.8Contingent resource (best estimate)

2.1 SAGD1.6 SAP1.72.1Design SOR

Potential size (Mbbls/d gross)

Working interest

130258290 – 310

50%50%50%

Narrows LakeChristina Lake

Foster Creek

Standard SAGD well pair and steam chambers coalesce

Wedge

Well producer

• Technology details:• < 0.1 average SOR

• first year production rate of 600 – 800 bbls/d at Foster Creek, current average of 400 bbls/d; 300 – 400 bbls/d at Christina Lake

• acceleration of production

• 10 – 15% potential increase in recovery factor

• Foster Creek wells – 38 producing, 13 coming on, 10 planned for 2011F

• Christina Lake wells – 4 producing

Wedge WellTM technology

13

0

50

100

150

200

250

Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-140

5,000

10,000

15,000

20,000

25,000

Wedge Well production

Wedge Well count

Well pair count

Wedge WellTM technology growthbbls/dWell count

TM

TM

Cenovus’s Solvent Aided Process (SAP)• SAP versus SAGD metrics

• 30% production rate improvement

• 15% incremental total oil recovery

• 3% reduction in annual fuel gas usage

• 0.05 bbls solvent (butane) purchased per bbl bitumen

• 30% increase to initial capital• 10% decrease in annual

sustaining capital• 5 – 10% reduction in non-fuel

operating cost• ~$1.00/bbl netback uplift

• Environmental benefits• lower SOR & emission intensity• lower water usage & footprint

Steam & solvent (SAP)

Steam only (SAGD)

Q2 SAP & SAGD Narrows Lake2010

Christina Lake isolated test2009 – 2011F

Christina Lake SAP pilot2004 – 2005

Senlac SAP pilot2000 – 2001

Milestones

14

Forward looking informationThe presentations and posters at Investor Day 2011 contain certain forward-looking statements and other information (collectively “forward-looking information”) about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-looking information in this presentation is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast” or “F”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “milestone”, “proposed”, “scheduled”, “outlook”, “potential”, “may” or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projected future value or net asset value, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, anticipated finding and development costs, expected reserves and contingent, prospective or in-place resources estimates, potential dividends and dividend growth strategy, anticipated timelines for future regulatory, partner or internal approvals, forecasted commodity prices, future use and development of technology and projected increasing shareholder value. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

The assumptions on which our 2011 guidance is based include actual prices for the first 9 months of 2011 and September 30 strip pricing for the remainder of the year and an average number of shares outstanding of approximately 758 million. Approximate September 30 strip prices: WTI of US$79.40/bbl; Western Canada Select of US$69.25/bbl; NYMEX of US$3.80/MMBtu; AECO of $3.50/GJ; Chicago 3-2-1 Crack Spread of US$31.95; and exchange rate of $0.961 US$/C$. For the period 2013 to 2021 assumptions include WTI of US$85.00-US$105.00/bbl; Western Canada Select of US$71.00-US$85.00/bbl; NYMEX of US$4.00-US$6.00/MMBtu; AECO of $3.30-$5.25/GJ; Chicago 3-2-1 crack spread of US$9.00; exchange rate of $0.98-$1.07 US$/C$; and average number of shares outstanding of approximately 752 million. 2012 guidance is based on an average diluted number of shares outstanding of approximately 759 million. It assumes WTI of US$90.00/bbl; Western Canada Select of US$75.00/bbl; NYMEX of US$3.50/MMBtu; AECO of $3.10/GJ; Chicago 3-2-1 Crack Spread of US$14.50; and exchange rate of $0.975 US$/C$.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include: assumptions inherent in our current guidance, available at www.cenovus.com; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects; our ability to generate sufficient cash flow from operations to meet our current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity prices, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; maintaining a desirable ratio of debt to adjusted EBITDA and debt to capitalization; our ability to access external sources of debt and equity capital; success of hedging strategies; accuracy of our reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate our integrated heavy oil business; reliability of our assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining of crude oil into petroleum and chemical products at two refineries; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in Alberta’s regulatory framework, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.

The forward-looking information contained in the presentations and posters, including the underlying assumptions, risks and uncertainties, are made as of December 7, 2011. For a full discussion of our material risk factors, see “Risk Factors” in our 2010 Annual Information Form and “Risk Management” in our most recent Management’s Discussion and Analysis, available at www.sedar.com and www.cenovus.com.

Oil and gas informationThe company-wide bitumen contingent resources estimates and the Pelican Lake discovered petroleum initially-in-place estimates, effective December 31, 2010, and the discovered bitumen initially-in-place estimates, effective December 31, 2009, were prepared by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator, and are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook. For further discussion regarding our (i) bitumen contingent resources, see our 2010 Annual Information Form (AIF) and (ii) our total bitumen initially-in-place and all subcategories thereof, see our June 16, 2010 news release, available on SEDAR at www.sedar.com and at www.cenovus.com. Actual resources may be greater than or less than the estimates provided. As at December 31, 2009, Discovered Bitumen Initially-in-Place (BIIP) company-wide, best estimate, is 56 Bbbls, including 0.1 Bbbls of cumulative production, 1.3 Bbbls of proved plus probable reserves, 5.4 Bbbls of economic contingent resources and 49 Bbbls of unrecoverable BIIP. As at December 31, 2010, proved plus probable reserves were 1.677 Bbbls and contingent resources were 6.1 Bbbls. As at December 31, 2010, Discovered Petroleum Initially-In-Place (PIIP) for Pelican Lake, best estimate, is 1.6 Bbbls, including 95 MMbbls of production, 141 MMbbls of proved reserves, 86 MMbbls of probable reserves and 1,293 MMbbls of unrecoverable PIIP.

Certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head. Additional information relating to our oil and gas reserves and resources is presented in our AIF, available at www.sedar.com and on our website at www.cenovus.com.

NET ASSET VALUE With respect to the particular year being valued, the net asset value (NAV) disclosed herein is based on the number of issued and outstanding Cenovus shares as at December 31 as reported in our Annual Information Form and Form 40-F. We calculate NAV as an average of (i) our average trading price for the month of December, (ii) an average of net asset values published by external analysts in December following the announcement of our budget forecast, and (iii) an average of two net asset values based primarily on discounted cash flows of independently evaluated reserves, resources and downstream data and using internal corporate costs, with one based on constant prices and costs and one based on forecast prices and costs.

NON-GAAP MEASURES The presentations and posters may contain references to non-GAAP measures. These measures have been described and presented in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations. Readers are encouraged to review our Third Quarter Report to Shareholders, available at www.cenovus.com for a full discussion of the use of each measure.

TM is a trademark of Cenovus Energy Inc.