achieving our potential - cenovus energy · 2017-06-20 · achieving our potential brian ferguson...

1

Achieving our potential

Brian Ferguson

President & Chief Executive Officer

Investor DayJune 20, 2017

$1B of capital, operating, and G&A savings

in 3 years

Annualized free funds flow

growth of 14%

Targeting net debt to adjusted EBITDA < 2.0x in

2019

Disciplined annual

production growth of 6%

Corporate breakeven of < US$40/bbl

WTI

Increasing returns to

shareholders

Note: Figures represent the potential outcomes of our five year business plan. Assumes US$50/bbl in 2017 and flat US$55/bbl WTI thereafter. See Advisory.


2

A demonstrated track record of execution

Safely executed 14 major oil sands expansion phases

Reductions since 2014:~50% sustaining capital ~30% operating costs

~30% G&A

Improving reservoir performance and

reducing GHG emissions intensity

We’ve executed before and we’ll continue to deliver

Cost leadership Technology innovationOil sands leader

Targeting $1 billion of cumulative synergies

Capital efficiencies

• Supply chain benefits driven by increased size and scale

• Re-designed well pads• Longer-reach horizontal wells• Multi-well pad development in Deep

Basin• Technology deployment

Operating cost reductions

• Increased activity in the Deep Basin• Cogeneration• Optimized maintenance scheduling• Big data analytics• Consistent field operations model• Portfolio optimization efforts

General & administrative savings

• Leverage increased size and scale• Optimizing workforce• FCCL partnership costs• Discretionary spending• Digital driven efficiencies• Subleasing strategy

~$500 million ~$125 million ~$375 million

Note: See Advisory.

3

Delivering on our potential2017F target milestones Transaction is fully financed2018F – 2021F target milestones

Q1

Continued to demonstrate strong operations

Announced transformational acquisition

Executed acquisition financing plan Resumed construction of Christina Lake phase G

Q2 Closed acquisition and integrated assets

Q3 Announce Pelican Lake and Suffield disposition agreements

In progress

Q4

Announce Palliser and Weyburn dispositionagreements

In progress

Retire asset sale bridge facility

Average 120,000 BOE/d from Deep Basin

2018

Sanction ready on Foster Creek phase H


Commercial demonstration of a solvent-aided process

2019

First oil from Christina Lake phase G in H2

Sanction ready on Narrows Lake phase A


Net debt to adjusted EBITDA < 2.0x

2020+

Achieve $1 billion of cumulative synergies

First production from Foster Creek phase H

First production from Narrows Lake phase A

Note: Sanctioning decisions are contingent upon successful completion of planned asset sales and deleveraging. See Advisory.

Paving the way to deleveragingLiquidity position supports investment grade ratings Transaction is fully financedTargeting < 2.0x net debt to adjusted EBITDA in 2019

2017F 2018F 2019F

$0.8 $0.8 $0.9

$0.5 billion cash on hand

$4.4 billion available oncredit facility

Q1 Q2F Q3F Q4F

Launch Pelican Lake & Suffield

dispositions

Prepare data rooms for Weyburn &

Palliser dispositions

Announce Pelican Lake & Suffield

dispositionagreements

AnnounceWeyburn &

Palliser disposition agreements

Open Weyburn & Palliser data rooms

Repay asset sale bridge facility

Targeting $4.0 - $5.0 billion of asset sales by year end

Free funds flow ($ billions)

2.1x

4.1x

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1.0

2.0

3.0

4.0

5.0

2017F $4.5B of asset saleproceeds

Free funds flow 2019F

Net debt to adjusted EBITDA (times)

Target < 2.0x

Note: Assumes US$50/bbl in 2017 and flat US$55/bbl WTI thereafter. $4.5 billion of asset sale proceeds represents the midpoint of targeted range of $4.0 - $5.0 billion. Estimated liquidity position as at June 30, 2017. See Advisory.

4

Deep inventory of short & long-cycle opportunitiesShort-cycle, high IRR potential in the Deep Basin Low-cost expansion potential in oil sands

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2017F 2018F 2019F 2020F 2021F

Deep Basin production(MBOE/d)

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400

600

800

Spirit River Montney Other Targets

Internal Cenovus estimates

Probable

Proved

Future drilling opportunities by targeted formation Phase Capacity Capital remaining

Go-fwd capital efficiency First oil

(Mbbls/d) ($ millions) ($k/flowing) (Year)

CL phase G 50 800 – 900 16 – 18 2019

FC phase H 40 800 – 900 20 – 23 TBD

NL phase A 65 1,600 – 1,900 25 – 29 TBD

Total 155 3,200 – 3,700 21 – 24

200

250

300

350

400

450

2017F 2018F 2019F 2020F 2021F

Oil sands production(Mbbls/d)

Note: 2017F based on revised guidance published June 20, 2017. Oil sands forecasts do not include incremental production from Foster Creek phase H or Narrows Lake phase A. Based on reserves report prepared by independent qualified reserves evaluators dated March 22, 2017. See Advisory.

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2017F 2018F 2019F 2020F 2021F

Oil sands Deep Basin Conventional

Disciplined production growth of 6% through 2021

• Expect to demonstrate 6% production CAGR from 2018 –2021F

• Expanded portfolio enhances scale, flexibility, and generates significant long-term production growth potential

• Well defined oil sands growth opportunities with emerging technology upside

• combined regulatory approved capacity of 735,000 bbls/d at Christina Lake, Foster Creek, and Narrows Lake

• Complementary short-cycle, low-decline production provides second growth platform in the Deep Basin

• ~1,500 potential drilling opportunities already identified

Full exposure to future growth opportunities Top-tier assets drive growth

Total Cenovus production(MBOE/d)

Note: Assumes disposition of all legacy conventional production volumes in 2017F.

6% CAGR 2018-2021F

5

Technology deployment enhances value

• Targeting a $2/bbl reduction in oil sands sustaining capital costs over the next five years

• Each $1/bbl reduction in finding and development costs has the potential to represent an estimated $650 million in NPV over the remaining life of our producing projects

• Plans to leverage innovation to unlock significant value:

• well pad design and longer reach horizontal wells

• flow control devices

• new start-up techniques

• implementation of a solvent process

• partial upgrading technology initiatives

• facility process enhancements

Focused innovation drives technological advancement Emerging technology drives incremental value

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$9.0

Totalpotential

Illustrative potential NPV uplift(gross, $ billions, discounted at 9%)

Note: Figures represent the expected increase in net present value over the remaining life cycle of current and potential oil sands projects.

Improved reservoir

performance

Future expansions

In development

Solvent aided process, resource additions, longer-term expansions, partial

upgrading, operating cost reductions

Implementing

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2017F 2018F 2019F 2020F 2021F

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$40

$60

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2014 2015 2016 2017F 2018F 2021F

Path to sustainability under US$40/bbl WTI

• Focused on safe and reliable operations

• maintenance & sustaining capital

• Fundamentally changed how we operate our base business to maximize efficiencies

• development and deployment of technology

• Plan to apply a manufacturing approach to the Deep Basin development program

• low base decline rates reduce sustaining capital requirements

• Leveraging our integrated portfolio and increased scale to improve pricing power and reduce costs

Delivering growth more efficiently Improved sustainability generates free funds flow

Note: Implied WTI breakeven represents the price of WTI in US dollars that would be required to generate enough adjusted funds flow to fully cover sustaining capital and the current level of dividend. See Advisory.

14% CAGR 2018-2021F

Total Cenovus free funds flow($ billions)

Implied WTI breakeven(US$/bbl)

Target < $US40/bbl

6

Capital allocation focused on two growth platforms

Note: The above reflects our intended capital allocation priorities in the indicated WTI price environments. See Advisory.

Stress case (< US$40/bbl WTI)

Total capital($ billions) $1.5 - $1.8

Safe & reliable operations Maintain

Oil sands sustaining Maintain

Balance sheet Protect the balance sheet

Oil sands growth No new oil sands projects

Deep Basin growth Reduce growth capital

Returns to shareholders Maintain

Growth case (> US$60/bbl WTI)

$2.5 - $3.0

Maintain

Maintain

Maintain < 2.0x net debt to adjusted EBITDA

A maximum of two projects

Disciplined development

Increase

Base case (US$40 – US$60/bbl WTI)

$1.8 - $2.5

Maintain

Maintain

Target < 2.0x net debt to adjusted EBITDA

A maximum of two projects

Disciplined development

Disciplined growth

Positioned to deliver value-added growth

Deep inventory of short & long-cycle development

Demonstrated execution excellence

Well-defined, low-risk growth profile

Positioned to increase returns to shareholders

Shareholder value proposition

7

Ensuring financial resilience

Ivor Ruste

Executive Vice-President & Chief Financial Officer


Liquidity position supports resilienceLiquidity position Near-term debt reduction

• ~$4.5 billion reduction in net debt position expected by year end

• Targeting net debt to adjusted EBITDA < 2.0x in2019

• ~$5 billion liquidity position supports investment grade ratings

• $3.6 billion drawn on asset sale bridge (12, 18, 24 month maturities)

Net debt($ billions)

Manageable long-term maturities

• Weighted average cost of debt ~5.2%• Expect to manage US$1.3 billion 2019 debt

maturity through refinancing activity and use of free funds flow

Principal outstanding(US$ billions)

$0

$4

$8

$12

$16

Q2 2017F Jan 2018F

Credit ratings

S&P Moody’s DBRS Fitch

BBB Ba2 BBB (high) BBB-

Negative outlook

Stable outlook

Under review –negative

implications

Stable outlook

$0.5 billion cash on hand

$4.4 billion available oncredit facility

Note: $4.5 billion of asset sale proceeds represents the midpoint of targeted range of $4.0 - $5.0 billion. Estimated liquidity position as at June 30, 2017. See Advisory.

~$4.5 billion

$0.0

$0.5

$1.0

$1.5

$2.0

2019

2022

2023

2027

2037

2039

2042

2043

2047

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$55.00

$60.00

$65.00

$70.00

$75.00

0

50,000

100,000

150,000

200,000

H1 2017 H2 2017 H1 2018

Swap volume (bbls/d) Collar volume (bbls/d)Put volume (bbls/d) Floor hedge price (C$/bbl)

Hedging strategy helps manage downsideHedging protects projected cash outflowsAdapting our hedging strategy to maintain resilience

bbls/d C$/bbl• Hedging strategy remains unchanged

• provide added certainty to protect targeted cashoutflows and support investment grade ratings

• Additional hedging approved to maintain resilience in thenear term

• 2017 and 2018 hedged volumes and cash outflowtargets increased to support financial resilienceduring period of asset sales

• Strategy and targets to be re-evaluated followingdivestitures to align with asset base and risk appetite

• Hedge program and instruments employed will ensurealignment with potential contingent payments

Note: US$ hedge prices converted to C$ at 0.7407 US$/C$ May 31, 2017 Bank of Canada noon day rate.

Demonstrated track record of asset salesTargeting $4.0 - $5.0 billion announced by year end

Deep Basin GORRs

Infrastructure assets

Marten Hills

Oil sands GORR

Non-core Deep Basin assets

Pelican Lake

Suffield

Palliser

Weyburn

Successfully executed divestitures Current divestiture processes Potential divestiture candidates

Provost

Boyer

Shaunavon

Bakken

Wainwright

Royalty lands

>$4.0 billion since 2010

Undeveloped oil sands

Note: See Advisory.

9

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1.0

2.0

3.0

4.0

5.0

Q2 2017F 2018F 2019F 2020F 2021F

On track to achieving targeted leverage

• Optimizing capital structure and providing support toinvestment grade ratings

• Targeting net debt to adjusted EBITDA of < 2.0x

• expect to announce agreements for $4.0 - $5.0billion of asset sales in 2017

• free funds flow driven by commodity prices, costreductions, capital discipline, and hedging

Asset sales and free funds flow drive deleveraging Transaction is fully financedPath to target leverage and increased liquidity

Target <2.0x

Note: $4.5 billion of asset sale proceeds represents the midpoint of targeted range of $4.0 - $5.0 billion. Assumes US$50/bbl WTI in 2017 and flat US$55/bbl WTI thereafter. See Advisory.

Net debt to adjusted EBITDA (times)

Maintaining resilience in a lower price environment

• Repositioned the base business to be sustainable across awider range of commodity prices

• Flexibility to reduce capital expenditures to $1.8 - $1.9billion and remain within adjusted funds flow

• continue construction at Christina Lake Phase G

• reduce Deep Basin capital to minimum levels aswe have minimal land expiry drilling requirements

• Ability to utilize $4.5 billion credit facility as appropriate

• 65% debt to capitalization covenant

• Hedging program further supports capital resilience

2018F Adjusted funds flow and capital expenditures($ billions)

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

US$55/bbl US$45/bbl

Adjusted funds flow Capital expenditures

Disciplined spending within adjusted funds flowCapital flexibility maintains resilience

Note: US$55/bbl case assumes flat US$55/bbl WTI. US$45/bbl case assumes flat US$45/bbl WTI. See Advisory.

10

Cost reductions improve sustainabilityOil sands sustaining capital Oil sands operating costs General & administrative costs

Note: See Advisory.

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$3.00

$6.00

$9.00

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$15.00

2014 2017F 2018F 2021F

$/bbl

• > 50% reduction to G&A• Improved efficiencies, workforce optimization,

and reduced discretionary spending

• > 30% reduction to oil sands opex• Non-fuel costs decreasing• Natural gas prices and turnarounds fluctuate

year-to-year

• > 60% reduction in oil sands sustaining capital costs

• Targeting a further $2/bbl reduction by 2021• Savings are expected to be structural

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$6.00

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2014 2017F 2018F 2021F

$/bbl

$0.00

$1.00

$2.00

$3.00

$4.00

2014 2017F 2018F 2021F

$/BOE

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

2017F 2018F 2019F 2020F 2021F

Capital expenditures Operating margin

Sustainability drives free funds flowLow corporate decline rates Improved sustainability Free funds flow growth over time

Note: Peters & Co Limited. Peers include: APA, CNQ, CPG, DVN, ECA, EOG, HSE, IMO, SU, TOU, VII. See Advisory.

0%

10%

20%

30%

40%

50%

CVE

Implied WTI breakeven(US$/bbl)

Total Cenovus capital expenditures and operating margin($ billions)

2017F Corporate decline rate(percent)

$30

$40

$50

$60

$70

2014 2015 2016 2017F 2018F 2021F

~17% Corporate decline rate WTI breakeven < US$40/bbl Increasing free funds flow

Target < $US40/bbl

11

Growth in free funds flow drives returns

Total shareholder return remains a key

component of our value proposition

Dividend growth will be contingent upon

achieving targeted leverage and growth in

free funds flow

Dividends must be sustainable at US$50/bbl WTI

or lower

Consider share repurchases in periods of

excess free funds flow

Targeting consistent growth in total shareholder returns

Committed to investment grade

Disciplined growth

Capital allocation priority

Flexibility of returns

Ensuring financial resilience and flexibility

Liquidity position and strategic hedging program support financial resilience

Portfolio optionality supports targeted $4.0 - $5.0 billion of asset sales

Positioning the portfolio to increase returns to shareholders

Targeting net debt to adjusted EBITDA < 2.0x in 2019

12

Oil sands drives free funds flow

Kieron McFadyen

Executive Vice-President & President, Upstream Oil & Gas


• Successfully executed 14 major capacity expansionsrepresenting 390,000 bbls/d of production capacity

• 26% cumulative annual growth rate since 2006

• Sustaining capital per barrel down > 50%; operatingcosts per barrel down > 30%

Cenovus is the largest thermal oil sands producer A track record of oil sands expansionsProduction capacity(Mbbls/d)

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600

2010 2011 2012 2013 2014 2015 2016 2016A 2019F

CL-CCL-D

CL-EFC-F

CL-CDE

FC-GCL-F

CL-GFC-H

NL-A

2010 production includes 7 phases

Potential growth

opportunities

26% CAGR in production capacity

since 2006

A track record of execution

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Oil sands sustaining capital Oil sands operating costs

2014 2017F

Track record of cost reductions$/bbl

13

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2014 2015 2016 2017F 2018F 2019F 2020F 2021F


• Significant reduction in sustaining capital requirements

• Disciplined capital allocation

• Strong operational performance

Strong free funds flow from top-tier oil sands assetsOil sands capital expenditures and operating margin($ billions)

Improving sustainability and free funds flow

Note: Includes Christina Lake phase G expansion, and excludes Foster Creek phase H and Narrows Lake phase A. Assumes US$50/bbl WTI in 2017 and flat US$55/bbl WTI thereafter.See advisory.

Oil sands drive free funds flow growth

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2017F 2018F 2019F 2020F 2021F

Oil sands production forecastMbbls/d

2.0

3.7

2.0

5.1

2.4

3.4

3.9

4.4

3.7

2.9

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6.0

0

100

200

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400

1 2 3 4 5 6 7 8 9 10 11April 2017 average production Portfolio-weighted SOR

SOR reflects resource quality and executionReinforcing our position as a leader in SAGD

Production(Mbbls/d)

Portfolio-weighted SOR

Cenovus

Note: Production data and steam-oil ratio based on AER data as of April 2017. Portfolio-weighted SOR calculated based on project operator and is a measure of current project efficiency. Peers include ATH, COP, CNQ, CNOOC, DVN, HSE, IMO, MEG, PGF and SU.

Our competitive advantage

• Low SOR means

• lower capital cost

• lower energy usage

• lower operating cost

• smaller surface footprint

• lower emissions

• less water usage2.7

14

Reducing SOR drives increased oil production

Match facility size to reservoir

Focus on achieving design

SOR

Develop technology to improve SOR performance

Maximize production

Steam capacity (fixed)

Steam capacity (fixed)

SORSOR Oil production

Oil production

Christina Lake continues to set industry benchmarks

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2010 2011 2012 2013 2014 2015 2016 2017

Mbbls/d

capacity

Key facts and reservoir characteristicsChristina Lake production history

Current productive capacity phases A-F (bbls/d) 210,000

Regulatory approved capacity (bbls/d) 310,000

Reservoir depth ~375 meters

Net pay ~40 meters

High permeability 5 – 10 darcies

High oil saturation ~80%

API bitumen 7.5° – 9.5°

Cogeneration capacity (MW) 100

CSOR 2.1

Average production per well (bbls/d) 1,140

2P reserves (MMbbls) 2,820

Q1 2017 production (bbls/d) ~180,000

15

Current productive capacity phases A-G (bbls/d) 180,000

Regulatory approved capacity (bbls/d) 295,000

Reservoir depth ~450 meters

Net pay 25 – 30 meters

High permeability 5 – 10 darcies

High oil saturation ~80%

API bitumen 9° – 11°

Cogeneration capacity (MW) 98

CSOR 2.5

Average production per well (bbls/d) 544

2P reserves (MMbbls) 2,660

Q1 2017 production (bbls/d) ~157,000

Significant improvements in Foster Creek performanceKey facts and reservoir characteristicsFoster Creek production history

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2010 2011 2012 2013 2014 2015 2016 2017

Mbbls/dcapacity

Date here 8

• Superior start-up andsteam circulation methods

• Advanced sub-surfaceequipment and design

• High pressure ramp up

8

2011

4D, or time-lapse seismic, can be acquired to determine changes in reservoir over an extended period. Lower conformance (left) can be identified for opportunities to improve well productivity. Consistent and continuous conformance (right) is ideal for best well productivity.

Major improvements Old well design: ~75% conformance New well design: ~90-95% conformance

Results in

New design improves well conformance

• Better conformance alongthe full horizontal well length

• Lower SOR

• Higher oil rates per wellpair

16

0%

5%

10%

15%

20%

25%

30%

0 3 6 9 12 15 18 21 24

Months on production

W10 Pad (2016) W07 Pad (2016) W08 Pad (2015) E08 Pad (2013)

W02 Pad (2011) E15 Pad (2009) E20 Pad (2008)

Improved start-up procedures on new pads

Improved performance

Foster Creek well performance improvingRecovery factor• Longer reach horizontal well pairs

• Drilling improvements

• Inflow/outflow control devices

• Improved start-up techniques

• Quicker start-up

• Better conformance and faster recovery

• Fewer Wedge Wells™ required

Technology driven field improvements

Results in

0

500

1,000

1,500

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2,500

3,000

3,500

1 31 61 91 121 151 181 211 241Day

Average 1,400m well Average 965m well

Christina Lake H09 pad – 6 well pairs at 1,600m

H-09 p

• Improved conformance allows us to drill longer wells andcapture a larger drainage area

• fewer wells and surface facilities (~25% reduction)

• reduces environmental footprint

Longer horizontal wells drive efficiencies

Well results from 1,400m wellsbbls/d per well

Improved conformance allows longer horizontal wells

Note: Well results show average of two 1,400m wells compared to two 965m wells.

17

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2.0

3.0

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5.0

2014 2015 2016/Current

• Improved programs and procedures drive efficiencies

• ~40% improvement in drilling time

• reduced completions time by ~30%

• Despite increased well lengths, efficiency gains drivingabsolute costs lower

• ~20% improvement in cost per meter since 2014

• Expect to leverage increased size and scale to driveimproved contracting and procurement

• Overall reduction of > 25% in drilling and completioncosts per well pair

Manufacturing approach drives efficiency gains Drilling and completions costs per well pairDrilling and completion costs per well pair($ millions)

Drilling and completion cost reductions

850m 1,200mAverage horizontal well length

Redesigned well pads drive cost improvementsImprovements provide sustainable reduction in F&D Transaction is fully financedRedesigned well pad at Christina Lake

• Improved modular and scalable design for well pairs andpads

• Materially reduces costs while maintaining safety,compliance, and production

• Scope reduction drives 35% – 50% cost savings

• 40% – 60% material reduction

• 15% – 20% well pad surface footprint reduction

• Reduces engineering and construction time

• 30% reduction in field construction time

• 70% reduction in field executed scope

• 65% reduction in man hours

18

Foster Creek estimated capital savings of $500 millionAfter:• 8 pads• 66 wells• ~$600 million• 220 MMbbl recoverable

Before:• 18 pads• 120 wells• ~$1.1 billion• 200 MMbbl recoverable

Christina Lake estimated capital savings of $800 millionBefore:• 19 pads• 213 wells• ~$1.6 billion• 310 MMbbl recoverable

After:• 13 pads• 105 wells• ~$800 million• 310 MMbbl recoverable

19

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$15

2014 2015 2016 2017F 2018F 2019F 2020F 2021F

Focused innovation reduces sustaining capital

• Targeting oil sands sustaining capital of $5/bbl

• already reduced sustaining capital per barrel bymore than 50% since 2014

• Leveraging technology to drive incremental margin

• superior wellbore conformance

• longer wells

• fewer wells and pad facilities

• lower cost design and greater executionefficiency

Targeting a further $2/bbl reduction in 5 yearsStructural changes reduce oil sands sustaining costsOil sands sustaining capital costs($/bbl)

Target $5/bbl

Note: See Advisory.

Christina Lake operating costs Foster Creek operating costs

Unit operating costs down over 30% from 2014

Note: 2017F based on midpoint of June 20, 2017 guidance.

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2014 2015 2016 2017F

Fuel Non-fuel

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2014 2015 2016 2017F

Fuel Non-fuel$/bbl$/bbl

• Non-fuel operating costs down 36% since 2014

• Driven by optimizing repairs and maintenance, reducedworkover costs, and increased productivity and uptime

• Non-fuel operating costs down 32% since 2014

• Driven by downhole improvements, reductions in wellservicing and pump replacement costs, and increasedproductivity and uptime

20

Aligning our workforce to support disciplined growth

• Organizational design improvements

• shift to functional organization

• reduced headcount to align with measured pace ofdevelopment

• non-essential roles moved off site

• Optimized field shifts to improve efficiency and reducecosts

• leadership continuity, reduced overtime

• Logistics efficiency

• centralized flight hubs, standardized schedules

• Increased productivity and run time

Leveraging our best-in-class people to drive value

Focused on safety and optimizing maintenance

• Targeted approach to ongoing maintenance

• maximizing production throughput with prioritizedmaintenance

• Leveraging integrated facilities to mitigate impacts ofplanned maintenance

• Improved cost, quality, and schedule through alignedleadership accountabilities

• Reduced annual maintenance spending per barrel byover 60% since 2014

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2014 2015 2016 2017

Annual maintenance spend ($/bbl)

Turnaround

Cenovus oil sands maintenance spendMaintenance prioritization generates value

Turnaround

Turnaround

21

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$1.00

2014 2015 2016 2017F

Workover costs trending lower

• Focus on optimizing workover program, whilemaximizing operability and performance

• Innovative technology drives workover efficiencies

• improved electric submersible pump (ESP) run lifeand performance

• new wellbore designs (liner design) that reduceoverall life cycle costs

• downhole instrumentation for well monitoring

• Reduced annual workover costs by more than 50% perbarrel since 2014

Christina Lake workover operating expensesFocused innovation enables workover optimizationAnnual workover operating costs($/bbl)

$0.00

$2.50

$5.00

$7.50

$10.00

$12.50

$15.00

2010 2011 2012 2013 2014 2015 2016 2017F

0

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200,000

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400,000

2010 2011 2012 2013 2014 2015 2016 2017F

0.65

0.39

0.46

0.37

0.28

0.2

0.15

2014 2015 2016 2017 2018 2019 2020

Total recordable injury frequency (TRIF)

Past performance Current performance Future targets

Leading safety performance while growing the business

Best North American

peer performance

(2016)

Best Canadian

peer performance

(2016)

Excellence in safety leads to excellence in business

Oil sands production (bbls/d)

Oil sands opex ($/bbl)

Q1 2017 F F F

Our Goal:

2010-2016 production is 100% gross FCCL, 2017F assumes acquisition closed January 1, 2017.

22

Improvement drives sustainable reductions

Redesigned well pads

Lower F&D• Improved modular & scalable

design• Scope reduction reduces costs• Reduced well pad footprint

Improved well design

• Quicker start-up• Better conformance and faster

recovery• Fewer wells required

Improved conformance

• Better conformance along thefull horizontal well length

• Lower SOR• Higher oil rates per well

Longer horizontal wells

• Capture a larger drainage area• Fewer wells to recover the same

resource• Fewer surface facilities

Advancing attractive organic growth opportunitiesHarbir Chhina

Executive Vice-President & Chief Technology Officer


23

Christina Lake Phase G demonstrates cost efficiency

Note: After-tax IRR based on go-forward spending and flat US$55/bbl WTI. See Advisory.

Christina Lake phase G project profile

0

10

20

30

40

50

60

2017F 2018F 2019F 2020F 2021F 2022F

30%

45%

20% 5% 0 0$0

$100

$200

$300

$400

$500

2017F 2018F 2019F 2020F 2021F 2022F

Christina Lake phase G capital profile($ millions)

Christina Lake phase G production profile(Mbbls/d)

Key statisticsUnits Statistic

Project oil capacity Mbbls/d 50Steam-oil ratio x 1.8 – 2.2

Capital spent to date $ millions $250

Capital remaining to completion $ millions $800 – $900

Construction resumed date H2 2017

First oil date from resuming construction months 24 – 30

Go-forward capital efficiency $k/bbl/d $16 – $18

After-tax IRR % > 30%

Best-in-class oil sands project

• Industry-leading steam-oil ratio of 1.7

• Strong capital efficiencies

• leveraging pre-installed infrastructure

• Construction is on track for first oil in H2 2019

• 50% reduction in capital efficiency from phase F

Foster Creek phase H on track to be sanction ready


Illustrative Foster Creek phase H project profile

0

10

20

30

40

50

Year 1 Year 2 Year 3 Year 4 Year 5 Year 6

5%

40% 40%

15%$0

$100

$200

$300

$400

$500


Foster Creek phase H capital profile($ millions)

Foster Creek phase H production profile(Mbbls/d)




Capital remaining to completion $ millions $800 – $900

Construction to resume date TBD




Benefiting from pre-build on phases F&G

• Plan to complete the remaining plant construction anddrilling of initial well pairs and pads

• Improved reservoir characterization and facility redesignnow supports 40,000 bbls/d capacity

• up ~30% from 30,000 bbls/d

24

Planning to commercialize solvents at Narrows Lake


Illustrative Narrows Lake phase A project profile

0

25

50

75


25%30%

25%

15% 5%

$0

$200

$400

$600

$800


Narrows Lake phase A capital profile($ millions)

Narrows Lake phase A production profile(Mbbls/d)




Capital remaining to completion $ millions $1,600 – $1,900

Construction to resume date TBD




Improving greenfield development at Narrows Lake

• Plant construction approximately ~25% complete

• Production of 65,000 bbls/d based on SAP; up ~40%

• faster implementation of solvents

• now includes 85 MW cogeneration

• Design flexibility for different solvents

Consolidation of oil sands unveils additional valueGreater Foster Creek regionGreater Christina Lake region

• Project approval could be submitted in ~12 months

• Directly adjacent to Devon Jackfish 2 project

• producing ~45 mbbls/d with an SOR of ~2.0

• Located northwest of 100% owned Foster Creek project

• Adjacent to CNRL Kirby South project

• producing ~40 mbbls/d with an SOR of ~2.6

Jackfish 2DVN WI 100%

Kirby West CVE WI 100%

Kirby South CNRL 100%

East IpiatikCVE WI 60%

West IpiatikCVE WI 100%

Foster CreekCVE WI 100%

25

Technology development focused on cost and carbon leadership

20

25

30

35

40

45

50

55

60

65

2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F

Base case emissions intensity

Full impementation of solvent & cogeneration

Technology enables cost and carbon competitiveness

• Direct GHG emissions intensity is:

• down > 30% since 2004

• 45% below industry average

• Improved emissions performance an outcome of topquartile SOR and technology such as:

• Wedge Well™ technology

• accelerated start-up

• improved steam quality and reducing heatexchanger fouling

• electric submersible pumps

• Well positioned under the new Alberta Climate LeadershipPlan

• Solvents are expected to help further reduce our GHGemissions

Targeting additional 33% reduction in GHG emissionsTechnology mandate helps reduce cost and carbonDirect oil sands GHG emissions intensity(Kg CO2e/bbl)

Target: 36 Kg CO2e/bbl

Note: 2015 CAPP RCE national data table for 2014 operating year.

26

Technology drives further improvement in valueCommercialized

• Blowdown boilers• ESP’s• Flow control devices• New liner design• Skystrat™ drilling rig• Wedge Well™ technology

1 – 3 years 3 – 5 years

• Implementation of solvent on a padscale

• Central plant equipment redesign

• Solvent process <1000C

• Warm lime softener elimination

• Further improvements on ESP’s &flow control devices

• Reduction in chemical use

• Subsurface imaging tool

• Downhole pumping systems• Digital and big data analytics

5 – 10 years

• Partial upgrading

• Full field solvent commercialization

• Reduced field equipment


• Advanced solvents

• Clean energy

• Commercialize solvents <1000C

Date here 30

• Superior start-up and steam circulation methods

• Advanced sub-surface equipment and design

• High pressure ramp up

30

2011Realized benefits

Future advancements

Enhancing existing technologies

• Controlling ICD’s/OCD’sfrom surface without workovers

• >60% of Foster Creekproduction on precisionpunched screen (PPS)liners

• Workover cost reductions

Adjustable steam distributor

New precision punched screen linerPrevious slotted liner

27

Path to solvent commercialization

Senlac butane test

Christina Lake A01 butane test

Q3 2017

2018

Foster Creek N-pad lean propane SAP

Foster Creek W06 propane solvent driven process

Q3 2017

Foster Creek butane solvent driven process

2018-2019

TBD

Commercializing solvents at a pad level

Narrows Lake full field implementation

Christina Lake A02 butane test

2001

2004

2009-2017

TBDFoster Creek & Christina Lake field conversion to SAP

• Christina A02 butane pilotdemonstrated 30% SORreduction and 70%+recovery of solvent

• Senlac butane pilot demonstrated50% improvement in oil rate and70%+ recovery of solvent

Solvents create value and reduce emissions intensity

• Decreases SOR by ~30% - 35%

• Increases individual well productionrates up to 10%

• Increases growth capital 15 - 20%

• Decreases sustaining capital by10 - 30%

• Reduces non-fuel operating costs byup to 20%

• Solvents have the potential toachieve up to 80% of our targeted33% GHG reduction

SAP Benefits of solvents SAGD

28

Implementation of solvents is a priorityIllustrative deployment of solvents

0

5

10

15

20

Year 1 Year 2 Year 3 Year 4 Year 5

0

10

20

30

40

50

60

Year 1 Year 2 Year 3 Year 4 Year 5

Illustrative wells on solvent(Cumulative well pairs)

Illustrative solvent project production profile(Mbbls/d)

Moving to next phase of solvent commercialization

• Planning solvent injection on existing pads at both FosterCreek and Christina Lake

• staged implementation strategy allows fordisciplined development

• SAP commercial demonstration has the potential toaverage 15,000 bbls/d by 2021 on existing wells

• potential to increase annual operating margin by~$100 million at 15,000 bbls/d

• Ultimate production potential of up to 200,000 bbls/d,including Narrows Lake

Note: Illustrative production from solvent aided process. See Advisory.

Partial upgrading improves product qualityBitumen blending process

Upgrading technology

1.0 bbl of Bitumen

0.4 bbl of Diluent

Pipeline specs:19o API, 350 cs

1.4 bbl of blend

• Improving oil sands economics through diluent reductionand product quality enhancements

• blend ratio ~ 30% diluent

• diluent costs > $2.0 billion per year

• Pipeline specifications require 19o API and 350 cs viscosity

• further requirement of over blending on density tomeet viscosity specs

Partial upgrading reduces transport & blending costs

29

Nozzles

De-risking partial upgrading at commercial scaleProcess flow diagram for partial upgrading opportunitiesOngoing field testing to validate results

• Pilot project capacity of 1,000 bbls/d operating since 2014

• Field tested both Foster Creek and Christina Lake crudes

• Pressurized to 3,000 psig and heated to 400°C

• Rapid depressurization, inducing cavitation

• Hydrotreating required to eliminate olefins

Note: See Advisory.Existing 1,000 bbls/ddemonstration facility

Maximizing value and increasing marginPotential partial upgrading benefitsSAGD process with partial upgrading

• Improves market access, product value, and reducespipeline requirements

• Reduce diluent required by 45 – 50%

• results in cost savings $3 – $5/bbl

• Reduce transportation volumes by ~15%

• results in increased available capacity

• Reduce TAN to 0.5

• results in improved product value up to $2/bbl

• Olefin free material

Units Statistic

Project oil throughput Mbbls/d 100

Capital efficiency $k/bbl/d $8 – $12

Construction to first oil years 4 – 5

Light/heavy differential assumption US$/bbl $15 – $25

Estimated margin enhancement $/bbl $3 – $5

Estimated annual operating margin $ millions $100 – $170


Note: See Advisory.

30

• Big data analytics – identifying efficiencies in ourdownhole and surface operations

• better capital planning

• decrease facility variability and increase uptime/throughput

• Shallow analytics – increasing data accessibility tomultiple data sources

• increase workforce efficiency, less time spentaccessing data

• Self-navigating robots and scanning devices

• increases execution efficiency and improvescapital efficiency A robot takes precise measurements of

modules to ensure alignment before deployment to the field.

Emerging digital technologies improve operationsMultiple opportunities for low-cost, high-return optimization

Oil sands drives free funds flow

Demonstrating strong operating performance and free funds flow

Achieving structural cost & value improvements

Advancing attractive organic growth opportunities

Technology development focused on cost & carbon leadership

31

Supplemental

Telephone Lake represents material opportunity

• Cenovus has 100% working interest

• Regulatory approval for 90,000 bbls/d received in 2014(phases A & B)

• Expected ultimate production capacity of 300,000+ bbls/d

• Excellent reservoir quality

• expected project SOR 2.2

• will contribute to strategic goal of reducing futureemissions intensity

• Closest geological analogue is adjacent Suncor Firebagproject

Telephone Lake project Location

32

Realizing the benefits of integration

Bob Pease

Executive Vice-President, Strategic Planning & President, Downstream


Flexible solutions key to integration

IntegrationSolvents

Marine

Supply chain integration

Diluent reduction

Partial upgradingCogeneration

Oil sands production

Bruderheimterminal

Refining capacity

Natural gas processing

Natural gas production

Natural gas consumption

Storage & blending

Transportation commitments

33

Takeaway capacity provides certainty

• Cenovus has no near term takeaway capacity issues

• West Coast: Trans Mountain

• US Gulf Coast: Enbridge USGC/Flanagan South

• Bruderheim rail facility provides incrementaloptionality

• Supporting pipeline expansions to secure future marketaccess

• US Gulf Coast: Keystone XL

• West Coast: Trans Mountain Expansion

• East Coast: Energy East

• Keeping firm commitments to a level that leaves capacityfor optimization

• Supplementing firm capacity with active blending,storage, sourcing, and destination optimization

Optimizing takeaway capacity to provide flexibility Sufficient near term takeaway capacity

PADD VPADD IV

PADD III

PADD I

Alberta

Borger Refinery

Wood River Refinery

PADD II

Hardisty

MontrealSaint John

Houston

Cushing

Chicago

Pipeline expansionProposed pipeline

Edmonton

Patoka

Vancouver

Current pipelines

• Long-term and low-cost optionality

• Easy to expand quickly with minimal capital

• Ability to move wider variety of crudes

• Development optionality expected to generate additionalvalue

• midstream value-add (blending, storage,transloading)

• cavern capacity

• partial upgrading

• cogeneration

• support for solvent strategy

Bruderheim provides strategic optionality Improving margin through development opportunities Strategic location provides optionality

MEG upgrading

pilot

Manifest operations

area

Unit train

operation

Rail lines

Bruderheim Energy TerminalPipeline

Caverns

34

Marine capability provides international access

• Actively engaged in various market access projects togain access to global pricing

• Calgary and Houston offices capable of contracting vesselsto move petroleum products to international markets

• Access to variety of ships provides flexibility in destinationand cost

• Panamax to VLCC (350,000 – 2,000,000 bbls)

• Positioned to take advantage of Trans Mountain Expansionand deliver large volumes to growing internationalmarkets

• Provides competitive route to heavy crude demandin the USGC

Low-cost optionality to global pricing

PADD V PADD IV

PADD III

PADD I

Alberta

Borger Refinery

Wood River Refinery

PADD II

HardistyEdmonton

Marine provides flexible transport option to key markets

Refining capacity mitigates heavy oil differentials

• Refining assets help to mitigate exposure to widerlight/heavy differentials

• Approximately 25% of total blended heavy oil volumes aremitigated with processing capacity

• Wood River capable of processing220,000 gross bbls/d of heavy

• Borger capable of processing35,000 gross bbls/d of heavy

• Transportation options provide further mitigation fromwider light/heavy differentials

Percentage of total operating margin

WTI-WCS differential (US$/bbl)

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009 2010 2011 2012 2013 2014 2015 2016

Downstream Upstream WCS differential (US$/bbl)

Refinery complexity drives margins Integration through the cycle

35

Benefiting from refinery location & processing capacity

$0

$200

$400

$600

2017F 2018F 2019F 2020F 2021F


• Refineries have access to wide range of advantaged crudes

• Wood River accesses multiple pipelines – Keystone,Express-Platte, Mustang, Ozark

• Borger has access to Canadian heavy, West TexasSour, and growing Permian supply

• Minimal downstream annual maintenance capital of$150 – $200 million annually

• Downstream operations have generated ~$2.5 billion infree funds flow since 2009

• Provides solid financial hedge when heavy crudes arediscounted

Downstream capital expenditures and operating margin($ millions)

Downstream continues to deliver free funds flowHeavy oil integration through processing capacity

Note: Assumes US$50/bbl in 2017 and flat US$55/bbl WTI thereafter. See Advisory.

Expanding margin across the value chain

Upstream

Midstream

Downstream

• Two growth platforms

• Deep Basin volumes provideeconomic hedge for naturalgas consumption and potentialfor solvent use in the oil sands

• Cogeneration


• Diluent reduction

• Highly flexible, upgradable rail

• High optionality, low-costmarine

• Pipeline certainty withblending, storage, and sourcing& destination options

• Optimize natural gas processingcapacity in the Deep Basin

• Active trading and exposuremanagement

• High-conversion refining

• Cogeneration


• Diluent reduction

margin uplift

margin uplift

36

Maximizing margin through integration

Create low-cost optionality to address market uncertainties

Mitigate our exposure to light-heavy differentials

Focus on margin improvement across the value chain

Generate free funds flow through the cycle

37

Deep Basin poised for growth

Drew ZieglgansbergerExecutive Vice-President, Deep Basin

Trevor CossariniVice-President, Development & Portfolio Management


Deep Basin provides second growth platform

Overview of Deep Basin

• One of the largest Deep Basin land positions

• Three core operating areas: Elmworth-Wapiti,Kaybob-Edson, and Clearwater

• Low decline production base coupled withsignificant liquids-rich development upside

• Deep inventory of short-cycle, high IRRpotential drilling opportunities in areas thatattract capital from offsetting operators

• Assets have been capital constrained

• 1.4 BCF/d of net natural gas processingcapacity; majority owned and operated

Deep Basin summary statistics

• Q4 2017F production: 120,000 BOE/d(26% liquids; 17% decline rate)

• Total net acres: ~3.0 million

• Proved + probable + future drillingopportunities: ~ 1,500

• 2P reserves: 725 MMBOE (62% proved)

Note: See Advisory.

38

Introductions

Trevor CossariniVP, Development & Portfolio

Management

20+ years of experience in Deep Basin with

ConocoPhillips, Chevron, Talisman, Burlington

Dean PerkinsDirector, Operations


ConocoPhillips, Kvaerner, Colt, Burlington

Terry WorbetsVP, Exploration & Subsurface


ConocoPhillips, Dome, Forest, Mark, Stampeder, CanHunter, Burlington

Drew ZieglgansbergerEVP, Deep Basin

20+ years of experience with

Cenovus, Encana, AEC

No near-term takeaway constraintsAsset overview Deep Basin infrastructure map

• ~1.4 BCF/d of net natural gas processing capacity and significantassociated gathering infrastructure

• Infrastructure footprint spans the Deep Basin

• Ownership and control underpins operational flexibility

• Excess processing capacity supports near-term development


Operated assets # 17Avg. working interest of operated facilities % 77Total net processing capacity MMcf/d ~1,400

Key operated facilitiesFacility Units StatisticElmworth 01-08-70-11W6 Net MMcf/d 395Noel B-059-D/093-9-08 Net MMcf/d 150Peco 6-19-73-08W6 Net MMcf/d 69

39

Deep Basin takeaway capacity and marketingPotential for growth and synergies with oil sands Current firm receipt capacity exceeds production levels

• Current firm receipt capacity exceeds forecast productionlevels

• sufficient transportation through 2019 viacommitted capacity and system efficiencies

• reviewing risked scenarios to help ensureadequate needs 2020 and beyond

• Demand opportunities:

• access to multiple natural gas export routes

• coal fired power plant conversions and retirements

• oil sands expansion

• Synergies with our oil sands business:

• natural gas liquids use and solvent aided process

Total Deep Basin firm transportation(MMcf/d)

0

250

500

750

1,000

1,250

2017F 2018F 2019F 2020F 2021F

Firm transport Deep Basin natural gas

Note: See Advisory.

Low decline, liquids rich production2017F production 2017F decline rate

Source: Peters & Co. E&P Overview Tables report dated May 29, 2017, company disclosures. See Advisory.

0

50

100

150

200

250

300

TOU VII CVE PEY

MBOE/d

• 17% decline rate is a competitive advantage• Reduces sustaining capital requirements• Declines expected to increase moderately with

activity through 2021F

• Beginning with a 3 rig program in 2017• Q4 2017F average production of 120,000 BOE/d• 2021F production doubles to 240,000 BOE/d• Represents 15% production CAGR

0%

10%

20%

30%

40%

50%

CVE TOU PEY VII

%

2017F percent oil & liquids

• Oil & liquids content drive economics• 40-45% of liquids production is crude oil and

condensate• Opportunities for synergies with oil sands

0%

25%

50%

75%

PEY TOU CVE VII

%CVE represents Q4 2017F average production

40

Future upside potential across acreageNet acreage Drilling opportunities / 1,000 acres

0

500

1,000

1,500

2,000

2,500

3,000

3,500

CVE TOU VII PEY

MM net acres

• Only ~430 locations are currently booked• Undercapitalized acreage base• Future upside potential from development activity

• Expansive land base across the Deep Basin• Opportunities to high grade acreage position

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

CVE PEY TOU VII

Drilling opportunities / 1,000 net acres

Pro forma 2P reserves

• Reserves evaluated by GLJ• 725 MMBOE of 2P reserves (62% proved)

0

500

1,000

1,500

2,000

TOU VII CVE PEY

MMBOE

Source: Peters & Co. E&P Overview Tables report dated May 29, 2017, company disclosures. 2P reserves evaluated by GLJ as of March 22, 2017. See Advisory.

Opportunity to reduce costsNet processing capacity

Note:

0

250

500

750

1,000

1,250

1,500

TOU CVE PEY VII

MMcf/d

• Owned and operated infrastructure is acompetitive advantage

• Plan to optimize underutilized processing capacity• Evaluating strategic infrastructure alternatives for

key development areas to support future growth

Q1 2017 operating netback

• Operating cost improvements drive margins• Liquids content increases realizations• Expect to see margin improvement as activity

ramps up and costs are driven lower

N/A$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

VII PEY TOU CVE

$/BOE

Q1 2017 operating costs

• Near-term focus on reducing operating costs• Opportunities to leverage existing underutilized

infrastructure

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

PEY TOU VII CVE

$/BOE


CVE represents the midpoint of revised 2017F guidance

CVE information not available for Q1 2017 as

transaction closed on May 17

41

Disciplined approach to investmentEstimated 2017F drilling plans 2017F capital expenditures

0

50

100

150

200

250

300

350

CVE VII PEY TOU

Estimated net operated wells

• Taking a disciplined approach• Capital expenditures to increase through 2021F• Additional infrastructure capital required

in 2020-2021F

• Plans to drill ~30 wells in 2017F • Development focused on Montney, Falher,

Wilrich, and Spirit River formations

$0

$500

$1,000

$1,500

$2,000

CVE PEY TOU VII

$ millions

Net wells drilled since 2014

• Relatively low activity levels since 2014• Expect to ramp up to ~110 wells per year

in 2019-2021F

0

150

300

450

600

CVE VII PEY TOU

Net wells


Over a decade of future drilling opportunities~1,500 potential drilling opportunities identified

Targeted type well

information by key areaIP365

(boe/d)Well costs

($MM,DC&T)Gas (%)

IRR (%)

NPV 10% before-tax

($MM)Payout (years)

F&D ($/boe)

Recycle ratio (x)

1 year capital efficiency

($k/flowing)

Pipestone Montney type well 760 6.3 55 >100 14.8 1.25 4.20 5.4 8.3

Wapiti Falher type well 705 4.8 86 65 5.7 1.75 4.05 4.0 6.8

Kakwa Falher type well 860 5.9 84 >100 8.3 1.50 6.00 3.3 6.9

Edson Wilrich type well 740 5.6 87 70 7.9 1.50 4.40 3.9 7.6

Clearwater Spirit River type well 835 4.7 72 >100 9.0 1.25 4.00 4.2 5.6

Targeted type well information by key development area

• High quality technical staff with execution experience

• Initial development focused on the Spirit River andMontney formations

• Attractive half-cycle development economics supportedby majority owned and operated infrastructure

Focused on the Spirit River and Montney formations

0

200

400

600

800

Spirit River Montney Other Targets

Internal Cenovus estimates

Probable

Proved

Future drilling opportunities by targeted formation

Note: See Advisory for key underlying assumptions and risks and a description of the metrics provided above.

42

Upside potential from stacked payUpside potential from stacked pay Target formations

Formation Elmworth Wapiti Kaybob Edson Clearwater TotalsCardium 164,813 224,221 341,855 259,195 990,085

Dunvegan 882,906 189,718 232,261 1,304,886

Spirit River 788,454 193,371 221,836 358,701 415,993 1,978,354

Glauconite 372,461 465,493 837,954

Cadomin 547,374 130,362 16,482 694,218

Nikanassin 63,343 63,343

Rock Creek 270,821 334,522 605,343

Montney 108,969 62,554 171,523

Note: Formation rights (net acres) by area. Spirit River formation includes the Notikewin, Falher, and Wilrich.

Focus on high quality and low risk locationsInitial drilling plans through March 2018 focused on development and appraisal

2017 - 2018 drilling June July August September October November December January February March

Elmworth / Wapiti

Pipestone Montney 5 wells

Wapiti Falher 5 wells

Wapiti Falher 4 wells

Kaybob / Edson

Kakwa Falher 7 wells

Kakwa Falher 4 wells

Kaybob Wilrich 6 wells

Kaybob Montney 2 wells

Edson Wilrich/Notikewin 9 wells

ClearwaterClearwater Spirit River 10 wells

Clearwater Spirit River 4 wells

43

Maximizing value in the Deep Basin

• Expect to run a three rig program in 2017 and rampingup thereafter

• self funded growth from 120,000 BOE/d toapproximately 240,000 BOE/d in 2021F

• represents a 15% production CAGR

• Capital can be increased or decreased depending oncommodity price environment

• leverage net processing capacity to drive growth

• three year infrastructure budget of $250-$300million to maximize throughput and optimizedevelopment

Taking a disciplined approach to development Internally funded growth potential

0

50

100

150

200

250

2017F 2018F 2019F 2020F 2021F

Net wells Production

$0

$500

$1,000

$1,500

2017F 2018F 2019F 2020F 2021F


Deep Basin capital expenditures and operating margin($ millions)

Deep Basin net wells drilled and production(Net wells; MBOE/d)

Note: Production growth assumes favorable drilling results and actual number of wells drilled within estimates provided. See Advisory.

Applying our experience to the Deep Basin

> 500 horizontal SAGD well pairs currently

producing over360,000 bbls/d

Reductions since 2014:~50% sustaining capital ~30% operating costs

> 300 operated horizontal wells drilled in the Deep Basin since

2012

Applying a manufacturing approach to development

Cost leadership Short-cycle executionAdvancing technology

44

Second growth platform repositions Cenovus

Top-tier assets and people

Self-funded doubling of production in five years

Manufacturing approach drives execution and delivers free funds flow

Short-cycle, low-decline production provides capital flexibility and competitive advantage

Detailed asset overviews

45

Restarting an execution machineProven ability to execute substantial drilling programs

0

25

50

75

100

125

2012 2013 2014 2015 2016 2017F 2018F 2019F 2020F 2021F

Previous operator hz wells CVE planned hz wells

Horizontal wells drilled(#)

Continued to streamline the portfolio

• Team has experience managing high activity levels despitereduced capital spending in 2015 – 2017

• 2015 – 2017 focus was on:

• streamlining organization and portfolio

• technical work to enable better assetunderstanding

• benchmarking industry activity

• development planning

• ~80 inventory locations being readied for potentialexecution in 2017 and 2018

Note: See Advisory.

0

1,000

2,000

3,000

4,000

5,000

6,0000 5 10 15 20 25 30 35 40 45

Demonstrated excellence in drillingPipestone Montney drilling performanceKakwa Falher drilling performance

Drilling days

Drilling depth(m)

2013 avg.

2014 avg.

2015 avg.

2016 well

Peer wellPeer well

0

1,000

2,000

3,000

4,000

5,000

6,0000 5 10 15 20 25 30 35 40 45 50

Drilling days

Drilling depth(m)

2013 avg.

2014 avg.

2015 avg.

2016 well

Peer well Peer well

Peer well

Striving for continuous improvement Striving for continuous improvement

46

Elmworthasset overview

Elmworth asset overviewElmworth asset overview Elmworth area asset map

• Active operators include Tourmaline, ARC, Encana, Shell,and Crew with ~90% of wells targeting the Montney

• Low base decline rate of ~10%

• Strong operated infrastructure position at Elmworth, Noel,and Wembley

• 2017/2018 capital program focused on Pipestone Montneyopportunity


Net acres acres ~900,000Proved + probable + future drilling opportunities # ~175

Total net processing capacity MMcf/d ~640

Q4 2017F production BOE/d 32,000% oil / liquids % 232017F capex $ millions 30

Note: See Advisory.

47

Pipestone Montney development opportunityPipestone Montney development plans Pipestone Montney acreage position

• ~25k gross acres with ~95% working interest

• thick 200m Montney interval with stack potential

• initial liquids yields range from120 – 230 bbls/MMcf

• 24 wells drilled by previous operator to date

• ~10 wells expected to be drilled over the next 18months

• identified > 100 potential drilling opportunities

• 2017/2018 capital program focused on informing anoptimized development scenario

• testing stacking and spacing

• completions

• choosing a preferred infrastructure option

Wapiti asset overview

48

Wapiti asset overviewWapiti asset overview Wapiti area asset map

• Active operators include NuVista, Shell, Modern, andParamount with ~70% of wells targeting the Montney

• Low base decline rate of ~14%

• 25% working interest ownership in CNRL Wapiti complex

• 2017/2018 capital program focused on Wapiti Falheropportunity





Note: See Advisory.

Wapiti Falher development opportunityWapiti Falher development plans Wapiti Falher development plans

• Tight gas sand play with attractive economics

• continuation of the Falher trends northwest ofestablished development in Kakwa

• ~400,000 gross acres with ~60% working interest acrossthe Wapiti area

• ~30 existing Falher horizontal wells by industry


• ~12 wells expected to be drilled over the next18 months

• identified ~100 potential drilling opportunities

• potential to expand inventory with additionalappraisal

• Assessing infrastructure solutions

49

Kaybobasset overview

Kaybob asset overviewKaybob asset overview Kaybob area asset map

• Industry activity dominated by Seven Generations andTourmaline who are focused on the Montney andFalher/Wilrich

• Active development area with ~22% decline rate

• Infrastructure position supports near-term development

• 2017/2018 capital program focused on Kakwa Falheropportunity





Note: See Advisory.

50

Kakwa Falher development opportunityKakwa Falher development plans Kakwa Falher development plans

• One of the most economic plays in Western Canada

• stacked shoreface and fluvial channel play

• ~78,000 gross acres with ~65% working interest



• demonstrated consistent execution performance

• identified ~100 – 200 potential drillingopportunities

• Opportunity to reduce costs with continuous activity

• Firm processing capacity supports long-term developmentplans

Edsonasset overview

51

Edson asset overviewEdson asset overview Edson area asset map

• Spirit River (Notikewin, Falher, Wilrich) dominate theactivity with ~800 wells drilled in the past three years

• Development focused at Peco/Wolf with ~19% decline rate

• Strong operated infrastructure position at Peco, Wolf, andNiton

• 2017/2018 capital program focused on Peco/WolfNotikewin opportunity





Note: See Advisory.

Edson Wilrich development opportunityEdson Wilrich development plans Edson Peco-Wolf development plans

• Emerging top quartile play in the Deep Basin

• ~150,000 net acres, majority of which is 100%working interest

• Planning first operated well in Q3 2017


• identified > 100 potential drilling opportunities

• Significant offset horizontal production in Wolf

• Favorable infrastructure position reduces operating costs

• over-pressured gas with 20 – 40 bbls/MMcf liquidscontent

• additional infrastructure will be required to fullydevelop inventory

52

Clearwater asset overview

Clearwater asset overviewClearwater asset overview Clearwater area asset map

• ~500 industry wells drilled since 2015 focused in the SpiritRiver (Falher, Wilrich, Notikewin) and Cardium

• Limited drilling activity since 2014 with ~17% decline rate

• Infrastructure position supports current productionvolumes

• 2017/2018 capital program focused on Spirit Riveropportunity





Note: See Advisory.

53

Clearwater Spirit River development opportunityClearwater Spirit River development plans Clearwater Spirit River development plans

• Proven top quartile play in the Deep Basin with highindustry activity levels

• significant liquids potential of 40 – 100 bbls/MMcf

• ~170,000 net acres with ~75% average workinginterest

• Testing known concepts with analog data and well controlto expand our inventory

• ~40 wells drilled by previous operator to date


• identified ~200 potential drilling opportunities

• Owned and operated infrastructure provides a costadvantage

• require an infrastructure solution for Nordegg area

Second growth platform repositions Cenovus

Top-tier assets and people

Self-funded doubling of production in five years

Manufacturing approach drives execution and delivers free funds flow

Short-cycle, low-decline production provides capital flexibility and competitive advantage

54

Supplemental

Elmworth area overviewElmworth area overview Elmworth area industry activity

55

Wapiti area overviewWapiti area industry activityWapiti area overview

Kaybob area overviewKaybob area industry activityKaybob area overview

56

Edson area overviewEdson area industry activityEdson area overview

Clearwater area overviewClearwater west area industry activityClearwater area overview

57

Closing remarks: Achieving our potential

Brian Ferguson

President & Chief Executive Officer


$1B of capital, operating, and G&A savings

in 3 years

Annualized free funds flow

growth of 14%

Targeting net debt to adjusted EBITDA < 2.0x in

2019

Disciplined annual

production growth of 6%

Corporate breakeven of < US$40/bbl

WTI

Increasing returns to

shareholders

Note: See advisories regarding forward-looking information and non-GAAP measures. Figures refer to the 2018F-2021F time period.


58

AdvisoryOil and Gas InformationThe estimates of reserves and resources data and related information were prepared effective December 31, 2016 by independent qualified reserves evaluators (“IQREs”), based on the Canadian Oil and Gas EvaluationHandbook (the “COGE Handbook”) and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

Barrels of Oil EquivalentNatural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf isbased on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oilcompared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

Resources InformationBest estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the bestestimate. Those resources that fall within the best estimate have a 50% probability that the actual quantities recovered will equal or exceed the estimate. Contingent resources are those quantities of bitumen estimated,as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due toone or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources theestimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates andmay be sub-classified based on project maturity and/or characterized by their economic status. The McDaniel estimates of contingent resources have not been adjusted for risk based on the chance of development. Thereis uncertainty that it will be commercially viable to produce any portion of the contingent resources.

Economic contingent resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. Economic contingent resources are estimated usingvolumetric calculations of the in-place quantities, combined with performance from analog reservoirs. Existing SAGD projects that are producing from the McMurray-Wabiskaw formations are used as performance analogsat Foster Creek and Christina Lake. Other regional analogs are used for contingent resources estimation in the Cretaceous Grand Rapids formation at the Grand Rapids property in the Greater Pelican region, in theMcMurray formation at the Telephone Lake property in the Borealis region and in the Clearwater formation in the Foster Creek region.

Contingencies which must be overcome to enable the reclassification of contingent resources as reserves can be categorized as economic, non-technical and technical. The COGE Handbook identifies non-technicalcontingencies as legal, environmental, political and regulatory matters or a lack of markets. Technical contingencies include available infrastructure and project justification. The outstanding contingencies applicable to ourdisclosed economic contingent resources do not include economic contingencies. Our bitumen contingent resources are located in four general regions: Foster Creek, Christina Lake, Borealis and Greater Pelican.

Further information with respect to contingent resources including project descriptions, significant factors relevant to the resource estimates, and contingencies which prevent the classification of contingent resources asreserves is contained in our supplemental Statement of Contingent and Prospective Resources for the year ended December 31, 2016, which is available on SEDAR at sedar.com and the company’s website atcenovus.com.

Definitions and Industry Terminology"Decline rate" is defined as the rate at which proved developed producing reserves are expected to naturally decline according to the evaluation by our independent qualified reserves evaluator.

"F&D" is defined as expected initial well costs divided by forecasted average recovery based on type curve analysis. F&D does not have any standard meaning prescribed by IFRS and therefore may not be comparablewith the calculation of similar measures for other entities. We believe that the presentation of F&D is relevant and useful to investors because it shows the illustrative well-level finding and development cost economics inrespect of wells that may be comparable to those we anticipate drilling in respect of the Deep Basin Assets.

AdvisoryDefinitions and Industry Terminology cont."IP365" is defined as the estimated average producing day rate over the first 365 days of a type curve forecast based on analysis of existing wells having characteristics believed to be similar as the identified drillingopportunities.

"IRR" is defined as the interest rate at which the net present value of all future cash flows from a well equal zero. IRR does not have any standard meaning prescribed by IFRS or the COGE Handbook and therefore maynot be comparable with the calculation of similar measures for other entities. We believe that the presentation of IRR is relevant and useful to investors because it shows illustrative well-level economics in respect of wellsthat may be comparable to those we anticipate drilling in respect of the Deep Basin Assets.

"NPV" is defined as the difference between the present value of projected cash inflows and the present value of projected cash outflows. NPV does not have any standard meaning prescribed by IFRS and therefore maynot be comparable with the calculation of similar measures for other entities. We believe that the presentation of NPV is relevant and useful to investors because it presents the relative monetary significance of wells thatmay be comparable to those we anticipate drilling in respect of the Deep Basin Assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to othercompanies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. NPV, however, does not purport to present the fair value of our oil, natural gas and NGLsreserves.

"Payout" is the number of years required for projected after-tax cash inflows to exceed initial well costs. Payout does not have any standard meaning prescribed by IFRS and therefore may not be comparable with thecalculation of similar measures for other entities. We believe that the presentation of Payout is relevant and useful to investors because it presents an illustration of the time length to profitability of wells that may becomparable to those we anticipate drilling in respect of the Deep Basin Assets.

"Recycle Ratio" is defined as estimated total operating margin over the life of a well divided by initial well costs. Recycle Ratio does not have any standard meaning prescribed by IFRS or the COGE Handbook andtherefore may not be comparable with the calculation of similar measures for other entities. We consider Recycle Ratio to be a useful supplemental measure of operating performance and profitability in respect of wellsthat may be comparable to those we anticipate drilling in respect of the Deep Basin Assets.

"Well Costs" include the average expected costs to drill, complete, and tie-in a single well.

Production Presentation BasisCenovus presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated.

Drilling Locations and OpportunitiesThis presentation discloses potential future drilling locations in two categories: (a) proved locations and (b) probable locations. This document also discloses additional un-booked future drilling opportunities. Provedlocations and probable locations are proposed drilling locations identified in reserve reports prepared for assets acquired pursuant to the acquisition from ConocoPhillips that have proved and/or probable reserves, asapplicable, attributed to them in such reports. Un-booked future drilling opportunities are internal Cenovus estimates based on prospective acreage and an assumption as to the number of wells that can be drilled persection based on industry practice and internal Cenovus technical analysis and review. Un-booked future drilling opportunities have been identified by Cenovus management based on evaluation of applicable geologic,seismic, engineering, production and reserves information. Un-booked future drilling opportunities do not have proved or probable reserves attributed to them in the relevant reserves reports. Of the approximately 1,500identified drilling opportunities within the Deep Basin assets to be acquired, 212 are proved locations, 221 are probable locations and the remainder are un-booked future drilling opportunities.

59

AdvisoryDrilling Locations and Opportunities cont.Cenovus’s ability to drill and develop these locations and opportunities and the drilling locations on which Cenovus actually drills wells depends on a number of uncertainties and factors, including, but not limited to, theavailability of capital, equipment and personnel, oil and natural gas prices, capital and operating costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and reservoir informationthat is obtained, production rate recovery, gathering system and transportation constraints, net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties,there can be no assurance that the potential future drilling locations and opportunities Cenovus has identified will ever be drilled or if Cenovus will be able to produce oil, NGL or natural gas from these or any otherpotential drilling locations or opportunities. As such, Cenovus’s actual drilling activities may differ materially from those presently identified, which could adversely affect Cenovus’s business. While certain of the identifiedun-booked drilling opportunities have been de-risked by drilling existing wells in relatively close proximity to such un-booked drilling opportunities, some of the other un-booked drilling opportunities are farther away fromexisting wells where Cenovus management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled and, if drilled, there is further uncertainty thatsuch wells will result in additional proved or probable reserves or production.

Non-GAAP Measures and Additional SubtotalThe following measures do not have a standardized meaning as prescribed by IFRS and therefore are considered non-GAAP measures. You should not consider these measures in isolation or as a substitute for analysis ofour results as reported under IFRS. These measures are defined differently by different companies in our industry. These measures may not be comparable to similar measures presented by other issuers.

Adjusted Funds Flow is used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as Cash From OperatingActivities excluding net change in other assets and liabilities and net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cashworking capital is composed of current assets and current liabilities, excluding cash and cash equivalents and risk management.

Free Funds Flow is defined as Adjusted Funds Flow less capital investment.

Operating earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings(Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreignexchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, lessincome taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.

Debt to capitalization, net debt to capitalization, debt to adjusted EBITDA and net debt to adjusted EBITDA are ratios that management uses to steward the company’s overall debt position as measures of the company’soverall financial strength. Debt is defined as short-term borrowings and long-term debt, including the current portion. Net debt is defined as debt net of cash and cash equivalents. Capitalization is defined as debt plusshareholders’ equity. Net debt to capitalization is defined as net debt divided by net debt plus shareholders' equity. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense,depreciation, depletion and amortization, goodwill and asset impairments, unrealized gains or losses on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income andloss, calculated on a trailing 12-month basis.

Operating margin is an additional subtotal found in Note 1 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of ourunderlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains lessrealized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.

AdvisoryForward-looking InformationThe presentations and posters at Investor Day 2017 contain certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking information”) within the meaning of applicablesecurities legislation, including the United States Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us inlight of our experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations willprove to be correct.

Forward-looking information in this presentation is identified by words such as “anticipate”, “believe”, “expect”, “estimate", “plan”, “forecast”, “future”, “target”, “position”, “project”, “committed”, “can be”, “pursue”,“capacity”, “could”, “should”, “focus”, “on track”, “outlook”, “potential”, “priority”, “may”, “strategy”, “forward”, “will”, “upside”, “aim”, “implication”, “visibility”, “line of sight”, “vision”, “commit”, “commitment”, “would”,“intend”, “confident”, “poised” or similar expressions and includes suggestions of future outcomes, including statements about: our strategy, business plans and related milestones and schedules, including expected timingfor oil sands expansion phases and associated expected production capacities; projections for 2017 and future years and our plans and strategies to realize such projections; our future development opportunities; forecastoperating and financial results; targets for our Debt (and Net Debt) to Capitalization and Debt (and Net Debt) to Adjusted EBITDA ratios; planned capital expenditures, including the amount, timing and financing thereof;expected future production, including the timing, stability or growth thereof; project capacities; our ability to preserve our financial resilience and various plans and strategies with respect thereto; forecast cost savingsand sustainability thereof; opportunities to improve reservoir performance; potential for development of emerging assets; expected ability for free funds flow generation by conventional oil and natural gas portfolio withmoderate spending, and related ability to invest in growth opportunities; potential drilling opportunities; potential impacts of our hedging program; anticipated use of proceeds of the planned asset sales; anticipatedimpacts of the acquisition from ConocoPhillips; availability and repayment of the existing credit facility and the Bridge Facility; lender commitments to extend maturities of Cenovus's existing credit facility; our ability tosuccessfully complete planned asset sales, including with desired transaction metrics and on targeted timelines; future access to and implementation of technology, including the development of a steam driven solventprocess at our oil sands operations; development or implementation of technologies and their potential impacts on performance; potential for growth and value creation; and projected shareholder return. Readers arecautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

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 industrygenerally. The factors or assumptions on which the forward-looking information is based include: forecast oil and natural gas prices and other assumptions inherent in Cenovus’s 2017 guidance, available at cenovus.com;our projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; the achievement of further cost reductions and sustainability thereof; expected condensate prices;estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; future use and development of technology; our ability to obtain necessary regulatoryand partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient funds flow to meet its current and future obligations; estimated abandonment andreclamation costs, including associated levies and regulations; our ability to successfully integrate the Deep Basin assets; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner;our ability to access sufficient capital to pursue its development plans; our ability to successfully complete the planned asset sales, including with desired transaction metrics and on targeted timelines; anticipated impactsof the acquisition from ConocoPhillips and related financing; forecast crude oil and natural gas prices, forecast inflation and other assumptions inherent in our current guidance set out below; our projected capitalinvestment levels, the flexibility of capital spending plans and the associated sources of funding; sustainability of achieved cost reductions, achievement of future cost reductions and sustainability thereof; expectedcondensate prices; estimates of quantities of oil, bitumen, natural gas and NGLs from properties and other sources not currently classified as proved; future use and development of technology; our ability to access andimplement all technology necessary to efficiently and effectively operate our assets (including, but not limited to, the acquired assets) and achieve and sustain cost reductions; our ability to implement capital projects orstages thereof in a successful and timely manner; our ability to generate sufficient cash flow to meet current and future obligations; and other risks and uncertainties described from time to time in the filings we makewith securities regulatory authorities.

2017 guidance, as updated on June 20, 2017, assumes: Brent prices of US$53.30/bbl, WTI prices of US$50.65/bbl; Western Canadian Select of US$37.55/bbl; NYMEX natural gas prices of US$3.35/MMBtu; AECO naturalgas prices of $3.00/GJ; Chicago 3-2-1 crack spread of US$12.50/bbl; and an exchange rate of $0.74 US$/C$.

60

AdvisoryForward-looking Information cont.Unless otherwise specifically stated or the context dictates otherwise, the financial outlook and forward-looking metrics in this presentation , in addition to the generally applicable assumptions described above, do notinclude or account for the effects or impacts of planned asset sales.

The risk factors and uncertainties that could cause our actual results to differ materially, include: possible failure to successfully complete planned asset sales, including with desired transaction metrics and on targetedtimelines; possible failure to realize the anticipated benefits of and synergies from the acquisition; possible failure to access or implement some or all of the technology necessary to efficiently and effectively operate ourassets (including, but not limited to, the acquired assets) and achieve and sustain future cost reductions; volatility of and other assumptions regarding commodity prices; the effectiveness of our risk managementprogram, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates; commodity prices, currency and interestrates; possible lack of alignment of realized WCS prices and WCS prices as calculated under the contingent payment arrangement between Cenovus and a subsidiary of ConocoPhillips; product supply and demand; marketcompetition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfycontractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of Debt (and Net Debt) to AdjustedEBITDA as well as Debt (and Net Debt) to Capitalization; ability to access various sources of debt and equity capital, generally, and on terms acceptable to Cenovus; ability to finance growth and sustaining capitalexpenditures; changes in credit ratings applicable to Cenovus or any of its securities; changes to dividend plans or strategy, including the dividend reinvestment plan; accuracy of reserves, resources, future productionand future net revenue estimates; ability to replace and expand oil and gas reserves; ability to maintain relationships with Cenovus's partners and to successfully manage and operate its integrated business; reliability ofassets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires,severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, includinglabour, natural gas and other energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; unexpected costincreases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of crude oil into petroleum and chemical products; risksassociated with technology and its application to our business; risks associated with climate change; the timing and the costs of well and pipeline construction; ability to secure adequate and cost-effective producttransportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain,critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; changes in labour relationships; changes in the regulatory framework in any of the locations in whichwe operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to theinterpretation 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 andstandards on our business, its financial results and its consolidated financial statements; changes in general economic, market and business conditions; the political and economic conditions in the countries in which weoperate or supply; 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 againstCenovus.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected andexpressed in, or implied by, the forward-looking information. For a full discussion of Cenovus's material risk factors, see “Risk Factors” in our Annual Information Form (AIF) or Form 40-F for the period ended December31, 2016 and the updates under "Risk Management" in the company's most recently filed Management's Discussion and Analysis available on SEDAR at sedar.com, on EDGAR at sec.gov and on Cenovus's website atcenovus.com.

TM denotes a trademark of Cenovus Energy Inc.© 2017 Cenovus Energy Inc.

Additional information

June 20, 2017 Guidance of all operating metrics includes forecast impacts of the acquisition effective May 18, 2017 (8)

Steam to oilrates (%) ratio

Foster Creek 123 - 131 525 - 575 Fuel 3.25 - 3.75 7 - 10 2.6 - 3.0Non-fuel 7.50 - 8.50Total 10.75 - 12.25

Christina Lake 164 - 174 475 - 525 Fuel 2.25 - 2.75 2 - 4 1.8 - 2.2Non-fuel 4.25 - 5.25Total 6.50 - 8.00

Narrows Lake - - 10 - 30 - - - - - -

New resource plays (1) - - 60 - 80 - - - - - -

Oil Sands total 287 - 305 1,070 - 1,210

3 - 4NGLs 15 - 17 ($ millions) ($/BOE)

160 - 180 9.00 - 10.00 10 - 12

315 - 335

($/bbl)

51 - 56 15.00 - 17.00 14 - 18

300 - 350 ($/Mcf)

340 - 360 1.20 - 1.40 4 - 6

356 - 382655 - 695465 - 498 1,530 - 1,740

200 - 220 8.50 - 9.50Marketing & transportation 10 - 20

35 - 50 Upstream DD&A ($ billions) 1.6 - 1.81.8 - 2.0 Other DD&A ($ millions) (5) 275 - 375310 - 350 Cash tax (recovery) ($ millions) (150) - (50)

Effective tax rate (%) (6) 27 - 32

Brent (US$/bbl) Independent base case sensitivities Increase DecreaseWTI (US$/bbl) (for second half of 2017) ($ millions) ($ millions)Western Canada Select (US$/bbl) Crude oil (WTI) - US$10.00 change 460 (530)NYMEX (US$/MMBtu) Light-heavy differential (WTI-WCS) - US$5.00 change (325) 260AECO ($/GJ) Chicago 3-2-1 crack spread - US$1.00 change 50 (50)Chicago 3-2-1 Crack Spread (US$/bbl) Natural gas (NYMEX) - US$1.00 change 260 (260)Exchange Rate (US$/C$) Exchange rate (US$/C$) - $0.05 change (150) 145(1) New resource plays includes Grand Rapids, Telephone Lake, and other emerging plays.(2) Oil & liquids includes Pelican Lake as well as oil and NGLs from Alberta and Saskatchewan. (3) Natural gas includes all natural gas production.(4) Refining capital and operating costs are reported in C$, but incurred in US$ and as such will be impacted by FX.(5) Includes DD&A related to Refining and Corporate and Eliminations.(6) Statutory rates of 27% in Canada and 38% in the US are applied separately to pre-tax operating earnings streams for each country. Excludes the effect of mark-to-market gains and losses. (7) Sensitivities include current hedge positions applicable to the full year 2017. Refining results embedded in the sensitivities are based on unlagged margin changes and do not include the effect of changes in inventory valuation for first-in, first-out/lower of cost or net realizable value. (8) Assumes no dispositions in 2017 and full contribution from Conventional assets.(9) Corporate capital exclude one time costs associated with Deep Basin operations.(10) Sensitivities includes contingent payment expense to ConocoPhillips.(11) Excludes one time transaction costs.

2017 Corporate Guidance - C$, before royalties

UPSTREAMOIL SANDS

Production Capital expenditures Operating costs Effective royalty(Mbbls/d) ($ millions) ($/bbl)

LEGACY CONVENTIONALProduction

Light/Medium Oil

Natural gas (3)

(Mbbls/d)

Operating costsrates (%)(Mbbls/d)

(MMcf/d)

Effective royaltyOperating costsCapital expendituresrates (%)

Effective royalty

Oil & liquids (2)

(MMcf/d)

Production Capital expenditures(Mbbls/d, MBOE/d) ($ millions)

($ millions)

Natural gas (3)

TOTAL

Capital expenditures

$3.00$12.50$0.74

DEEP BASINProduction

Total capital expenditures ($ billions)General & administrative expenses ($ millions) (11)

PRICE ASSUMPTIONS & ADJUSTED FUNDS FLOW SENSITIVITIES (7)

$53.30$50.65

($ millions) ($/bbl)Refining (4)

$37.55$3.35

CORPORATE

Corporate & other expenditures ($ millions) 9

Total liquids

Total upstream

REFINING & MARKETINGCapital expenditures Operating costs

Total natural gas

Forward-looking Information This document contains certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking information”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.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 in this document is based include: forecast oil and natural gas prices; our projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; the achievement of further cost reductions and sustainability thereof; expected condensate prices; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; future use and development of technology; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient funds flow to meet its current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations; our ability to successfully integrate the Deep Basin assets; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to access sufficient capital to pursue its development plans; our ability to successfully complete the planned asset sales, including with desired transaction metrics and on targeted timelines; anticipated impacts of the acquisition from ConocoPhillips and related financing; forecast crude oil and natural gas prices, forecast inflation and other assumptions inherent in our current guidance set out below; our projected capital investment levels, the flexibility of capital spending plans and the associated sources of funding; sustainability of achieved cost reductions, achievement of future cost reductions and sustainability thereof; expected condensate prices; estimates of quantities of oil, bitumen, natural gas and NGLs from properties and other sources not currently classified as proved; future use and development of technology; our ability to access and implement all technology necessary to efficiently and effectively operate our assets (including, but not limited to, the acquired assets) and achieve and sustain cost reductions; our ability to implement capital projects or stages thereof in a successful and timely manner; our ability to generate sufficient cash flow to meet 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: possible failure to successfully complete planned asset sales, including with desired transaction metrics and on targeted timelines; possible failure to realize the anticipated benefits of and synergies from the acquisition; possible failure to access or implement some or all of the technology necessary to efficiently and effectively operate our assets (including, but not limited to, the acquired assets) and achieve and sustain future cost reductions; volatility of and other assumptions regarding commodity prices; the effectiveness of our risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates; commodity prices, currency and interest rates; possible lack of alignment of realized WCS prices and WCS prices as calculated under the contingent payment arrangement between Cenovus and a subsidiary of ConocoPhillips; product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of Debt (and Net Debt) to Adjusted EBITDA as well as Debt (and Net Debt) to Capitalization; ability to access various sources of debt and equity capital, generally, and on terms acceptable to Cenovus; ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to Cenovus or any of its securities; changes to dividend plans or strategy, including the dividend reinvestment plan; accuracy of reserves, resources, future production and future net revenue estimates; ability to replace and expand oil and gas reserves; ability to maintain relationships with Cenovus's partners and to successfully manage and operate its integrated business; reliability of assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of crude oil into petroleum and chemical products; risks associated with technology and its application to our business; risks associated with climate change; the timing and the costs of well and pipeline construction; ability to secure adequate and cost-effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; changes in labour relationships; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change 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, its financial results and its consolidated financial statements; changes in general economic, market and business conditions; the political and economic conditions in the countries in which we operate or supply; 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 Cenovus.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of Cenovus's material risk factors, see “Risk Factors” in our Annual Information Form (AIF) or Form 40-F for the period ended December 31, 2016 and the updates under "Risk Management" in the company's most recently filed Management's Discussion and Analysis available on SEDAR at sedar.com, on EDGAR at sec.gov and on Cenovus's website at cenovus.com.

Steepbank

East McMurray

TelephoneLake

Grosmont

Grand Rapids

Foster Creek Proper

Narrows Lake

West Kirby Winefred LakeChristina Lake Proper

Wabiskaw BOREALIS REGIONGREATER PELICAN REGION

CHRISTINA LAKE REGION

FOSTER CREEK REGION

HardyLeismer

Albert

a

Saskatchewan

Fort McMurray

GrosmontWabiskaw/McMurray

Clearwater

Birch

CVE-

1782

-701

Vernon CalgaryKelowna

EdmontonRed Deer

LethbridgeMedicine Hat

Prince George

Fort McMurrayGrande Prairie

0 10 205Kilometers

1:1,500,000

R1W4R5W4R10W4R15W4R20W4R1W5T95

T100T85

T90T70

T75T80

T65T6

0T6

5T7

0T7

5T8

0T8

5T9

0T9

5T1

00

R25W3R1W4R5W4R10W4R15W4R20W4R25W4R1W5

Cenovus oil sands land at Dec. 31, 2016

Cenovus PNG LandGrosmont Deposit

Clearwater DepositWabiskaw/McMurrayDeposit

62

Conventional oil & natural gas

Free funds flow has enabled oil sands growthFree funds flow each and every year

Note: Free funds flow defined as operating margin less capital expenditures.

• Generated nearly $6.0 billion of free funds flow

• Approximately $4.0 billion of net A&D proceeds

• sale of Heritage Royalty Partnership for $3.3 billionin 2015

• sales of Shaunavon, Wainwright, and other non-core producing properties

• Enabled a 26% CAGR in oil sands production to390,000 bbls/d

• We have more material opportunities within our portfolioand we intend to divest all of our legacy conventionalproduction

Contributed nearly $10 billion since 2010

$0.0

$0.5

$1.0

$1.5

$2.0

2010 2011 2012 2013 2014 2015 2016 Q1 2017

Free funds flow

Net A&D activity

Free funds flow and net A&D activity($ billions)

$3.3

63

Palliser asset overviewPalliser asset overview Free funds flow each and every year

• Over 1,200 sections of leased and available prospectiveMannville oil lands; 10-year option exclusive to Cenovus

• High-return, low-cost and short-cycle growth opportunities

• Over 700 unrisked Mannville horizontal oil locationsidentified



Average working interest % ~95Net operated processing capacity MMcf/d 650

2017F production BOE/d 53,000% oil / liquids % 242017F capex $ millions 210

$0.0

$0.5

$1.0

$1.5

$2.0

2010 2011 2012 2013 2014 2015 2016 2017F


Palliser cumulative free funds flow($ billions)

Palliser development program is on trackPalliser production volumes are on track

Note: Volumes are incremental only and relate to recent development drilling.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Jan‐17 Feb‐17 Mar‐17 Apr‐17 May‐17 Jun‐17 Jul‐17 Aug‐17 Sep‐17 Oct‐17 Nov‐17 Dec‐17

Budget Actual

Palliser incremental development volumes versus budget(BOE/d)

Palliser development program is going well

• Drilled, completed, and tied-in 27 horizontal wells ofcurrent program

• well costs coming in on budget and productivity is aspredicted

• initial production ramp-up impacted by wet weather

• drilling currently paused for spring break-up

• Strat wells continue to verify inventory

• Successfully leveraging existing infrastructure to maintainlow operating costs

64

Weyburn asset overviewWeyburn asset overview

• Medium oil CO2 enhanced oil recovery project located insoutheastern Saskatchewan

• Over 30 million tonnes of CO2 stored with over 500 millionbarrels of oil recovered to date (36% recovery to date)

• Low decline, free funds flow generating asset



Average working interest % 62

2017F production BOE/d 15,000% oil / liquids % 1002017F capex $ millions 70

Free funds flow each and every year


$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

2010 2011 2012 2013 2014 2015 2016 2017F

Weyburn cumulative free funds flow($ billions)

Kam SandharVice-President, Investor Relations & Corporate [email protected]

Steven [email protected]

Graham [email protected]

Michelle [email protected]

Cenovus Energy Inc.500 Centre Street SECalgary, Alberta T2P 0M5Telephone: 403.766.2000Toll free in Canada: 1.877.766.2066Fax: 403.766.7600cenovus.com

Investor relations contacts

achieving our potential - cenovus energy · 2017-06-20 · achieving our potential brian ferguson...

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