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Achieving our potential
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About Cenovus
British Columbia Alberta Saskatchewan
Edmonton
Calgary Regina
Fort St. JohnFort McMurray
Saskatoon
Horn River
Elmworth-Wapiti
Kaybob-Edson
Clearwater
Narrows Lake
Christina Lake
Foster Creek
Telephone Lake
Note: Values are approximate. 2018F production based on the midpoint of December 13, 2017 guidance. 1 2018F total natural gas includes production from the Deep Basin and Cenovus’s Athabasca natural gas asset. See advisory.
TSX, NYSE | CVE
Enterprise value C$ 23 billion
Shares outstanding 1,229 million
2018F production
Oil sands 373 Mbbls/d
Deep Basin
Oil & liquids 32 Mbbls/d
Natural gas 540 MMcf/d
Total liquids 405 Mbbls/d
Total natural gas1 550 MMcf/d
Total production 497 MBOE/d
2017 proved + probable reserves 7.1 BBOE
Refining capacity 230 Mbbls/d net
Strong free funds flow potential2019F adjusted funds flow projected to increase Attractive free funds flow yield
• Q1 2018 financial results are transitory:
• impacted by realized hedging losses, wider light-heavy oil differentials and planned turnaround activity
• underlying operations are running extremely well
• Majority of out of the money hedges roll off in H2 2018
• ~37% of H2 2018 oil production hedged versus ~80% in H1 2018
• Significant leverage to higher oil prices in 2019
• 2019 adjusted funds flow expected to increase more than 50% over 2018 per analyst consensus estimates
• capital discipline drives free funds flow
2019F free funds flow yield(percent)
12%
10%
8%
7%
6%5%
5% 5%
4% 4% 3%
NM
0%
3%
6%
9%
12%
15%
CVE
Note: Free funds flow yield is calculated as unhedged cash flow less Peters & Co. estimate of required capital spending to maintain flat production volume YoY, expressed as a percentage of market capitalization. Peers include: APA, CNQ, DVN, ECA, EOG, HSE, IMO, PSK, SU, TOU, VII.See Advisory.
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• Majority of 2018 capital sustains base production at Cenovus’s oil sands operations
• Targeting <2.0x net debt to adjusted EBITDA
• Remaining capital:
• Christina Lake phase G expansion
• targeted drilling program in the Deep Basin
Demonstrating disciplined capital allocation
Sustain current assets and dividend
Return to shareholders:
• Increased dividend• Share repurchases
High-return growth projects:
• Christina Lake phase G
Manage balance sheet to
investment grade status
Targeting consistent growth in total shareholder returns
Focused on capital discipline
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Continuing to streamline the asset portfolio
Note: See Advisory.
Evaluating non-core assets Track record on divestitures since 2010
• Continuing to evaluate portfolio for non-core divestitures
• Deep Basin non-core Clearwater assets currently being marketed, ~15,000 BOE/d
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1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
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Historical asset sale proceeds($ millions)
Executed ~$4.5 billion in divestitures
Pelican Lake
Palliser
Weyburn
Suffield
2010 - 2015 2017 – 2018F
Alberta
Edmonton
Calgary
Fort St. John
Elmworth-Wapiti
Kaybob-Edson
Clearwater (15,000 BOE/d)
Christina Lake
Foster Creek
British Columbia
Identified divestiture target
Deep Basin
Cenovus lands
Executed ~$3.7 billion in divestitures
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~$3.5 billion
Maintaining financial resilience and flexibility
Note: Liquidity positions as at March 31, 2018. See Advisory.
Liquidity position Near-term debt reduction
• Targeting net debt to adjusted EBITDA < 2.0x• ~$5 billion liquidity position supports investment grade ratings
Net debt($ billions)
Manageable long-term maturities
• Weighted average cost of debt ~5.1%
Principal outstanding(US$ billions)
$0
$4
$8
$12
$16
Q2 2017 Q3 2017 Q4 2017 Q1 2018
Credit ratings
S&P Moody’s DBRS Fitch
BBB Ba2 BBB BBB-
Negative outlook
Stable outlook
Negative outlook
Stable outlook
$0.4 billion cash on hand
$4.5 billion available oncredit facility
$0.0
$0.5
$1.0
$1.5
$2.0
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Cost reductions improve sustainability
Note: General & administrative costs exclude one-time severance and non-cash onerous lease charges. See Advisory.
Oil sands sustaining capital Oil sands operating costs General & administrative costs
$0.00
$3.00
$6.00
$9.00
$12.00
$15.00
2014 2015 2016 2017 2018F
$/bbl
• > 50% reduction to G&A costs
• Improved efficiencies, workforce optimization, and reduced discretionary spending
• > 40% reduction to oil sands opex
• Non-fuel costs decreasing
• Natural gas prices and turnarounds fluctuateyear-to-year
• > 50% reduction in oil sands sustaining capital costs
• Savings are expected to be sustainable
$0.00
$3.00
$6.00
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2014 2015 2016 2017 2018F
$/bbl
$0.00
$1.00
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2014 2015 2016 2017 2018F
$/BOE
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Sustainability drives free funds flow
Note: Implied WTI breakeven required to cover sustaining capital and dividends.Decline rates as per Peters & Co. Limited. Free funds flow as per Peters & Co. as of April 16, 2018 strip pricing. Free funds flow yield is calculated as unhedged cash flow less Peters & Co. estimate of required capital spending to maintain flat production volume YoY, expressed as a percentage of market capitalization. Peers include: APA, CNQ, DVN, ECA, EOG, HSE, IMO, PSK, SU, TOU, VII. See Advisory.
Low corporate decline rates Improved sustainability Free funds flow yield
0%
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30%
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50%
CVE
Implied WTI breakeven(US$/bbl)
2018F corporate decline rate(percent)
$30
$40
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$60
$70
2014 2015 2016 2017 2018F
~15% corporate decline rate Low WTI breakeven Increasing free funds flow
-3%
0%
3%
6%
9%
12%
15%
2019F free funds flow yield(percent)
CVE
Improvement drives sustainable reductions
Redesigned well pads
Lower F&DTargeting $8 – $10/bbl
• 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 the full 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
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• Superior start-up and steam circulation methods
• Advanced sub-surface equipment and design
• High pressure ramp up
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2011
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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
Potential for
New design improves well conformance
• Better conformance along the full horizontal well length
• Lower SOR
• Higher oil rates per well pair
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0%
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30%
0 3 6 9 12 15 18 21 24
Months on production
E20 PAD (2008) E15 PAD (2009) W02 PAD (2011) E08 PAD (2013)W08 PAD (2015) W07 PAD (2016) W10 PAD (2016) W05 PAD (2016)W18 PAD (2016) W23 PAD (2016) W15 PAD (2016)
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
Potential for
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2,000
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1 31 61 91 121 151 181 211 241 271 301 331 361 391 421Day
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 and capture 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
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Improved conformance allows longer horizontal wells
Note: Well results show average of two 1,400m wells compared to two 965m wells.
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 and pads
• 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
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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
Improved conformance, longer horizontal wells and redesigned well pads result in substantial cost savings
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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
Improved conformance, longer horizontal wells and redesigned well pads result in substantial cost savings
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Total production Portfolio-weighted SOR
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SOR reflects resource quality and execution
Note: Production data and steam-oil ratio based on AER data as of February 2018. 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.
Reinforcing our position as a leader in SAGD
Production(Mbbls/d)
Portfolio-weighted SOR
CVE
Our competitive advantage
Low SOR means:
• lower capital cost
• lower energy usage
• lower operating cost
• smaller surface footprint
• lower emissions
• less water usage
$0
$5
$10
$15
$20
$25
$30
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Demonstrating top quartile oil sands operating costsQ4 2017 oil sands operating costs per barrel
Operating costs($/bbl)
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Source: Company reports. Peers include ATH, CNQ, HSE, MEG and SU.
CVEChristina Lake
CVEFoster Creek
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Mbbls/d
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Christina Lake overview
Note: Production is shown before royalties on a gross basis. 2018F production based on midpoint of December 13, 2017 guidance. 2P reserves as of December 31, 2017.
PhaseBPhase
A
PhaseC
PhaseD
OptimizationCDE
PhaseF
PhaseE
Christina Lake production history Key facts and reservoir characteristics
Successfully executed 7 SAGD expansions and optimizations
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) 2,759
2018F production (bbls/d) ~207,000
Phase G builds on Christina Lake success
Note: After-tax IRR based on go-forward spending and flat US$55/bbl WTI. See Advisory.
Christina Lake phase G project profile
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2017 2018F 2019F 2020F 2021F 2022F
25%
40%30%
5% 0 0$0
$100
$200
$300
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$500
2017 2018F 2019F 2020F 2021F 2022F
Christina Lake phase G capital profile($ millions)
Christina Lake phase G production profile(Mbbls/d)
Forecasted key statistics
Units Statistic
Project oil capacity Mbbls/d 50
Steam-oil ratio x 1.8 – 2.2
Capital spent to date $ millions $425
Capital remaining to completion $ millions $475 – $525
Construction resumed date H2 2017
Expected first oil date date H2 2019
Go-forward capital efficiency $M/bbl/d $13 – $14
After-tax IRR % > 30%
Best-in-class oil sands project
• Industry-leading steam-oil ratio
• Expected go-forward capital efficiency of $13,000 - $14,000/bbl/d (was $16,000 - $18,000/bbl/d)
• Construction is on track for first oil in H2 2019
• >50% reduction in capital efficiency from phase F
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Note: Capital spent to date as at December 31, 2017. Go-forward capital efficiency based on remaining capital required at time of reactivation (Q1 2017) and project oil capacity.
10
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) 2,607
2018F production (bbls/d) ~166,000
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Foster Creek overview
Note: Production is shown before royalties on a gross basis. 2018F production based on the midpoint of December 13, 2017 guidance. 2P reserves as of December 31, 2017.
PhaseC
Phase D,E
PhaseF
PhaseG
PhaseA
PhaseB
Foster Creek production history
Successfully executed 7 SAGD expansions and optimizations
Key facts and reservoir characteristics
Solvents expected to create value and reduce emissions intensity
• Decreases SOR by ~30% - 35%
• Increases individual well production rates up to 10%
• Increases growth capital by15% - 20%
• Decreases sustaining capital by 10% - 30%
• Reduces non-fuel operating costs by up to 20%
• Solvents have the potential to achieve up to 80% of our targeted 33% GHG reduction
CSAP Potential benefits of solvents SAGD
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Deep Basin provides second production platform
Note: Deep Basin summary statistics excludes any potential divestitures. 2P reserves as of December 31, 2017. See Advisory.
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 with significant liquids-rich development upside
• Deep inventory of short-cycle, high IRR potential drilling opportunities in areas that attract capital from offsetting operators
• Assets were previously capital constrained
• 1.4 BCF/d of net natural gas processing capacity; majority owned and operated
Deep Basin summary statistics
• 2018F production: 122,000 BOE/d(26% liquids; 17% decline rate)
• Total net acres: ~3.0 million
• Proved + probable + future drilling opportunities: ~ 1,500
• 2P reserves: 660 MMBOE (62% proved)
22
Deep Basin results exceeding expectations
Elmworth / Wapiti
• 14 wells drilled, 10 on production
• Appraised multiple layers of the Wapiti stack
• Initiated Pipestone Montney stacking and spacing pilotand Lower Montney test
Kaybob / Edson
• 18 wells drilled, 9 on production
• First 2 Edson Wilrich wells IP30 average of 1,650 BOE/d (restricted rates)
• Best Edson Notikewin well drilled to date; IP30 1,510 BOE/d (~105 bbls/d free condensate)
• Tested a more intense completion design with BigstoneMontney appraisal well
Clearwater
• 11 wells drilled, 7 on production
• Average IP30 of ~2,400 BOE/d for longer-reach wells
• Top decile well at Ferrier with IP30 of 2,725 BOE/d (350 bbls/d free condensate, restricted rate)
Note: Activity and results reflective of 2017-2018 program.
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No near-term takeaway constraintsAsset overview Deep Basin infrastructure map
• ~1.4 BCF/d of net natural gas processing capacity and significant associated gathering infrastructure
• Infrastructure footprint spans the Deep Basin
• Ownership and control underpins operational flexibility
• Excess processing capacity supports near-term development
Key statistics
Units Statistic
Operated assets # 17
Avg. working interest of operated facilities % 77
Total net processing capacity MMcf/d ~1,400
Key operated facilities
Facility Units Statistic
Elmworth 01-08-70-11W6 Net MMcf/d 395
Noel B-059-D/093-9-08 Net MMcf/d 150
Peco 12-01-049-16W5 Net MMcf/d 69
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$20.00Operating costs % Natural gas
Driving efficiencies in Deep Basin operating costsQ4 2017 operating costs for Deep Basin & Montney peers
($/BOE) (% gas)
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Source: Company reports. Peers include AAV, ARX, BIR, BNP, BXE, CNQ, CR, ECA, HSE, KEL, NVA, PEY, PONY, POU, TOU, VII.
CVE
Highlights
• Higher operating costs are a result of a broad acreage base and underutilized infrastructure
• Scalable and efficient capital program should bring more economies of scale
• Q1 2018 operating costs per BOE down 18% from Q3 2017
• Expect to achieve an 11% reduction in operating costs compared with 2017
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Upside potential from stacked pay
Note: Formation rights (net acres) by area. Spirit River formation includes the Notikewin, Falher, and Wilrich.
Upside potential from stacked pay Target formations
Formation Elmworth Wapiti Kaybob Edson Clearwater Totals
Cardium 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
.
Supplemental
14
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 production levels
• sufficient transportation via committed capacity and system efficiencies
• reviewing risked scenarios to help ensure adequate needs in the future
• 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
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500
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2017 2018F
Firm transport Deep Basin natural gas
Note: See Advisory.
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Mitigating our exposure to wider heavy differentials
Note: See Advisory.
Marketing in excess of 500 Mbbls/d Heavy processing mitigates ~25% Transportation provides optionality
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2018F dry bitumen 2018F blended heavy oil
Oil sands production volumes(Mbbls/d)
• Long haul pipeline commitments and Bruderheim provide additional mitigation against wider light-heavy differentials
• Represents approximately 25% - 30% of forecasted blended heavy oil volumes
• Heavy processing capacity provides strong mitigation against wider light-heavy differentials
• Represents approximately 25% of forecasted blended heavy oil volumes
• Dry bitumen requires blending with a lighter hydrocarbon such as condensate to meet pipeline specifications
• A typical barrel of blended heavy oil consists of 30% condensate and 70% bitumen
~25%
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2018F heavy oilprocessing capacity
2018F blended heavy oil
Volumes(Mbbls/d)
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2018F blended heavy oil
~25% - 30%
Volumes(Mbbls/d)
15
Refining capacity mitigates heavy oil differentials
• Refining assets help to mitigate exposure to wider light/heavy differentials
• Approximately 25% of total blended heavy oil volumes are mitigated with processing capacity
• Wood River capable of processing 220,000 gross bbls/d of heavy
• Borger capable of processing 35,000 gross bbls/d of heavy
• Transportation options provide further mitigation from wider light/heavy differentials
Percentage of total operating margin
WTI-WCS differential (US$/bbl)
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2009 2010 2011 2012 2013 2014 2015 2016 2017
Downstream Upstream WCS differential (US$/bbl)
Refinery complexity drives margins Integration through the cycle
29
Refining operating margin sensitivities
-$500
-$250
$0
$250
$500
$750
$1,000
$10.00 $12.00 $14.00 $16.00 $18.00 $20.00
Chicago crack spread - US$/bbl
US$20/bbl
US$15/bbl
US$10/bbl
Refining operating margin net (LIFO basis)US$ million
L/H diff
U$1 change in crack spread = ~US$67 million refining operating marginU$1 change in L/H differential = ~US$40 million refining operating margin
U$1 change in WTI = ~US$7 million refining operating margin
Note: Based on an approximately US$52/bbl WTI as a basis and assumes no unplanned downtime or external disruptions. RINs assumed at US$0.70 cpg.
Refining operating margin sensitivities 2018F
30
16
Takeaway capacity reduces market access risk
• Cenovus takes a portfolio approach maximizing the value of every barrel
• West Coast: Trans Mountain
• US Gulf Coast: Enbridge USGC/Flanagan South
• Bruderheim rail facility provides incremental optionality
• Supporting pipeline expansions to secure future market access
• US Gulf Coast: Keystone XL
• West Coast: Trans Mountain Expansion
• Marine capability provides additional flexibility and low-cost optionality to global pricing
Optimizing takeaway capacity to provide flexibility Sufficient near term takeaway capacity
PADD V
PADD IV
PADD III
PADD I
Alberta
Borger Refinery
Wood River Refinery
PADD II
Hardisty
Houston
Cushing
Chicago
Pipeline expansionProposed pipeline
Edmonton
Patoka
Vancouver
Current pipelines
31
• 100 Mbbls/d of gross loading capacity
• Long-term and low-cost optionality
• Ability to move wider variety of crudes
• Development optionality expected to generate additional value
• midstream value-add (blending, storage, transloading)
• cavern capacity
• partial upgrading
• cogeneration
• support for solvent strategy
32
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
17
Current hedge positions for 2018
Hedges at March 31, 2018 Terms Volumes Average price
Crude – Brent Fixed Price April – June 60,000 bbls/d US$53.34/bbl
Crude – WTI Fixed Price April – June 150,000 bbls/d US$48.91/bbl
Crude – WTI Fixed Price July – December 75,000 bbls/d US$49.32/bbl
Crude – Brent Put Options April – June 25,000 bbls/d US$53.00/bbl
Crude – Brent Collars April – June 80,000 bbls/d US$49.54 – US$59.86/bbl
Crude – Brent Collars July – December 75,000 bbls/d US$49.00 – US$59.69/bbl
Crude – WTI Collars April – June 10,000 bbls/d US$45.30 – US$62.77/bbl
Crude – WCS Differential April – June 14,800 bbls/d US$(14.05)/bbl
Crude – WCS Differential April – December 10,500 bbls/d ~US$(14.52)/bbl
Current hedge positions for 2019
Hedges at March 31, 2018 Terms Volumes Average price
Crude – WTI Collars January – December 19,000 bbls/d US$50.00 – US$62.08/bbl
Hedging summary
33
Creating value through corporate responsibility
• SER Committee of the Board provides oversight of environment and sustainability performance
• Enterprise Risk Management program, practices and policy help ensure active and effective risk mitigation
• Transparent disclosure and reporting through annual Corporate Responsibility Report
• Partnering with Aboriginal communities through employment, education, and business development
• more than $2.0 billion spent since 2009 on goods and services supplied by Aboriginal businesses
• Targeting 1% of pre-tax profits donated to non-profit and charitable organizations to create shared value and build long-term relationships in the communities where we operate
• more than $96 million donated through our community investment program since 2010
DJSI North American
IndexEuronext Vigeo
World 120 Index for Responsible Performance
Corporate Knights Best 50 Corporate Citizens
in Canada
Committed to good governance
Building long-term support in our communities
Recognized for corporate sustainability
34
Global Sustainability Index
18
Advancing our carbon and environmental performance
• Rigorous regulatory framework ensures environment considerations throughout project lifecycle
• Dedicated internal environment team focused on mitigating environmental risks
• Ongoing collaborative technology investment through COSIA and Evok Innovations aimed at advancing Cenovus and industry environmental performance
• Low carbon intensity, carbon price modelling and innovation drive oil sands carbon emissions performance
• Direct oil sands GHG emissions intensity is down 35% since 2004 and 40%* below industry average
• Oil sands freshwater, NOx and SO2 intensity below industry average
Committed to responsible development
35
Note: Oil sands freshwater intensity performance refers to AER Directive 81 Thermal In-situ Water Publication for all schemes operating in 2017 with production > 5,000 bbl/d. GHG, NOx and SO2 intensity performance refers to 2015 CAPP RCE national data table for 2014 operating year.
0.303 0.304 0.295 0.2880.312
0.221 0.222 0.224 0.234 0.255
0.522
0.00
0.10
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0.30
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0.60
2012 2013 2014 2015 2016
Oil sands Company wide CAPP RCE oil sands average (2014)
Tonnes CO2E/M3 OE
Oil sands direct GHG emissions intensity
Supplemental terms of the ConocoPhillips’ transaction
• Based on a 5-year time horizon, with a threshold price of $52.00/bbl Western Canadian Select (“WCS”)
• Calculation based on $6.0 million per quarter multiplied by the difference between the average WCS price and the threshold price of $52.00/bbl
• Payments and calculations are done on a quarterly basis
• Contingent payments will be reduced during periods of material production outages
• Cenovus retains 80-85% of the benefit above the trigger price based on current FCCL production volumes
Contingent payment terms Vendor take-back terms
• ConocoPhillips has agreed to receive 208 million common shares of Cenovus
• Share consideration reinforces ConocoPhillips’ confidence in the strategic rationale of this transaction and future outlook for Cenovus
• ConocoPhillips is bound by the terms in the investor agreement, including a restriction on its ability to sell or hedge its shares for a minimum period of six months from the closing date of the transaction
• ConocoPhillips has agreed to vote with Cenovus management voting recommendations or abstain from voting and is restricted from nominating new members to Cenovus’s Board of Directors
36
^
Steepbank
East McMurray
TelephoneLake
Foster Creek Proper
Narrows Lake
West Kirby Winefred LakeChristina Lake Proper
BOREALIS REGION
CHRISTINA LAKE REGION
FOSTER CREEK REGION
HardyLeismer
Albert
a
Saskatchewan
Fort McMurray
GrosmontWabiskaw/McMurray
Clearwater
Birch
Dover
North &
SouthHouse
Portage Duncan
SouthPortage
K
CVE-
1782
-1401 !
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Vernon CalgaryKelowna
Red DeerEdmonton
LethbridgeMedicine Hat
Prince George
Fort McMurrayGrande Prairie
0 10 20 30 40 50Kilometers
1:1,500,000
R1W4R5W4R10W4R15W4R20W4R1W5T95
T100T85
T90T70
T75T80
T65T6
0T6
5T7
0T7
5T8
0T8
5T9
0T9
5T1
00
R25W3R1W4R5W4R10W4R15W4R20W4R25W4R1W5
Cenovus oil sands land at December 31, 2017
Cenovus PNG LandGrosmont Deposit
Clearwater DepositWabiskaw/McMurrayDeposit
Oil and Gas Information The estimates of reserves and related information were prepared effective December 31, 2017 by independent qualified reserves evaluators (“IQREs”), based on the Canadian Oil and Gas Evaluation Handbook (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 Equivalent Natural 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 is based 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 oil compared 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. 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 comparable with 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 in respect of wells that may be comparable to those we anticipate drilling in respect of the Deep Basin Assets. “IP30” is defined as the initial average production rate for the first 30 producing days of a well. "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 drilling opportunities. "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 may not 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 wells that 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 may not 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 that may 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 other companies. 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 NGLs reserves. "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 the calculation 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 be comparable 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 and therefore 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 wells that 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 Basis Cenovus presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Drilling Locations and Opportunities This 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. Proved locations 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, as applicable, 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 per section 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 1,500 identified drilling opportunities within the Deep Basin assets, 212 are proved locations, 221 are probable locations and the remainder are un-booked future drilling opportunities. 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, the availability 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 information that 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 other potential 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 identified un-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 from existing 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 that such wells will result in additional proved or probable reserves or production.
Non-GAAP Measures and Additional Subtotal The 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 of our 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 Operating Activities 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-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Free Funds Flow is defined as Adjusted Funds Flow less capital investment. Operating Earnings - earnings (loss) before income tax excluding gain (loss) on discontinuance, revaluation gain, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange 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, less income 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’s overall 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 plus shareholders’ equity. Net debt to capitalization is defined as net debt divided by net debt plus shareholders' equity. Adjusted EBITDA - earnings before finance costs, interest income, income tax expense, DD&A, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing 12-month basis. Operating Margin is an additional subtotal found in Note 8 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying 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 less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. 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. 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 timing for oil sands expansion phases and associated expected production capacities; projections for 2018 and future years and our plans and strategies to realize such projections; our future development opportunities; forecast operating 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 savings and 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 with moderate spending, and related ability to invest in growth opportunities; potential drilling opportunities; potential impacts of our hedging program; lender commitments to extend maturities of Cenovus's existing credit facility; our ability to successfully 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 solvent process 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 are cautioned 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 industry generally. 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 2018 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 regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient funds flow to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations; 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 development plans; our ability to successfully complete the planned asset sales, including with desired transaction metrics and on targeted timelines; 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; 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 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. 2018 guidance, dated December 13, 2017, assumes: Brent prices of US$55.00/bbl; WTI prices of US$52.00/bbl; WCS of US$37.00/bbl; NYMEX natural gas prices of US$3.00/MMBtu; AECO natural gas prices of $2.20/GJ; Chicago 3-2-1 crack spread of US$15.00/bbl; and an exchange rate of $0.78 US$/C$. 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 not include 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 targeted timelines; 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 Management and Risk Factors” in our annual Management’s Discussion and Analysis (MD&A) or Form 40-F for the period ended December 31, 2017 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. TM denotes a trademark of Cenovus Energy Inc. © 2018 Cenovus Energy Inc.
December 13, 2017
Steam to oilrates (%) ratio
Foster Creek 162 - 170 500 - 550 Fuel 2.00 - 2.50 9 - 12 2.6 - 3.0Non-fuel 6.50 - 7.50Total 8.50 - 10.00
Christina Lake 202 - 212 500 - 550 Fuel 1.75 - 2.25 3 - 5 1.8 - 2.2Non-fuel 4.25 - 5.25Total 6.00 - 7.50
Narrows Lake - - 5 - 10 - - - - - -
Technology & other (1) - - 35 - 45 - - - - - -
Oil Sands total 364 - 382 1,040 - 1,155
5 - 7NGLs 24 - 28
175 - 195 7.50 - 8.50 7 - 9
530 - 550
Deep Basin total 117 - 127
393 - 417Total natural gas (2) 540 - 560
483 - 510 1,215 - 1,350
180 - 200 8.00 - 9.00Marketing & transportation 0 - 10
100 - 120 Upstream DD&A ($ billions) 1.8 - 2.01.5 - 1.7 Other DD&A ($ millions) (5) 250 - 350290 - 310 Cash tax (recovery) ($ millions) (6) 0 - (50)
Effective tax rate (%) (7) 27 - 32
Brent (US$/bbl) Independent base case sensitivities Increase DecreaseWTI (US$/bbl) (for the full year 2018) ($ millions) ($ millions)Western Canada Select (US$/bbl) Crude oil (WTI) - US$1.00 change 45 (90)NYMEX (US$/MMBtu) Light-heavy differential (WTI-WCS) - US$1.00 change (125) 80AECO ($/GJ) Chicago 3-2-1 crack spread - US$1.00 change 85 (85)Chicago 3-2-1 Crack Spread (US$/bbl) Natural gas (NYMEX) - US$1.00 change 120 (110)Exchange Rate (US$/C$) Exchange rate (US$/C$) - $0.05 change (250) 245
(1) Technology & other includes Telephone Lake, and other emerging plays.(2) Natural gas includes production from the Deep Basin and Cenovus's Athabasca natural gas asset, which is not being marketed for sale.(3) Refining capital and operating costs are reported in C$, but incurred in US$ and as such will be impacted by FX.(4) Excludes anticipated 2018 severance charges related to workforce reductions.(5) Includes DD&A related to Refining and Corporate and Eliminations.(6) A portion of which will reduce tax paid on investing activities in prior years.(7) 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. (8) Sensitivities include current hedge positions applicable to the full year 2018. 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.
37.003.002.20
15.000.78
Capital expenditures Operating costs
52.00
($ millions) ($/bbl)
PRICE ASSUMPTIONS & ADJUSTED FUNDS FLOW SENSITIVITIES (8)
55.00
Refining (3)
CORPORATE
Corporate & other expenditures ($ millions)Total capital expenditures ($ billions)General & administrative expenses ($ millions) (4)
($ millions)
Total liquids
Total upstream
REFINING & MARKETING
(Mbbls/d, MMcf/d, MBOE/d)
Natural gas
TOTALProduction Capital expenditures
(MMcf/d)
($ millions) ($/bbl)Operating costs
rates (%)Effective royalty
Production
Capital expenditures
(Mbbls/d) ($ millions) ($/bbl)
DEEP BASIN
Light/Medium oil
(Mbbls/d)
2018 Corporate Guidance - C$, before royalties
UPSTREAMOIL SANDS
Production Capital expenditures Operating costs Effective royalty
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.
Investor relations contacts
Kam SandharSenior Vice-President, Strategy & Corporate [email protected]
Steven MurrayManager, Investor [email protected]
Mark AustinSenior Advisor, Investor [email protected]
Colin RonaldAnalyst, Investor [email protected]
Cenovus Energy Inc.500 Centre Street SEPO Box 766Calgary, Alberta T2P 0M5Telephone: 403.766.2000Toll free in Canada: 1.877.766.2066Fax: 403.766.7600
cenovus.com
