Cenovus Energy

2020 ANNUAL REPORT

Indigenous Housing Initiative 
Investing in, and working with, Indigenous communities near 
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development has always been part of how we do business. 

We talked to Indigenous communities about what they needed and 
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communities in northern Alberta. It’s the largest community investment 
in our company’s history and an important way for us to contribute 
meaningfully, by addressing one of the most pressing issues facing 
Indigenous communities in Canada today — lack of adequate housing. 

We’ve also partnered with Portage College, creating a training program 
to provide members of communities participating in the initiative with 
the opportunity to learn valuable trade skills that will enable them to 
take part in building and maintaining homes.

Participating communities: 
•   Beaver Lake Cree Nation
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•   Chipewyan Prairie Dene First Nation
•   Cold Lake First Nations
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•   Heart Lake First Nation

Progress in 2020 
Even with  COVID-19-related challenges, 12 homes were built in 2020 
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into their new homes in February 2021.

Our response to COVID-19  
We began to monitor and respond to the COVID-19 pandemic early  
in 2020, with dedicated teams developing and implementing proactive 
measures to protect the health and safety of our workers and the 
continuity of our business.

Cenovus established comprehensive COVID-19 protocols, including 
enhanced cleaning, physical distancing and health screening measures 
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We are impressed by the resilience and agility of our people and will 
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the appropriate protocols remain in place for as long as required based 
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TABLE OF CONTENTS

1 

2 

4 

5  

67 

78 

124 

127 

141 

OUR HISTORY

MESSAGE FROM OUR PRESIDENT  
& CHIEF EXECUTIVE OFFICER

MESSAGE FROM OUR BOARD CHAIR

MANAGEMENT’S DISCUSSION AND ANALYSIS

CONSOLIDATED FINANCIAL STATEMENTS

NOTES TO CONSOLIDATED 
FINANCIAL STATEMENTS

SUPPLEMENTAL INFORMATION

ADVISORY

INFORMATION FOR SHAREHOLDERS

For additional information about forward-looking statements, 
non-GAAP measures and reserves contained in this annual 
report, see Non-GAAP Measures and Additional Subtotals  
on page 5 and our Advisory on page 127.

 
 
WE’RE A CANADIAN-BASED INTEGRATED ENERGY COMPANY
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OUR HISTORY
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Canadians with an opportunity to participate, through share ownership,  
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operations in Western and Atlantic Canada, the United States and  
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(cid:76)(cid:81)(cid:3)(cid:21)(cid:19)(cid:19)(cid:26)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:21)(cid:19)(cid:20)(cid:26)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:79)(cid:92)(cid:17)

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)

M E S S A G E   F R O M   O U R

(cid:51)(cid:53)(cid:40)(cid:54)(cid:44)(cid:39)(cid:40)(cid:49)(cid:55)(cid:3)(cid:9)(cid:3) 
(cid:38)(cid:43)(cid:44)(cid:40)(cid:41)(cid:3)(cid:40)(cid:59)(cid:40)(cid:38)(cid:56)(cid:55)(cid:44)(cid:57)(cid:40)(cid:3)(cid:50)(cid:41)(cid:41)(cid:44)(cid:38)(cid:40)(cid:53)

(cid:44)(cid:81)(cid:3)(cid:80)(cid:68)(cid:81)(cid:92)(cid:3)(cid:90)(cid:68)(cid:92)(cid:86)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:88)(cid:81)(cid:83)(cid:85)(cid:72)(cid:70)(cid:72)(cid:71)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:76)(cid:81)(cid:71)(cid:88)(cid:86)(cid:87)(cid:85)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:69)(cid:72)(cid:74)(cid:68)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:3)(cid:82)(cid:81)(cid:3)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:3)(cid:238)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:73)(cid:82)(cid:82)(cid:87)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)(cid:75)(cid:68)(cid:89)(cid:76)(cid:81)(cid:74)(cid:3)
(cid:71)(cid:72)(cid:79)(cid:76)(cid:89)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:86)(cid:87)(cid:85)(cid:82)(cid:81)(cid:74)(cid:3)(cid:73)(cid:85)(cid:72)(cid:72)(cid:3)(cid:73)(cid:88)(cid:81)(cid:71)(cid:86)(cid:3)(cid:239)(cid:82)(cid:90)(cid:3)(cid:76)(cid:81)(cid:3)(cid:21)(cid:19)(cid:20)(cid:28)(cid:3)(cid:90)(cid:75)(cid:76)(cid:79)(cid:72)(cid:3)(cid:68)(cid:79)(cid:86)(cid:82)(cid:3)(cid:85)(cid:72)(cid:71)(cid:88)(cid:70)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
(cid:81)(cid:72)(cid:87)(cid:3)(cid:71)(cid:72)(cid:69)(cid:87)(cid:3)(cid:69)(cid:92)(cid:3)(cid:21)(cid:21)(cid:3)(cid:83)(cid:72)(cid:85)(cid:70)(cid:72)(cid:81)(cid:87)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:90)(cid:72)(cid:85)(cid:72)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:90)(cid:68)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:85)(cid:72)(cid:68)(cid:70)(cid:75)(cid:76)(cid:81)(cid:74)(cid:3)
(cid:82)(cid:88)(cid:85)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:3)(cid:74)(cid:82)(cid:68)(cid:79)(cid:86)(cid:15)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:83)(cid:72)(cid:85)(cid:73)(cid:82)(cid:85)(cid:80)(cid:3)
(cid:90)(cid:72)(cid:79)(cid:79)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:75)(cid:68)(cid:71)(cid:3)(cid:73)(cid:88)(cid:79)(cid:79)(cid:92)(cid:3)(cid:85)(cid:68)(cid:80)(cid:83)(cid:72)(cid:71)(cid:3)(cid:88)(cid:83)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:85)(cid:88)(cid:71)(cid:72)(cid:16)(cid:69)(cid:92)(cid:16)(cid:85)(cid:68)(cid:76)(cid:79)(cid:3)(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:72)(cid:3)
(cid:90)(cid:72)(cid:85)(cid:72)(cid:3)(cid:69)(cid:72)(cid:74)(cid:76)(cid:81)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:82)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:73)(cid:88)(cid:79)(cid:79)(cid:3)(cid:69)(cid:72)(cid:81)(cid:72)(cid:238)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:38)(cid:75)(cid:85)(cid:76)(cid:86)(cid:87)(cid:76)(cid:81)(cid:68)(cid:3)(cid:47)(cid:68)(cid:78)(cid:72)(cid:3)(cid:51)(cid:75)(cid:68)(cid:86)(cid:72)(cid:3)(cid:42)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:90)(cid:72)(cid:85)(cid:72)(cid:3)(cid:68)(cid:79)(cid:86)(cid:82)(cid:3)(cid:70)(cid:79)(cid:72)(cid:68)(cid:85)(cid:79)(cid:92)(cid:3)(cid:71)(cid:72)(cid:80)(cid:82)(cid:81)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)
(cid:38)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:112)(cid:86)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:86)(cid:88)(cid:86)(cid:87)(cid:68)(cid:76)(cid:81)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:17)(cid:3)(cid:44)(cid:81)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)
(cid:83)(cid:88)(cid:69)(cid:79)(cid:76)(cid:86)(cid:75)(cid:72)(cid:71)(cid:3)(cid:69)(cid:82)(cid:79)(cid:71)(cid:3)(cid:72)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:15)(cid:3)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:74)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:11)(cid:40)(cid:54)(cid:42)(cid:12)(cid:3)(cid:87)(cid:68)(cid:85)(cid:74)(cid:72)(cid:87)(cid:86)(cid:3)
(cid:76)(cid:81)(cid:3)(cid:73)(cid:82)(cid:88)(cid:85)(cid:3)(cid:78)(cid:72)(cid:92)(cid:3)(cid:68)(cid:85)(cid:72)(cid:68)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:15)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:68)(cid:80)(cid:69)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:87)(cid:82)(cid:3)
(cid:68)(cid:70)(cid:75)(cid:76)(cid:72)(cid:89)(cid:72)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:93)(cid:72)(cid:85)(cid:82)(cid:3)(cid:72)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:69)(cid:92)(cid:3)(cid:21)(cid:19)(cid:24)(cid:19)(cid:17)(cid:3)(cid:44)(cid:81)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:68)(cid:81)(cid:81)(cid:82)(cid:88)(cid:81)(cid:70)(cid:72)(cid:71)(cid:3)
(cid:82)(cid:88)(cid:85)(cid:3)(cid:44)(cid:81)(cid:71)(cid:76)(cid:74)(cid:72)(cid:81)(cid:82)(cid:88)(cid:86)(cid:3)(cid:43)(cid:82)(cid:88)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:44)(cid:81)(cid:76)(cid:87)(cid:76)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:117)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:87)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:88)(cid:81)(cid:76)(cid:87)(cid:92)(cid:3)
(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:3)(cid:38)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:112)(cid:86)(cid:3)(cid:75)(cid:76)(cid:86)(cid:87)(cid:82)(cid:85)(cid:92)(cid:17)(cid:3)(cid:44)(cid:87)(cid:112)(cid:86)(cid:3)(cid:68)(cid:81)(cid:3)(cid:76)(cid:81)(cid:76)(cid:87)(cid:76)(cid:68)(cid:79)(cid:3)(cid:238)(cid:89)(cid:72)(cid:16)(cid:92)(cid:72)(cid:68)(cid:85)(cid:15)(cid:3)(cid:7)(cid:24)(cid:19)(cid:16)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)
(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:3)(cid:87)(cid:82)(cid:3)(cid:69)(cid:88)(cid:76)(cid:79)(cid:71)(cid:3)(cid:80)(cid:88)(cid:70)(cid:75)(cid:3)(cid:81)(cid:72)(cid:72)(cid:71)(cid:72)(cid:71)(cid:3)(cid:75)(cid:82)(cid:80)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:86)(cid:76)(cid:91)(cid:3)(cid:41)(cid:76)(cid:85)(cid:86)(cid:87)(cid:3)(cid:49)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:48)(cid:197)(cid:87)(cid:76)(cid:86)(cid:3)
(cid:70)(cid:82)(cid:80)(cid:80)(cid:88)(cid:81)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:70)(cid:79)(cid:82)(cid:86)(cid:72)(cid:86)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:86)(cid:68)(cid:81)(cid:71)(cid:86)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:81)(cid:82)(cid:85)(cid:87)(cid:75)(cid:72)(cid:85)(cid:81)(cid:3)(cid:36)(cid:79)(cid:69)(cid:72)(cid:85)(cid:87)(cid:68)(cid:17)(cid:3)

(cid:55)(cid:75)(cid:72)(cid:81)(cid:15)(cid:3)(cid:72)(cid:68)(cid:85)(cid:79)(cid:92)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:15)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:80)(cid:68)(cid:70)(cid:85)(cid:82)(cid:16)(cid:72)(cid:70)(cid:82)(cid:81)(cid:82)(cid:80)(cid:76)(cid:70)(cid:3)(cid:72)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)
(cid:71)(cid:72)(cid:87)(cid:72)(cid:85)(cid:76)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:84)(cid:88)(cid:76)(cid:70)(cid:78)(cid:79)(cid:92)(cid:17)(cid:3)(cid:44)(cid:81)(cid:3)(cid:68)(cid:3)(cid:238)(cid:74)(cid:75)(cid:87)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:15)(cid:3)(cid:54)(cid:68)(cid:88)(cid:71)(cid:76)(cid:3)(cid:36)(cid:85)(cid:68)(cid:69)(cid:76)(cid:68)(cid:3)
(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:88)(cid:86)(cid:86)(cid:76)(cid:68)(cid:3)(cid:86)(cid:87)(cid:82)(cid:83)(cid:83)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:76)(cid:85)(cid:3)(cid:70)(cid:82)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:87)(cid:82)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:3)(cid:74)(cid:79)(cid:82)(cid:69)(cid:68)(cid:79)(cid:3)(cid:70)(cid:85)(cid:88)(cid:71)(cid:72)(cid:3)
(cid:82)(cid:76)(cid:79)(cid:3)(cid:86)(cid:88)(cid:83)(cid:83)(cid:79)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:50)(cid:57)(cid:44)(cid:39)(cid:16)(cid:20)(cid:28)(cid:3)(cid:75)(cid:76)(cid:87)(cid:15)(cid:3)(cid:70)(cid:68)(cid:88)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:238)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:71)(cid:72)(cid:80)(cid:68)(cid:81)(cid:71)(cid:3)
(cid:71)(cid:72)(cid:86)(cid:87)(cid:85)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:76)(cid:81)(cid:71)(cid:88)(cid:86)(cid:87)(cid:85)(cid:92)(cid:112)(cid:86)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:86)(cid:17)(cid:3)(cid:55)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:72)(cid:89)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:79)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3) 
(cid:68)(cid:3)(cid:70)(cid:82)(cid:79)(cid:79)(cid:68)(cid:83)(cid:86)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:69)(cid:72)(cid:81)(cid:70)(cid:75)(cid:80)(cid:68)(cid:85)(cid:78)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:72)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:72)(cid:74)(cid:76)(cid:81)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:73)(cid:3)
March to early May, followed by a slow and volatile recovery 
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drop in share prices across the entire energy sector, including 
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continued to deliver safe and reliable operations and 
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in the second half of the year, we restarted our crude-by-rail 
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liquidity and with the gradual recovery in oil prices towards the 
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(cid:55)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:69)(cid:76)(cid:81)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:71)(cid:71)(cid:85)(cid:72)(cid:86)(cid:86)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:85)(cid:72)(cid:72)(cid:3)(cid:78)(cid:72)(cid:92)(cid:3)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:72)(cid:74)(cid:76)(cid:70)(cid:3)(cid:83)(cid:85)(cid:76)(cid:82)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:29)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:82)(cid:3)(cid:76)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:86)(cid:87)(cid:3)(cid:86)(cid:87)(cid:85)(cid:88)(cid:70)(cid:87)(cid:88)(cid:85)(cid:72)(cid:15)(cid:3)(cid:72)(cid:81)(cid:75)(cid:68)(cid:81)(cid:70)(cid:76)(cid:81)(cid:74)(cid:3)
(cid:82)(cid:88)(cid:85)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:3)(cid:68)(cid:70)(cid:70)(cid:72)(cid:86)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:71)(cid:72)(cid:79)(cid:72)(cid:89)(cid:72)(cid:85)(cid:68)(cid:74)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:17)(cid:3)

(cid:44)(cid:81)(cid:3)(cid:21)(cid:19)(cid:21)(cid:20)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:70)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:68)(cid:70)(cid:75)(cid:76)(cid:72)(cid:89)(cid:72)(cid:3)(cid:81)(cid:72)(cid:68)(cid:85)(cid:79)(cid:92)(cid:3)(cid:7)(cid:20)(cid:3)(cid:69)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:86)(cid:92)(cid:81)(cid:72)(cid:85)(cid:74)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)
(cid:83)(cid:88)(cid:87)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:88)(cid:86)(cid:3)(cid:238)(cid:85)(cid:80)(cid:79)(cid:92)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:85)(cid:68)(cid:70)(cid:78)(cid:3)(cid:87)(cid:82)(cid:3)(cid:85)(cid:72)(cid:68)(cid:70)(cid:75)(cid:3)(cid:68)(cid:87)(cid:3)(cid:79)(cid:72)(cid:68)(cid:86)(cid:87)(cid:3)(cid:7)(cid:20)(cid:17)(cid:21)(cid:3)(cid:69)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:3)(cid:68)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)
(cid:85)(cid:88)(cid:81)(cid:16)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:86)(cid:92)(cid:81)(cid:72)(cid:85)(cid:74)(cid:76)(cid:72)(cid:86)(cid:17)(cid:3)(cid:50)(cid:88)(cid:85)(cid:3)(cid:86)(cid:87)(cid:85)(cid:82)(cid:81)(cid:74)(cid:3)(cid:83)(cid:82)(cid:85)(cid:87)(cid:73)(cid:82)(cid:79)(cid:76)(cid:82)(cid:3)(cid:82)(cid:73)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:16)(cid:80)(cid:68)(cid:87)(cid:70)(cid:75)(cid:72)(cid:71)(cid:3)

(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:55)(cid:50)(cid:55)(cid:36)(cid:47)(cid:3)(cid:54)(cid:43)(cid:36)(cid:53)(cid:40)(cid:43)(cid:50)(cid:47)(cid:39)(cid:40)(cid:53)(cid:3)(cid:53)(cid:40)(cid:55)(cid:56)(cid:53)(cid:49)

$120

$110

$100

$90

$80

$70

$60

$50

$40

$30

$20

$10

$-

(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:28)

(cid:48)(cid:68)(cid:85)(cid:70)(cid:75)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)

(cid:45)(cid:88)(cid:81)(cid:72)(cid:3)(cid:22)(cid:19)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)

(cid:54)(cid:72)(cid:83)(cid:87)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:19)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)

(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)

(cid:38)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)(cid:11)(cid:55)(cid:54)(cid:59)(cid:12)

(cid:54)(cid:9)(cid:51)(cid:18)(cid:55)(cid:54)(cid:59)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:72)(cid:3)(cid:44)(cid:81)(cid:71)(cid:72)(cid:91)

(cid:54)(cid:9)(cid:51)(cid:18)(cid:55)(cid:54)(cid:59)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)(cid:44)(cid:81)(cid:71)(cid:72)(cid:91)

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(cid:54)(cid:43)(cid:36)(cid:53)(cid:40)(cid:3)(cid:51)(cid:53)(cid:44)(cid:38)(cid:40)(cid:3)(cid:51)(cid:40)(cid:53)(cid:41)(cid:50)(cid:53)(cid:48)(cid:36)(cid:49)(cid:38)(cid:40)(cid:3)(cid:41)(cid:50)(cid:47)(cid:47)(cid:50)(cid:58)(cid:44)(cid:49)(cid:42)(cid:3)(cid:43)(cid:56)(cid:54)(cid:46)(cid:60)(cid:3)(cid:55)(cid:53)(cid:36)(cid:49)(cid:54)(cid:36)(cid:38)(cid:55)(cid:44)(cid:50)(cid:49)

120%

100%

80%

60%

40%

20%

0%

-20%

(cid:50)(cid:70)(cid:87)(cid:82)(cid:69)(cid:72)(cid:85)(cid:3)(cid:21)(cid:22)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)

(cid:49)(cid:82)(cid:89)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:21)(cid:26)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)

(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:21)(cid:24)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)

(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:21)(cid:28)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:20)

(cid:41)(cid:72)(cid:69)(cid:85)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:21)(cid:25)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:20)

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Oil Sands Peers

Integrated Peers

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(cid:70)(cid:85)(cid:72)(cid:68)(cid:87)(cid:72)(cid:86)(cid:3)(cid:68)(cid:3)(cid:74)(cid:79)(cid:82)(cid:69)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:72)(cid:87)(cid:76)(cid:87)(cid:82)(cid:85)(cid:3)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:82)(cid:83)(cid:87)(cid:76)(cid:80)(cid:76)(cid:93)(cid:72)(cid:3)(cid:80)(cid:68)(cid:85)(cid:74)(cid:76)(cid:81)(cid:3)(cid:70)(cid:68)(cid:83)(cid:87)(cid:88)(cid:85)(cid:72)(cid:3)
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allowing us to accelerate the deleveraging of our balance sheet 
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/s/ Alex Pourbaix 
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M E S S A G E   F R O M   O U R

BOARD CHAIR

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operating plans to preserve liquidity, while also strategically 
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also reviewed several alternatives available to Cenovus, including 
continuing to operate as a standalone entity, and incorporated the 
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integrated oil and natural gas producer than we were a year ago, 
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/s/ Keith MacPhail 
Board Chair

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MANAGEMENT’S DISCUSSION AND ANALYSIS
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ESTIMATION UNCERTAINTIES AND  
ACCOUNTING POLICIES

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website at (cid:70)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:17)(cid:70)(cid:82)(cid:80)(cid:17)(cid:3)(cid:44)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:81)(cid:72)(cid:70)(cid:87)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:90)(cid:72)(cid:69)(cid:86)(cid:76)(cid:87)(cid:72)(cid:15)(cid:3)(cid:72)(cid:89)(cid:72)(cid:81)(cid:3)(cid:76)(cid:73)(cid:3)(cid:85)(cid:72)(cid:73)(cid:72)(cid:85)(cid:85)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:48)(cid:39)(cid:9)(cid:36)(cid:15)(cid:3)(cid:71)(cid:82)(cid:72)(cid:86)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:87)(cid:76)(cid:87)(cid:88)(cid:87)(cid:72)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:48)(cid:39)(cid:9)(cid:36)(cid:17)(cid:3)

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Basis of Presentation  
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(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:86)(cid:3)(cid:37)(cid:82)(cid:68)(cid:85)(cid:71)(cid:3)(cid:11)(cid:113)(cid:44)(cid:36)(cid:54)(cid:37)(cid:114)(cid:12)(cid:17)(cid:3)(cid:51)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:89)(cid:82)(cid:79)(cid:88)(cid:80)(cid:72)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:68)(cid:3)(cid:69)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)(cid:3)(cid:85)(cid:82)(cid:92)(cid:68)(cid:79)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:69)(cid:68)(cid:86)(cid:76)(cid:86)(cid:17)(cid:3)

Non-GAAP Measures and Additional Subtotals  
(cid:38)(cid:72)(cid:85)(cid:87)(cid:68)(cid:76)(cid:81)(cid:3)(cid:238)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:71)(cid:82)(cid:70)(cid:88)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:71)(cid:82)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:68)(cid:3)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:80)(cid:72)(cid:68)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:70)(cid:85)(cid:76)(cid:69)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:44)(cid:41)(cid:53)(cid:54)(cid:15)(cid:3)(cid:86)(cid:88)(cid:70)(cid:75)(cid:3)(cid:68)(cid:86)(cid:3)(cid:49)(cid:72)(cid:87)(cid:69)(cid:68)(cid:70)(cid:78)(cid:86)(cid:15)(cid:3)(cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:41)(cid:88)(cid:81)(cid:71)(cid:86)(cid:3)(cid:41)(cid:79)(cid:82)(cid:90)(cid:15)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:40)(cid:68)(cid:85)(cid:81)(cid:76)(cid:81)(cid:74)(cid:86)(cid:15)(cid:3)(cid:41)(cid:85)(cid:72)(cid:72)(cid:3)(cid:41)(cid:88)(cid:81)(cid:71)(cid:86)(cid:3)
(cid:41)(cid:79)(cid:82)(cid:90)(cid:15)(cid:3)(cid:49)(cid:72)(cid:87)(cid:3)(cid:39)(cid:72)(cid:69)(cid:87)(cid:15)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:76)(cid:93)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:40)(cid:68)(cid:85)(cid:81)(cid:76)(cid:81)(cid:74)(cid:86)(cid:3)(cid:37)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)(cid:3)(cid:44)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:15)(cid:3)(cid:55)(cid:68)(cid:91)(cid:72)(cid:86)(cid:15)(cid:3)(cid:39)(cid:72)(cid:83)(cid:85)(cid:72)(cid:70)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:80)(cid:82)(cid:85)(cid:87)(cid:76)(cid:93)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:11)(cid:113)(cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:40)(cid:37)(cid:44)(cid:55)(cid:39)(cid:36)(cid:114)(cid:12)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:85)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)
(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:17)(cid:3)(cid:44)(cid:81)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:48)(cid:68)(cid:85)(cid:74)(cid:76)(cid:81)(cid:3)(cid:76)(cid:86)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:68)(cid:81)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:86)(cid:88)(cid:69)(cid:87)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:73)(cid:82)(cid:88)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:3)(cid:20)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:38)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:17)(cid:3)(cid:55)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:80)(cid:68)(cid:92)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:69)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:85)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)
(cid:87)(cid:82)(cid:3)(cid:86)(cid:76)(cid:80)(cid:76)(cid:79)(cid:68)(cid:85)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:76)(cid:86)(cid:86)(cid:88)(cid:72)(cid:85)(cid:86)(cid:17)(cid:3)(cid:55)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:69)(cid:72)(cid:72)(cid:81)(cid:3)(cid:71)(cid:72)(cid:86)(cid:70)(cid:85)(cid:76)(cid:69)(cid:72)(cid:71)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:82)(cid:85)(cid:71)(cid:72)(cid:85)(cid:3)(cid:87)(cid:82)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:82)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)
(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:68)(cid:81)(cid:68)(cid:79)(cid:92)(cid:93)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:74)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:73)(cid:88)(cid:81)(cid:71)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:238)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:85)(cid:72)(cid:74)(cid:68)(cid:85)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:79)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:76)(cid:87)(cid:92)(cid:17)(cid:3)(cid:55)(cid:75)(cid:76)(cid:86)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:86)(cid:75)(cid:82)(cid:88)(cid:79)(cid:71)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:69)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3) 
(cid:76)(cid:81)(cid:3)(cid:76)(cid:86)(cid:82)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:85)(cid:3)(cid:68)(cid:86)(cid:3)(cid:68)(cid:3)(cid:86)(cid:88)(cid:69)(cid:86)(cid:87)(cid:76)(cid:87)(cid:88)(cid:87)(cid:72)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:83)(cid:68)(cid:85)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:85)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:44)(cid:41)(cid:53)(cid:54)(cid:17)(cid:3)

(cid:55)(cid:75)(cid:72)(cid:3)(cid:71)(cid:72)(cid:238)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:81)(cid:70)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:76)(cid:73)(cid:3)(cid:68)(cid:83)(cid:83)(cid:79)(cid:76)(cid:70)(cid:68)(cid:69)(cid:79)(cid:72)(cid:15)(cid:3)(cid:82)(cid:73)(cid:3)(cid:72)(cid:68)(cid:70)(cid:75)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:3)(cid:82)(cid:85)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:86)(cid:88)(cid:69)(cid:87)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:76)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:15)(cid:3)(cid:47)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:76)(cid:87)(cid:92)(cid:3) 
(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:48)(cid:39)(cid:9)(cid:36)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:49)(cid:72)(cid:87)(cid:69)(cid:68)(cid:70)(cid:78)(cid:3)(cid:53)(cid:72)(cid:70)(cid:82)(cid:81)(cid:70)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:82)(cid:81)(cid:3)(cid:83)(cid:68)(cid:74)(cid:72)(cid:3)(cid:20)(cid:22)(cid:21)(cid:17)(cid:3)

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OVERVIEW OF CENOVUS  

We  are  a  Canadian-based  integrated  oil  and  natural  gas  company  headquartered  in  Calgary,  Alberta,  with  our 
shares  listed  on  the  Toronto  and  New  York  stock  exchanges.  At  December 31, 2020,  prior  to  the  close  of  the 
transaction  with  Husky  on  January 1, 2021,  as  described  below,  our  operations  included  oil  sands  projects  in 
northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and 
British  Columbia.  Total  production  from  our  upstream  assets  averaged  approximately  472,000 BOE  per  day  in 
2020.  We  also  conducted  marketing  activities  and  have  ownership  interest  in  refining  operations  in  the  United 
States (“U.S.”). The refineries processed an average of 372,000 gross barrels per day of crude oil feedstock into an 
average of 385,000 gross barrels per day of refined products in 2020. 

For a description of our operations in 2020, refer to the Reportable Segments section of this MD&A. 

Cenovus and Husky Arrangement 

On October 24, 2020, Cenovus and Husky entered into a definitive agreement to combine the two companies in an 
all-stock  transaction  to  create  a  resilient  Canadian-based  integrated  energy  company.  The  transaction  was 
accomplished  through  a  plan  of  arrangement  (“the  Arrangement”)  pursuant  to  which  Cenovus  acquired  all  the 
issued  and  outstanding  common  shares  of  Husky  in  exchange  for  common  shares  and  common  share  purchase 
warrants  of  Cenovus.  In  addition,  all  of  the  issued  and  outstanding  Husky  preferred  shares  were  exchanged  for 
Cenovus  preferred  shares  with  substantially  identical  terms.  The  Arrangement  closed  on  January 1, 2021  and  we 
continue to operate as Cenovus, trade under the Cenovus name, and remain headquartered in Calgary, Alberta. 

The Arrangement combines high quality oil sands and heavy oil assets with extensive trading, supply and logistics 
infrastructure,  and  downstream  infrastructure,  creating  opportunities  to  optimize  the  margin  captured  across  the 
heavy  oil  value  chain.  With  the  combination  of  processing  capacity  and  market  access  outside  Alberta  for  the 
majority  of  the  Company’s  oil  sands  and  heavy  oil  production,  exposure  to  Alberta  heavy  oil  price  differentials  is 
reduced  while  maintaining  exposure  to  global  commodity  prices.  The  combined  company  has  a  cost-and-market-
advantaged  asset  portfolio,  which  prioritizes  free  funds  flow  generation,  balance  sheet  strength  and  returns  to 
shareholders. 

The combined company is the third largest Canadian oil and natural gas producer and the second largest Canadian-
based refiner and upgrader with operations in Canada, the U.S. and the Asia Pacific region. Our operations include 
oil sands projects in northern Alberta, thermal and conventional crude oil and natural gas projects across Western 
Canada, crude oil production offshore Newfoundland and Labrador and natural gas and liquids production offshore 
China and Indonesia. Our downstream operations include upgrading, refining and marketing operations in Canada 
and the U.S. 

Management  is  in  the  process  of  finalizing  the  determination  of  the  operating  and  reporting  segments  for  the 
Company. It is anticipated that the Company’s business will be conducted predominately through an upstream and 
downstream  segment.  Management  continues  to  evaluate  how  the  segments  may  be  presented  and  will  make  a 
final determination during the first quarter of 2021. 

The Upstream business is anticipated to be reported as follows: 

(cid:120)

(cid:120)

(cid:120)

Oil Sands, includes the development and production of heavy oil and bitumen in northeast Alberta and 
Saskatchewan.  Cenovus’s  oil  sands  assets  include  Foster  Creek,  Christina  Lake,  Sunrise  and  Tucker  oil 
sands projects, as well as Lloydminster Thermal and Cold and Enhanced Oil Recovery assets. 

Conventional,  includes  the  operations  from  conventional  oil  and  natural  gas  production,  including 
processing operations in the Deep Basin and other parts of Western Canada. 

Offshore,  includes  the  offshore  operations,  exploration  and  development  activities  in  the  Asia  Pacific 
region and Atlantic Canada region. 

The Downstream business is anticipated to be reported under the following segments: 

(cid:120)

(cid:120)

(cid:120)

Canadian  Manufacturing,  includes  Cenovus’s  owned  and  operated  upgrader  and  asphalt  refinery  in 
Lloydminster, the owned and operated crude-by-rail terminal and two ethanol plants.  

Retail, includes the Canadian retail, commercial and wholesale channels. 

U.S.  Manufacturing,  includes  the  U.S.  operations  of  wholly  owned  refineries  in  Lima  and  Superior,  the 
jointly  owned  Wood  River  and  Borger  refineries  with  operator  Phillips  66  and  the  jointly  owned  Toledo 
refinery with BP Products North America Inc. as operator. 

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Our Strategy 

Our  strategy  remains  focused  on  maximizing  shareholder  value  through  cost  leadership  and  realizing  the  best 
margins for our products. Our diverse and integrated portfolio will help us to deliver stable cash flow through price 
cycles  while  maintaining  safe  and  reliable  operations.  We  remain  focused  on  sustainably  growing  shareholder 
returns  and  reducing  Net  Debt.  The  diverse  portfolio  of  projects  and  other  opportunities  across  our  business  are 
expected  to  allow  us  to  leverage  increased  economies  of scale  to  better  compete  in  an  increasingly  consolidated 
energy  industry.  We  believe  that  maintaining  a  strong  balance  sheet  will  help  Cenovus  navigate  through 
commodity price volatility. We  plan to use our capital allocation framework to evaluate disciplined investments in 
our  portfolio  against  dividends,  share  repurchases  and  managing  to  the  optimal  debt  level  while  maintaining 
investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive 
advantage  to  generate  the  highest  returns  and  incorporate  Environmental,  Social  and  Governance  (“ESG”) 
considerations into our business plan. 

On January 28, 2021 we announced the 2021 budget for the combined company focused on sustaining capital and 
generating free funds flow to strengthen the balance sheet, accelerated by capturing transaction-related synergies 
across the organization. 2021 guidance dated January 28, 2021 is available on our website at cenovus.com. 

Additional  information  on  the  Arrangement  is  available  in  our  news  releases,  dated  October 25, 2020  and 
January 4, 2021  available  on SEDAR  at  sedar.com,  on  EDGAR  at  sec.gov,  and on our website  at  cenovus.com,  in 
our  joint  management  information  circular  with  Husky  dated  November 9, 2020  available  on  SEDAR  and  EDGAR, 
and  in  our  material  change  reports  dated  November 3, 2020  and  January 11, 2021  available  on  SEDAR  and 
EDGAR. The information in this MD&A, as it relates to our operations for 2020, does not reflect the closing of the 
Arrangement, unless otherwise noted. 

LOW OIL PRICES AND THE NOVEL CORONAVIRUS (”COVID-19”) 

2020 was a challenging year due to the significant decrease in crude oil demand due to COVID-19 resulting in the 
low global oil price environment. 

During the first half of the year, there was a significant reduction in crude oil demand as a result of measures taken 
by  governments  around  the  world  to  contain  the  COVID-19  pandemic.  At  the  same  time,  overall  global  crude  oil 
supply  increased  as  efforts  between  the  Organization  of  Petroleum  Exporting  Countries  (“OPEC”)  and  non-OPEC 
members,  primarily  Saudi  Arabia  and  Russia,  to  manage  global  crude  oil  production  levels  broke  down  and  each 
party  increased  their  daily  crude  production.  The  combination  of  these  events  resulted  in  a  collapse  of  crude  oil 
low  of 
benchmark  prices,  dropping  to  a 
negative US$37.63 per barrel on April 20, 2020. 

low  of  US$10.01 per barrel,  excluding  a  historic  one-day 

In light of these unprecedented conditions, we reduced our planned capital investment plan, operating costs, and 
general and administrative (“G&A”) costs. We remained focused on enhancing our financial resilience and financial 
capability to maintain our base business and deliver safe and reliable operations. 

In April, the agreement between OPEC and a group of 10 non-OPEC members (collectively, “OPEC+”) to cut crude 
oil output, and several other countries announcing similar production cuts decreased the global supply of crude oil. 
At  the  same  time,  governments  began  to  ease  off  on  some  of  the  measures  taken  to  contain  the  pandemic 
increasing demand for crude oil, which helped increase crude oil prices.  

In  the  second  half  of  2020,  crude  oil  prices  improved  from  the  low  prices  impacting  the  first  half  of  the  year; 
however,  prices  continued  to  be  volatile  due  to  market  responses  to  COVID-19  and  OPEC  crude  oil  production 
output decisions.  Volatility  of  crude oil prices  continued  in  the fourth  quarter,  responding  to  news of COVID-19 
vaccine  breakthroughs,  continued  OPEC  and  OPEC+  output  restrictions,  and  government  responses  to  the 
resurgence of COVID-19 cases. 

We  believe  that  we  have  ample  liquidity  and  runway  to  sustain  our  operations  through  a  prolonged  market 
downturn.  Following  the  closing  of  the  Arrangement  on  January 1, 2021,  Cenovus  has  $8.5 billion  in  committed 
credit  facilities,  with  $2.0 billion  maturing  in  June 2022,  $1.2 billion  maturing  in  November 2022,  $3.3 billion 
maturing  in  November 2023,  and  $2.0 billion  maturing  in  March 2024.  Under  the  terms  of  Cenovus’s  committed 
credit  facilities,  the  Company  is  required  to  maintain  a  debt  to  capitalization  ratio,  as  defined  in  the  agreement 
governing  the credit  facilities,  not  to  exceed  65 percent.  As  at  December 31, 2020,  the Company  was  well  below 
this limit and we expect to continue to be in compliance with all financial covenants under the credit facilities. 

The  Provincial  and  Federal  governments  have  recognized  the  serious  economic  impacts  of  COVID-19  and  have 
taken steps to provide various programs, such as the Canada Emergency Wage Subsidy (“CEWS”) program. During 
the  year  we  continued  to  benefit  from  the  assistance  of  the  CEWS  program  to  help  protect  jobs  during  the 
pandemic. 

The Company remains committed to the health and safety of its workforce and the public while providing essential 
services. Physical distancing measures continue to be taken to maintain the health and safety of our people and to 
help  mitigate  the  risk  of  COVID-19  at  our  workplaces.  We  continue  to  monitor  the  changing  COVID-19  situation 
and  respond  accordingly  in  a  timely  manner.  In  October,  we  lifted  our  mandatory  work  from  home  measure, 

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implemented in March, to open our modified workspaces in the Calgary offices to staff again, with workplace safety 
plans and protocols in place. However, due to rising COVID-19 cases in November this was scaled back and office 
staff  are  once  again  required  to  work  from  home.  Mandatory  work-from-home  measures  are  now  in  place  for  all 
non-essential staff at our combined offices and worksites in Alberta, Saskatchewan and Manitoba until the end of 
March  2021,  pending  further  review.  Our  U.S.  and  Atlantic  Canada  locations  will  continue  to  take  direction  from 
local  health  authorities  regarding  their  COVID-19  workplace  mandates.  Staff  levels  at  sites  and  offices  have  and 
will  continue  to follow guidance received from  the  applicable  federal,  provincial,  state  and  local  governments  and 
public health officials. 

YEAR IN REVIEW 

During  2020,  operating  variables  under  Management’s  control  performed  well.  We  focused  on  delivering  value 
through  preserving  financial  resilience.  Throughout  the  year,  we  demonstrated  our  ability  to  use  our  full  suite  of 
assets to maximize prices received for every barrel as we adjusted our Oil Sands production rates in response to 
price  signals  and  stored  volumes  in  a  low-price  environment  and  cleared  inventory  when  we  could  obtain  higher 
prices. We also remained focused on maintaining our low cost structure. 

Operationally,  our  upstream  assets  performed  well.  Our  upstream  production  averaged  471,740 BOE per day  in 
2020,  compared  with  451,680 BOE per day  in  2019.  In  2020  we  managed  our  production  to  optimal  levels, 
producing  above  the  Government  of  Alberta’s  mandatory  production  curtailment  as  we  purchased  additional 
credits. As of December 2020, monthly oil production limits are no longer in effect and the Government of Alberta 
will give 30 to 60 days’ notice if production limits are put back into place. 

The  Wood  River  and  Borger  refineries  (the  “Refineries”)  demonstrated  reliable  operational  performance  while 
operating below capacity for the majority of the year due to economic crude rate reductions in response to lower 
refined product demand and weak market crack spreads. 

Throughout 2020, Management continued to focus on maintaining our low operating and capital cost structure. 

Crude oil prices were volatile throughout the year due to demand and supply impacts as a result of COVID-19 and 
OPEC and non-OPEC members production level commitments. West Texas Intermediate (“WTI”) benchmark crude 
oil  prices  ranged  from  a  high  of  US$63.27 per barrel  to  a  low  of  US$10.01 per barrel  and  averaged  31 percent 
lower  than  2019.  Western  Canadian  Select  (“WCS”)  benchmark  prices  averaged  US$26.80 per barrel,  39 percent 
lower than US$44.27 per barrel in 2019. Our average realized crude oil sales price of $28.82 per barrel decreased 
significantly compared with $53.95 per barrel in 2019 due to declining benchmark WTI prices. 

As noted, COVID-19 had a significant impact on our results. 

(cid:120)

(cid:120)

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(cid:120)

Our first quarter results were impacted by measures taken to contain COVID-19 and the over-supply of crude 
oil. We responded by announcing reductions to our capital spending, operating and G&A costs, and temporarily 
suspended  our  dividend.  Average  WTI  and  WCS  crude  oil  benchmark  prices  for  the  first  quarter  declined  to 
US$46.17 per barrel and US$25.64 per barrel, respectively, which had a significant impact on our first quarter 
results with asset impairment charges of $318 million, a Net Loss of $1,797 million and our operating margin 
was negative $589 million; 
The second quarter was a transition period for the market. Crude oil prices were severely impacted, with WCS 
averaging a low of US$3.50 per barrel in April. This was followed by a steady strengthening of crude oil prices 
with WCS averaging US$33.97 per barrel in June, caused by the easing of some of the restrictions imposed by 
governments  to  limit  the  spread  of  COVID-19  combined  with  the  commitment  by  OPEC  and  non-OPEC 
members  to  reduce  crude  oil  production  levels  in  response  to  lower  demand  and  low  commodity  prices.  We 
responded  to  price  signals,  managing  our  Oil  Sands  production  by  reducing  production  rates  in  April  and 
successfully ramped up production in May and June, to achieve peak production rates, when pricing was more 
favourable. Our Net Loss of $235 million improved in the second quarter compared with the first quarter and 
our operating margin was $291 million, demonstrating some momentum in economic recovery; 
Our results  in  the  third  quarter  gradually  improved  along with  the  improvement  in  crude  oil prices.  WTI  and 
WCS  averaged  US$40.93 per barrel  and  US$31.84 per barrel,  respectively,  in  the  third  quarter.  However, 
crude oil prices remained low as the second wave of COVID-19 infections drove uncertainty. Operationally, our 
upstream  assets  continued  to  perform  well  and  in  response  to  increasing  crude  oil  prices,  we  purchased 
production curtailment credits available in the market to produce above our curtailment limit and sold crude oil 
inventory  that  had  built  up  when  crude  oil  prices  were  lower.  Our  Net  Loss  of  $194 million,  which  included 
impairments and write-downs of $521 million, continued to improve quarter over quarter and operating margin 
of  $594 million  more  than  doubled  that  of  the  second  quarter  of  2020.  In  the  third  quarter  we  used  the 
proceeds  from  the  issuance  of  US$1.0 billion  in  5.375 percent  senior  unsecured  notes  due  in  2025  to  repay 
short-term borrowings; and 
Our  fourth  quarter  results  were  mixed  as  COVID-19  infection  rates,  global  economic  performance  and 
speculation  on  vaccine  development  impacted  the  pace  of  crude  oil  demand  recovery  with  WTI  and  WCS 
averaging  US$42.66 per barrel  and  US$33.36 per barrel,  respectively.  Our  fourth  quarter  Net  Loss  of 
$153 million  decreased  and  operating  margin  of  $625 million  increased  compared  with  the  third  quarter  of 

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2020,  and  we  recognized  $298 million  in  impairments  and  write-downs.  Net  income  also  included  a 
$100 million loss related to the Keystone XL pipeline project. We exited the year with Net Debt of $7.2 billion. 

In 2020, upstream operating margin of $1,309 million decreased compared with $3,723 million in 2019, due to a 
lower average realized crude oil sales price, the use of higher priced condensate in a declining market earlier in the 
year, partially offset by lower royalties and higher sales volumes. 

Our Refining and Marketing segment generated operating margin of negative $388 million, down from $737 million 
in  2019  primarily  due  to  decreased  market  crack  spreads,  lower  crude  advantage  and  reduced  crude  oil  runs, 
partially offset by lower operating costs. 

OPERATING AND FINANCIAL RESULTS 

Selected Operating Results 

Upstream Production Volumes 

Oil Sands (barrels per day)

Foster Creek 

Christina Lake 

Total Oil Sands Crude Oil 

2020     

Percent 
Change     

2019     

Percent 
Change     

2018  

   163,210       

   218,513       

   381,723       

2        159,598       
12        194,659       
8        354,257       

(1 )      161,979  
(3 )      201,017  
(2 )      362,996  

Conventional (1) (BOE per day)

   89,932       

(8 )     

97,423       

(19 )      120,258  

Total Production from Continuing Operations (BOE per day)    471,740       

4        451,680       

(7 )      483,458  

Production From Discontinued Operations (BOE per day)

-       

-       

-       

(100 )     

294  

Sales from Continuing Operations (2) (BOE per day)

   420,456       

8        390,813       

(10 )      436,163  

Oil and Gas Reserves (MMBOE)

Proved 

Probable 

Proved plus Probable 

Refining and Marketing 

Crude Oil Runs (3) (Mbbls/d)
Refined Product (3) (Mbbls/d)
Crude Utilization (3) (percent)

Crude-by-Rail (barrels per day)

Crude-by-Rail Loads (4)
Crude-by-Rail Sales (5)

5,030       

1,656       

6,686       

(1 )     

(6 )     

(3 )     

5,103       
1,768       
6,871       

(1 )     
(3 )     
(2 )     

5,167  

1,821  

6,988  

372       

385       

75       

(16 )     

(17 )     

(17 )     

443       
466       
92       

(1 )     
(1 )     
(5 )     

446  

470  

97  

   30,422       

   33,870       

(43 )     

(30 )     

53,345       
48,626       

1,197       
1,367       

4,113  

3,314   

(1)
(2)
(3)
(4)
(5)

This segment was previously referred to as the Deep Basin segment. 
Less natural gas volumes used for internal consumption by the Oil Sands segment. 
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent. 
Represents volumes transported outside of Alberta. 
Represents volumes sold outside of Alberta. 

Upstream Production Volumes 

Oil Sands production for 2020 reflects production above our curtailment limit as we managed to optimal production 
levels  by  purchasing  production  curtailment  credits.  In  2019,  our  production  was  in  line  with  the  Government  of 
Alberta’s  mandatory  production  curtailment  program  and  impacted  by  a  planned  turnaround  at  Christina  Lake 
during the second quarter of 2019. 

Conventional  production  in  2020  decreased  to  89,932 BOE per day  compared  with  97,423 BOE per day  in  2019, 
due to natural declines, partially offset by Marten Hills heavy oil production prior to its disposition, as well as fewer 
shut-ins  for  low  commodity  pricing.  Prior  to  the  disposition,  Marten  Hills  production  averaged  approximately 
2,800 barrels per day. 

Oil and Gas Reserves 

Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2020 
we  had  total  proved  reserves  and  total  proved  plus  probable  reserves  of  approximately  5.0 billion BOE  and 
6.7 billion BOE,  respectively,  decreases  of  one percent  and  three percent  compared  with  2019.  As  a  result  of  the 
close of  the Arrangement  on  January 1, 2021,  including reported reserves from  Husky,  our  total  proved  reserves 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:28)

 
  
    
    
    
    
    
    
   
    
    
  
    
    
    
    
    
    
   
    
    
  
  
       
       
       
       
  
  
  
       
       
       
       
  
  
  
    
  
  
    
  
  
    
  
  
   
  
  
    
  
  
  
       
       
       
       
  
  
  
       
       
       
       
  
  
       
       
       
       
  
  
  
  
  
  
       
       
       
       
  
  
    
    
    
    
    
    
   
    
    
  
  
  
  
  
       
       
       
       
  
  
       
       
       
       
  
and  total  proved  plus  probable  reserves  are  anticipated  to  increase  by  approximately  1.2 billion BOE  and 
1.8 billion BOE, respectively. 

Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. 

Refining and Marketing 

Crude oil runs and refined product output decreased in 2020 as both Refineries implemented crude rate reductions 
in response to reduced demand as a result of COVID-19. The economic crude rate reductions in 2020 had a greater 
impact  than  the  operational performance  impacts  from  unplanned outages, planned  maintenance  and  turnaround 
activities at the Refineries in 2019. 

Further information on the changes in our financial and operating results can be found in the Reportable Segments 
section of this MD&A. Further information on our risk management activities can be found in the Risk Management 
and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements. 

Selected Consolidated Financial Results 

Market  factors  such  as  falling  crude  oil  prices,  low  market  crack  spreads,  and  volatile  blending  costs  were  the 
primary  drivers  of  our  financial  results.  The  following  key  performance  measures  are  discussed  in  more  detail 
within this MD&A.  

($ millions, except per share amounts) 

Operating Margin (2) (3)

Cash From (Used in) Operating Activities 

From Continuing Operations 

Total 

Adjusted Funds Flow (4)

Operating Earnings (loss) (2) (4)

Per Share ($) (5)

Net Earnings (Loss) 

From Continuing Operations 

Per Share ($) (5)

Total 

Per Share ($) (5)

Total Assets 

2020     

Percent 
Change     

2019     

Percent 
Change     

2018 (1)

921       

(79 )     

4,460       

86       

2,394   

273       

(92 )     

3,285       

273       

(92 )     

3,285       

55       

53       

2,118   

2,154   

147       

(96 )     

3,702       

115       

1,721   

(2,604 )     
(2.12 )     

(671 )     
(673 )     

456       
0.37       

117       
117       

(2,755 ) 

(2.24 ) 

(2,379 )     
(1.94 )     

(2,379 )     
(1.94 )     

(208 )     
(209 )     

(208 )     
(209 )     

2,194       
1.78       

2,194       
1.78       

175       
175       

182       
182       

(2,916 ) 

(2.37 ) 

(2,669 ) 

(2.17 ) 

   32,770       

(7 )     

35,173       

-       

35,174   

Total Long-Term Financial Liabilities (6)

9,041       

7       

8,483       

(1 )     

8,602   

Capital Investment (7)

Dividends 

Cash Dividends 

Per Share ($)

841       

(28 )     

1,176       

(14 )     

1,363   

77       
   0.0625       

(70 )     
(71 )     

260       
0.2125       

6       
6       

245   

0.2000   

(1)

(2)
(3)
(4)

(5)
(6)

(7)

On January 1, 2019, we adopted IFRS 16, “Leases” (“IFRS 16”), using the modified retrospective approach; therefore, comparative information has 
not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in our 2019 annual MD&A. 
Represented on a continuing basis. 
Additional subtotal found in Note 1 of the Consolidated Financial Statements and defined in this MD&A. 
Non-GAAP measure defined in this MD&A. The comparative periods have been reclassified to conform with the current period treatment of non-cash 
inventory write-downs and reversals. 
Represented on a basic and diluted per share basis. 
Includes  Long-Term  Debt,  Lease  Liabilities,  Contingent  Payment  Liabilities  and  other  financial  liabilities  included  within  Other  Liabilities  on  the 
Consolidated Balance Sheets. 
Includes expenditures on property, plant and equipment (“PP&E”) and Exploration and Evaluation (“E&E”) assets. 

(cid:20)(cid:19)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
  
  
    
    
    
    
    
    
    
    
   
  
  
  
    
    
    
    
    
    
    
    
   
  
       
       
       
       
   
  
  
  
    
    
    
    
    
    
    
    
   
  
  
  
    
    
    
    
    
    
    
    
   
  
  
  
    
    
    
    
    
    
    
    
   
  
  
  
  
    
    
    
    
    
    
    
    
   
  
       
       
       
       
   
  
  
  
  
    
    
    
    
    
    
    
    
   
  
  
  
  
    
    
    
    
    
    
    
    
   
  
  
    
    
    
    
    
    
    
    
   
  
  
  
    
    
    
    
    
    
    
    
   
  
  
  
    
    
    
    
    
    
    
    
   
  
       
       
       
       
   
  
 
Operating Margin 

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 our underlying 
financial  performance  between  periods.  Operating  Margin  is  defined  as  revenues  less  purchased  product, 
transportation and blending, operating  expenses, inventory write-downs, net of reversals, 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. 

($ millions) 

Gross Sales 

Less: Royalties 

Revenues 

Expenses 

Purchased Product 
Transportation and Blending 

Operating Expenses 

Inventory Write-Down (Reversal) 

Realized (Gain) Loss on Risk Management Activities 

Operating Margin 

2020     
14,200       
364       
13,836       

5,397       
4,480       
2,236       
555       
247       
921       

2019 (1) (2)   

22,042       
1,173       
20,869       

8,795       
5,234       
2,324       
49       
7       
4,460       

2018 (2)

22,113   
546   

21,567   

9,201   
5,969   

2,367   

60   

1,576   

2,394   

(1)
(2)

The comparative period has been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals. 
On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

Operating Margin Variance 

(1)

Other  includes  the  net  effect  of  the  value  of  condensate  sold  as  heavy  oil  blend  recorded  in  revenues  and  condensate  costs  recorded  in 
transportation and blending expense. The crude oil price excludes the impact of condensate purchases. 

Operating Margin decreased in 2020 primarily due to: 

(cid:120)
(cid:120)

(cid:120)

A 47 percent decline in our average crude oil sales price resulting from lower WTI and WCS benchmark pricing; 
Lower  Operating  Margin  from  our  Refining  and  Marketing  segment  primarily  due  to  reduced  market  crack 
spreads, lower crude advantage and reduced crude oil runs, partially offset by lower operating costs; and  
The use of higher priced condensate in a declining market earlier in the year. 

These decreases in Operating Margin were partially offset by: 

(cid:120)
(cid:120)
(cid:120)

Lower royalties due to lower realized prices; 
Higher liquids sales volumes; and 
A decrease in transportation and blending expenses due to lower priced condensate used for blending. 

Additional details explaining the changes in Operating Margin can be found in the Reportable Segments section of 
this MD&A. 

Cash From (Used in) Operating Activities and Adjusted Funds Flow 

Adjusted Funds Flow is a non-GAAP measure commonly 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  (used  in)  operating  activities  excluding  net  change  in  other  assets  and  liabilities  and  net  change  in 
non-cash  working  capital.  Non-cash  working  capital  is  composed  of  accounts  receivable,  inventories  (excluding 
non-cash inventory write-downs and reversals), income tax receivable, accounts payable and income tax payable. 
Net change in other assets and liabilities is composed of site restoration costs and pension funding. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:20)

 
  
  
  
  
       
       
   
  
  
  
  
  
  
 
($ millions) 

Cash From (Used in) Operating Activities 

(Add) Deduct: 

Net Change in Other Assets and Liabilities 
Net Change in Non-Cash Working Capital (2)

Adjusted Funds Flow (2)

2020     

273       

(72 )     
198       
147       

2019     
3,285       

(84 )     
(333 )     
3,702       

2018 (1)

2,154   

(72 ) 
505   

1,721   

(1)
(2)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 
The comparative period has been reclassified to conform with the current period treatment of non-cash inventory write-downs and reversals. 

Cash  From  Operating  Activities  and  Adjusted  Funds  Flow  decreased  significantly  in  2020,  primarily  due  to  lower 
Operating  Margin,  as  discussed  above,  transaction  costs  of  $29  million  related  to  the  Arrangement,  and  higher 
finance costs. The decrease was partially offset by funding from the CEWS program and  a current tax recovery of 
$13 million  compared  with  current  tax  expense  of  $17 million.  Adjusted  Funds  Flow  was  further  reduced  by  a 
$100 million loss related to the Keystone XL pipeline project. The change in non-cash working capital in 2020 was 
primarily  due  to  a  decrease  in  inventory  and  accounts  receivable,  partially  offset  by  a  decrease  in  accounts 
payable.  

In  2019,  the  change  in  non-cash  working  capital  was  primarily  due  to  an  increase  in  accounts  receivable  and 
inventory, partially offset by an increase in accounts payable and a decrease in income tax receivable. 

Operating Earnings (Loss) 

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, revaluation gain, 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 income tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase 
in U.S. tax basis. 

($ millions) 

Earnings (Loss), Before Income Tax 

Add (Deduct): 

Unrealized Risk Management (Gain) Loss (2)
Non-Operating Unrealized Foreign Exchange (Gain) Loss (3)
(Gain) Loss on Divestiture of Assets 

Operating Earnings (Loss), Before Income Tax 

Income Tax Expense (Recovery) 

Total Operating Earnings (Loss) 

2020     
(3,230 )     

56       
(194 )     
(81 )     
(3,449 )     
(845 )     
(2,604 )     

2019     
1,397       

149       
(787 )     
(2 )     
757       
301       
456       

2018 (1)

(3,926 ) 

(1,249 ) 

593   

795   

(3,787 ) 

(1,032 ) 

(2,755 ) 

(1)
(2)
(3)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 
Includes the reversal of unrealized (gains) losses recorded in prior periods. 
Includes  unrealized  foreign  exchange  (gains)  losses  on  translation  of  U.S.  dollar  denominated  notes  issued  from  Canada  and  foreign  exchange 
(gains) losses on settlement of intercompany transactions. 

We incurred an Operating Loss in 2020, relative to Operating Earnings in 2019, primarily due to lower Cash From 
Operating Activities and Adjusted Funds Flow, as discussed above, higher Depletion, Depreciation and Amortization 
(“DD&A”)  including  impairment  charges  of  $1,112 million,  and  operating  unrealized  foreign  exchange  losses  of 
$63 million compared with gains of $27 million in 2019. The increase in our Operating Loss was partially offset by 
non-operating realized foreign exchange gains of $33 million compared with realized losses of $401 million in 2019 
on our unsecured notes, a re-measurement gain of $80 million on the contingent payment compared with a loss of 
$164 million in 2019, and lower non-cash employee long-term incentive costs. 

(cid:20)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

  
  
       
       
   
  
  
  
 
  
  
       
       
   
  
  
  
  
  
  
Net Earnings (Loss) 

($ millions) 

Net Earnings (Loss), Comparative Year 

Increase (Decrease) due to: 

Operating Margin 
Corporate and Eliminations: 

Unrealized Risk Management Gain (Loss) 
Unrealized Foreign Exchange Gain (Loss) 

Re-measurement of Contingent Payment 
Gain (Loss) on Divestiture of Assets 
Expenses (2)

DD&A 

Exploration Expense 
Income Tax Recovery (Expense) 

Net Earnings (Loss), End of Year 

2020 
vs. 2019     
2,194       

2019 
vs. 2018 (1)  
(2,916 ) 

(3,539 )     

2,066   

93       
(696 )     
244       
79       
416       
(1,215 )     
(9 )     
54       
(2,379 )     

(1,398 ) 
1,476   

(114 ) 
797   

573   
(118 ) 

2,041   
(213 ) 

2,194   

(1)
(2)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 
Includes  Corporate  and  Eliminations  realized  risk management  (gains)  losses,  general  and  administrative, finance  costs,  interest  income,  realized 
foreign exchange (gains) losses, research costs, other (income) loss, net, Corporate and Eliminations revenues, purchased product, transportation 
and blending, and operating expenses. 

Net  Loss  of  $2,379 million  was  significantly  lower  than  Net  Earnings  of  $2,194 million  in  2019  due  to  lower 
Operating  Earnings,  as  discussed  above,  and  non-operating  unrealized  foreign  exchange  gains  of  $194 million 
compared  with  $787 million  in  2019  partially  offset  by  unrealized  risk  management  losses  of  $56 million  in  2020 
compared with losses of $149 million in 2019 and a gain of $79 million on the divestiture of the Marten Hills assets. 

Capital Investment 

($ millions) 

Oil Sands 
Conventional (3)
Refining and Marketing 

Corporate and Eliminations 
Capital Investment (4)

2020     

2019 (1)   

2018 (2)

427       
78       
276       
60       
841       

656       
103       
280       
137       
1,176       

870   

228   

208   

57   

1,363   

(1)

(2)
(3)
(4)

In  the  first  quarter  of  2020,  Marten  Hills  was  reclassified  from  the  Oil  Sands  segment  to  the  Conventional  segment,  prior  to  the  divestiture  in 
December 2020. The comparative information has been reclassified. 
On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 
This segment was previously referred to as the Deep Basin segment. 
Includes expenditures on PP&E and E&E assets. 

Capital investment in 2020 decreased compared with 2019, reflecting our reduced capital investment program and 
revised budget announced in April. Our upstream capital investment focused primarily on sustaining programs. Our 
downstream capital expenditures focused primarily on yield enhancement, reliability and maintenance projects, as 
well as storage infrastructure projects. 

Further  information  regarding  our  capital  investment  can  be  found  in  the  Reportable  Segments  section  of  this 
MD&A.

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:22)

  
  
       
   
  
  
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS 

Key performance drivers for our financial results include commodity prices, quality and location price differentials, 
refining  crack  spreads  as  well  as  the  U.S./Canadian  dollar  exchange  rate.  The  following  table  shows  selected 
market  benchmark  prices  and  the  U.S./Canadian  dollar  average  exchange  rates  to  assist  in  understanding  our 
financial results. 

Selected Benchmark Prices and Exchange Rates (1) 

(US$/bbl, unless otherwise indicated) 

Q4 2020      Q4 2019     

2020     

Percent 
Change     

2019     

2018   

Brent 

Average 

WTI 

Average 

Average Differential Brent-WTI 

WCS at Hardisty ("WCS") 

Average 
Average Differential WTI-WCS 

Average (C$/bbl)
WCS at Nederland 

Average 

45.24       

62.50       

43.21       

(33 )     

64.18       

71.53   

42.66       

56.96       

39.40       

2.58       

5.54       

3.81       

(31 )     
(47 )     

57.03       
7.15       

64.77   

6.76   

33.36       
9.30       

41.13       
15.83       

26.80       
12.60       

43.41       

54.29       

35.59       

(39 )     
(1 )     
(39 )     

44.27       
12.76       
58.77       

38.46   
26.31   

49.81   

Average Differential WTI-WCS at Nederland 

2.30       

5.49       

3.54       

40.36       

51.47       

35.86       

(35 )     
141       

55.56       
1.47       

62.05   

2.72   

West Texas Sour ("WTS") 

Average 

Average Differential WTI-WTS 

Condensate (C5 @ Edmonton) 

Average 
Average Differential WTI-Condensate 
(Premium)/Discount 
Average Differential WCS-Condensate 
(Premium)/Discount 

Average (C$/bbl)

Average Refined Product Prices 

43.02       

57.26       

39.37       

(0.36 )     

(0.30 )     

0.03       

(30 )     
(96 )     

56.27       
0.76       

57.24   

7.53   

42.54       

53.01       

37.16       

(30 )     

52.86       

61.00   

0.12       

3.95       

2.24       

(46 )     

4.17       

3.77   

(9.18 )     

(11.88 )     

(10.36 )     

55.36       

69.97       

49.44       

21       
(30 )     

(8.59 )     
70.15       

(22.54 ) 

79.02   

Chicago Regular Unleaded Gasoline ("RUL") 

47.31       

64.83       

45.24       

Chicago Ultra-low Sulphur Diesel ("ULSD") 

54.21       

78.09       

50.08       

(36 )     
(36 )     

70.55       
77.97       

77.96   

86.75   

Refining Margin: Average 3-2-1 Crack 
Spreads (2)
Chicago 

Group 3 

Average Natural Gas Prices 

AECO (3) (C$/Mcf)
NYMEX (US$/Mcf)

Foreign Exchange Rate (US$ per C$1)

Average 

End of Period 

7.05       

12.27       

7.57       

14.60       

7.54       

8.67       

(53 )     
(48 )     

16.00       
16.67       

15.97   

16.74   

2.77       

2.66       

2.34       

2.50       

2.24       

2.08       

38       
(21 )     

1.62       
2.63       

1.53   

3.09   

0.768       

0.758       

0.746       

0.785       

0.770       

0.785       

(1 )     
2       

0.754       
0.770       

0.772   

0.733   

(1)

(2)
(3)

These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk 
management results, refer to the Netback tables in the Reportable Segments section of this MD&A. 
The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis. 
Alberta Energy Company (“AECO”) natural gas monthly index. 

Crude Oil and Condensate Benchmarks 

In  2020,  the demand for crude  oil was  under pressure  due  to COVID-19  while  OPEC-led production  cuts  reduced 
the impact of the demand destruction resulting in lower average Brent and WTI crude oil benchmark prices. 

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and 
the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In 
2020,  the  Brent-WTI  differential  narrowed  compared  with  2019  due  to  lower  exports  of  crude  oil  from  North 
America and reduced U.S. crude oil supply. 

WCS  is  blended  heavy  oil  which  consists  of  both  conventional  heavy  oil  and  unconventional  diluted  bitumen.  In 
2020,  the  WTI-WCS  at  Hardisty  differential  narrowed  slightly  compared  with  2019  as  reduced  Western  Canadian 
Sedimentary Basin (“WCSB”) crude supply resulted in excess pipeline capacity for parts of the year, reducing the 
need for more expensive crude-by-rail shipments. This resulted in average differentials being similar to 2019 when 
the Government of Alberta enforced their mandatory production curtailment limits. 

(cid:20)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

  
  
  
       
       
       
       
       
   
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
  
       
       
       
       
       
   
  
  
  
  
 
WCS at Nederland is a heavy oil benchmark at the U.S. Gulf Coast (“USGC”) which is representative of pricing for 
our sales in the USGC. WCS at Nederland crude oil prices weakened in 2020, consistent with falling crude oil prices 
globally  as  refiners  lowered  crude  runs  to  adjust  to  reduced  demand  for  products.  In  2020,  WCS  at  Nederland 
benchmark prices relative to WTI widened compared with 2019. The widening was mainly attributed to very wide 
differentials  in  the  second  quarter  of  2020  when  demand  was  weak  and  OPEC+  had  not  yet  committed  to 
production cuts. OPEC+ production cuts are weighed towards medium and heavy sour grades and have resulted in 
narrower heavy differentials at the USGC in the second half of 2020 compared with the same period of 2019. 

Crude Oil Benchmark  Prices

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Brent

WTI

Condensate

WCS at Hardisty

Forward Spot Pricing
as at December 31, 2020

WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI 
crude  oil,  and  is  a  primary  component  of  the  input  feedstock  at  the  Borger  refinery.  The  average  differential 
between  WTI  and  WTS  benchmark  prices  narrowed  in  2020  as  debottlenecking  of  transportation  constraints 
resulted in WTS trading in a narrow range around parity with WTI pricing since early 2019. 

Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, 
diluent volumes as a percentage of total blended volumes, range from approximately 25 percent to 33 percent. The 
WCS-Condensate  differential  is  an  important  benchmark  as  a  wider  differential  generally  results  in  a  decrease  in 
the  recovery  of  condensate  costs  when  selling  a  barrel  of  blended  crude  oil.  When  the  supply  of  condensate  in 
Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus 
the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases 
and deliveries of condensate into inventory to be available for use in blending as well as timing of sales of blended 
product. 

Average condensate benchmark prices were at a narrower discount relative to WTI in Alberta in 2020 as a result of 
weaker  diluent  demand  due  to  shut-in  heavy  oil  production  offset  by  lower  imported  barrels  from  the  U.S.  and 
strong global demand. 

Refining Benchmarks 

The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices 
are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. 
The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude 
oil  into  two  barrels  of  regular  unleaded  gasoline  and  one  barrel  of  ultra-low  sulphur  diesel  using  current  month 
WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis. 

Average  Chicago  refined  product  prices  decreased  in  2020,  primarily  due  to  lower  refined  product  demand  as  a 
result  of  COVID-19.  Weaker  refined  product  demand  resulted  in  higher  inventory  levels  which  put  pressure  on 
market  crack  spreads.  As  North  American  refining  crack  spreads  are  expressed  on  a  WTI  basis,  while  refined 
products  are  set  by  global  prices,  the  weakening  of  refining  market  crack  spreads  in  the  U.S.  Midwest  and 
Midcontinent will reflect the differential between Brent and WTI benchmark prices. 

Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, refinery 
configuration and product output, the time lag between the  purchase and delivery of crude oil feedstock, and the 
cost of feedstock, which is valued on a first in, first out (“FIFO”) accounting basis.

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Chicago 3-2-1 Crack Spread Benchmark

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Chicago 3-2-1 Crack Spreads

Forward Spot Pricing
as at December 31, 2020

Natural Gas Benchmarks 

Average  AECO  prices  strengthened  in 2020  compared  with  2019  as  the  differential  between  AECO  and  NYMEX 
narrowed significantly due  to  lower  than  expected  supply, ample  access  to domestic storage  injections  and  lower 
pipeline utilization in the WCSB. Average NYMEX prices decreased compared with 2019 due to lower demand and a 
large decrease in liquified natural gas exports. 

Foreign Exchange Benchmark 

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and 
refined products are determined by reference to U.S.  benchmark prices. An increase in the value of the Canadian 
dollar  compared  with  the  U.S.  dollar  has  a  negative  impact  on  our  reported  results.  Likewise,  as  the  Canadian 
dollar weakens, there is a positive impact on our reported results. In addition to our revenues being denominated 
in U.S. dollars, our long-term debt is also U.S. dollar denominated. In periods of a weakening Canadian dollar, our 
U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. 

The Canadian dollar on average weakened relative to the U.S. dollar in 2020, compared with 2019, resulting in a 
positive impact of approximately  $140 million on our revenues  in 2020. The strengthening of the Canadian dollar 
relative  to  the  U.S.  dollar  as  at  December  31, 2020  compared  with  December 31, 2019,  resulted  in  unrealized 
foreign exchange gains of $194 million on the translation of our U.S. dollar debt. 

REPORTABLE SEGMENTS 

Our reportable segments at December 31, 2020 are: 

Oil  Sands,  which  includes  the  development  and  production  of  bitumen  in  northeast  Alberta.  Cenovus’s  bitumen 
assets  include  Foster  Creek,  Christina  Lake  and  Narrows  Lake  as  well  as  other  projects  in  the  early  stages  of 
development. 

Conventional,  which  includes  assets  rich  in  NGLs  and  natural  gas  within  the  Elmworth-Wapiti,  Kaybob-Edson, 
and Clearwater operating areas in Alberta and British Columbia and the  exploration for heavy oil in the Marten 
Hills  area.  The  assets  include  interests  in  numerous  natural  gas  processing  facilities.  We  renamed  our  Deep 
Basin  segment  to  Conventional  in  2020  and  our  new  resource  play,  Marten  Hills,  was  reclassified  from  the  Oil 
Sands  segment 
reclassified.  On 
December 2, 2020,  we  completed  the  sale  of  our  Marten  Hills  assets  with  a  retained  Gross  Overriding  Royalty 
agreement. 

the  Conventional  segment.  Comparative  periods  have  been 

to 

Refining and Marketing, which  is responsible for  transporting,  selling  and  refining  crude  oil  into petroleum 
and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated 
U.S.  public  company.  In  addition,  Cenovus  owns  and  operates  a  crude-by-rail  terminal  in  Alberta.  This  segment 
coordinates  Cenovus’s  marketing  and  transportation  initiatives  to  optimize  product  mix,  delivery  points, 
transportation commitments and customer diversification. 

Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial 
instruments,  gains  and  losses  on  divestiture  of  assets,  as  well  as  other  Cenovus-wide  costs  for  general  and 
administrative, financing activities and research costs. As financial instruments are settled, the realized gains and 
losses  are  recorded  in  the  reportable  segment  to  which  the  derivative  instrument  relates.  Eliminations  include 
adjustments for internal usage of natural gas production between segments, transloading services provided to the 
Oil  Sands  segment  by  the  Company’s  rail  terminal,  crude  oil  production  used  as  feedstock  by  the  Refining  and 
Marketing  segment,  and  unrealized  intersegment  profits  in  inventory.  Eliminations  are  recorded  at  transfer  prices 
based on current market prices. 

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Revenues by Reportable Segment 

($ millions) 
Oil Sands 
Conventional (1)
Refining and Marketing 
Corporate and Eliminations 

2020     
7,190       
595       
6,051       
(609 )     
13,227       

2019     
9,695       
661       
10,513       
(689 )     
20,180       

2018   
9,553   
831   
11,183   
(724 ) 
20,843   

(1)

This segment was previously referred to as the Deep Basin segment. 

Oil Sands revenues decreased due to lower average realized liquids sales prices, partially offset by lower royalties 
and higher sales volumes. 

Conventional  revenues  decreased  due  to  lower  average  realized  liquids  sales  prices,  lower  natural  gas  sales 
volumes and higher royalties, partially offset by a higher average natural gas sales price and the commencement of 
heavy oil production from our Marten Hills assets prior to its divestiture. 

Refining  and  Marketing  revenues  declined  in  2020.  Refining  revenues  decreased  due  to  lower  refined  product 
pricing  consistent with  the  decline  in  average refined  product  benchmark  prices  and  lower refined  product  output 
due to the economic crude rate reductions. Revenues from third-party crude oil and natural gas sales undertaken 
by our marketing group decreased compared with 2019 due to lower crude oil prices and lower volumes, partially 
offset by higher natural gas prices. 

Corporate  and  Eliminations  revenues  relate  to  sales  of  natural  gas  or  crude  oil  and  operating  revenues  between 
segments and are recorded at transfer prices based on current market prices. 

Overall, revenues declined slightly in 2019 compared with 2018, primarily due to lower refined product pricing and 
lower upstream sales volumes, partially offset by higher realized crude oil pricing. 

OIL SANDS 

In 2020, we: 

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Delivered safe and reliable operations; 
Increased our Oil Sands production rates to average 381,723 barrels per day; 
Demonstrated  our  ability  to  use  our  full  suite  of  assets  to  maximize  prices  received  for  every  barrel  as  we 
managed  to  store  volumes  in  a  low-price  environment  and  cleared  inventory  when  we  could  obtain  higher 
prices; and 
Generated Operating Margin of $1,113 million, a decrease of $2,368 million compared with 2019 due to lower 
average realized sales prices, partially offset by lower royalties, higher volumes and lower transportation and 
blending costs. 

Financial Results 

($ millions) 

Gross Sales 

Less: Royalties 

Revenues 

Expenses 

Transportation and Blending 

Operating 

Inventory Write-Down (Reversal) 

(Gain) Loss on Risk Management 

Operating Margin 

Depreciation, Depletion and Amortization 

Exploration Expense 

Segment Income (Loss) 

2020     
7,514       
324       
7,190       

4,399       
1,094       
316       
268       
1,113       
1,684       

9       

(580 )     

2019     
10,838       
1,143       
9,695       

2018 (1)

10,026   

473   

9,553   

5,152       
1,039       
-       
23       
3,481       
1,543       
18       
1,920       

5,879   

1,037   

-   

1,551   

1,086   
1,439   

6   

(359 ) 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

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 Operating Margin Variance 

(1)

Revenues  include  the  value  of  condensate  sold  as  heavy  oil  blend.  Condensate  costs  are  recorded  in  transportation  and  blending  expense.  The 
crude oil price excludes the impact of condensate purchases.  

Revenues 

Price 

In  2020,  our  realized  crude  oil  sales  price  was  $28.64 per barrel  compared  with  $53.78 per barrel  in  2019, 
consistent  with  the  overall  declines  in  crude  oil  benchmark  pricing  led  by  a  decrease  in  WTI  average  benchmark 
price,  partially  offset  by  the  lower  cost  of  condensate  with  an  average  price  of  US$37.16 per barrel  (2019  – 
US$52.86 per barrel).  The  decrease  in  our  crude  oil  price  also  reflects  the  wider  WCS-Condensate  premium  of 
US$10.36 per barrel  (2019  –  premium  of  US$8.59 per barrel).  In  2020,  COVID-19  impacts  resulted  in  low  WTI-
WCS differentials during periods of the year resulting in more volumes sold in Alberta compared with 2019, which 
decreased  our  realized  sales  prices.  In  2019,  we  sold  more  than  25 percent  of  our  production  at  sales  locations 
outside  of  Alberta.  We  used  our  transportation,  storage  and  logistics  assets  and  expertise  to  sell  our  products  in 
higher-priced  months,  when  the  opportunities  were  available,  which  reduced  the  impact  of  the  drop  in  crude  oil 
prices on our realized sales prices. 

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to 
transport it to market through pipelines. Our realized crude oil sales price is influenced by the cost of condensate 
used  in  blending.  Our  blending  ratios  range  between  25 percent  and  33 percent.  As  the  cost  of  condensate 
decreases relative to the price of blended crude oil, our realized bitumen sales price increases. Due to high demand 
for condensate at Edmonton, we also purchase condensate from U.S. markets and deliver it to the Edmonton hub. 
As  such,  our  average  cost  of  condensate  is  generally  higher  than  the  Edmonton  benchmark  price  due  to 
transportation  between  market  hubs  and  transportation  to  field  locations.  In  addition,  up  to  three  months  may 
elapse from when we purchase condensate to when we sell our blended production. In a declining crude oil price 
environment, we expect to see a negative impact on our realized bitumen sales price as we are using condensate 
purchased at a higher price earlier in the year. During the year we reduced condensate volumes transported from 
the  USGC,  as  the  price  differential  between  market  hubs  was  not  significant  enough  to  cover  variable 
transportation  costs  for  part  of  the  year.  Condensate  prices  declined  during  the  summer  months  due  to  lower 
demand making it more cost-effective to buy in Alberta compared with the USGC. 

As  a  result  of  our  decisions  to  store  rather  than  sell,  we  were  able  to  minimize  the  impact  on  our  realized  sales 
prices. Cenovus uses its marketing and transportation initiatives, including storage and pipeline assets to optimize 
product  mix,  delivery  points,  transportation  commitments  and  customer  diversification,  to  inventory  physical 
positions.  At  the  time  we  make  the  decision  to  store  crude  oil  and  condensate  volumes,  the  prices  available  for 
future periods we plan to sell in can be locked in and the improved margin realized in the future periods, which are 
superior  to  short-term  prices.  The  additional  revenues  generated  from  the  underlying  physical  sales  may  be 
impacted by the related risk management gains and losses. 

Transactions  typically  span  across  periods  in  order  to  execute  the  optimization  strategy  and  these  transactions 
reside  across  both realized  and  unrealized risk  management.  As  the financial  contracts settle,  they  will flow from 
unrealized to realized risk management gains and losses and final settlement will match when the physical product 
is sold. 

Production Volumes 

(barrels per day) 

Foster Creek 

Christina Lake 

2020     
   163,210       
   218,513       
   381,723       

Percent 
Change      

2019     
2        159,598       
12        194,659       
8        354,257       

Percent 
Change     

2018  
(1 )      161,979  
(3 )      201,017  
(2 )      362,996   

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In  2020,  we  actively  managed  production  levels  to  respond  to  price  signals  and  the  availability  of  production 
curtailment  credits,  both  our  own  and  those  available  in  the  market.  In  2019,  our  production  was  in  line  with 
Government of Alberta’s mandatory production curtailment program. 

Royalties 

Royalty  calculations  for  our  oil  sands  projects  are  based  on  government  prescribed  pre-  and  post-payout  royalty 
rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price. 

Royalties  for  a  pre-payout  project  are  based  on  a  monthly  calculation  that  applies  a  royalty  rate  (ranging  from 
one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues 
from the project. 

Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross 
revenues  multiplied  by  the  applicable  royalty  rate  (one percent  to  nine percent,  based  on  the  Canadian  dollar 
equivalent  WTI  benchmark  price);  or  (2)  the  net  profits  of  the  project  multiplied  by  the  applicable  royalty  rate 
(25 percent  to  40 percent,  based on  the  Canadian  dollar equivalent  WTI  benchmark  price).  For royalty purposes, 
gross  revenues  are  a  function  of  sales  revenues  less  diluent  costs  and  transportation  costs  and  net  profits  are  a 
function of sales revenues less diluent costs, transportation costs, and allowed operating and capital costs. 

Foster Creek and Christina Lake are post-payout projects for determining royalties. 

Effective Royalty Rates 

(percent) 
Foster Creek 
Christina Lake 

2020     

7.9       
14.4       

2019     
18.8       
21.6       

2018   
18.0   
4.8   

In  2020,  royalties  decreased  $819 million  compared  with  2019  as  a  result  of  lower  net  profits  due  to  lower 
commodity pricing, combined  with  lower Alberta  Department  of  Energy posted royalty rates  related  to decreased 
annual average WTI benchmark pricing. 

Expenses 

Transportation and Blending 

Total  transportation  and  blending  costs  have  decreased  $753 million  compared  with  2019.  Blending  costs 
decreased due to a decline in condensate price, partially offset by increased condensate volumes required to move 
increased bitumen volumes. 

Transportation  costs  increased  primarily  due  to  higher  fixed  costs  in  2020,  as  our  rail  freight  and  offloading 
commitments gradually increased in 2019 as the crude-by-rail program ramped up. 

Per-unit Transportation Expenses 

Foster Creek per-barrel transportation costs decreased $0.65 per barrel due to lower pipeline tariffs as a result of 
lower sales at U.S. destinations and increased sales volumes, partially offset by increased rail transportation costs 
from  higher  fixed  costs  in  2020,  as  discussed  above.  Christina  Lake  per-barrel  transportation  costs  increased 
$0.31 per barrel as a result of increased pipelines tariff rates due to higher piped sales at U.S. destinations, higher 
fixed  costs,  as  discussed  above,  and  higher  storage  costs,  partially  offset  by  increased  sales  volumes  relative  to 
2019. 

Operating 

Total  operating  costs  increased  $55 million  due  to  higher  fuel,  workforce,  and  chemical  costs  from  increased 
production,  partially  offset  by  lower  repairs  and  maintenance  costs  and  fluid,  waste  handling  and  trucking  costs 
from the 2020 planned turnaround compared with the planned turnaround at Christina Lake in the second quarter 
of 2019 and reduction in activity and resources due to COVID-19 safety measures. 

Per-unit Operating Expenses 

($/bbl) 

Foster Creek 

Fuel 
Non-fuel 

Total 

Christina Lake 

Fuel 
Non-fuel 

Total 

Total 

2020     

Percent 
Change      

2019     

Percent 
Change      2018 (1)

2.83       
6.41       
9.24       

2.18       
4.61       
6.79       
7.84       

15       
(4 )     
1       

6       
(13 )     
(7 )     
(4 )     

2.47       
6.67       
9.14       

2.06       
5.27       
7.33       
8.15       

16       
(2 )     
2       

10       
11       
11       
7       

2.13  
6.84  

8.97  

1.87  
4.73  

6.60  

7.65   

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

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At  both  Foster  Creek  and  Christina  Lake,  per-barrel  fuel  costs  increased  due  to  higher  natural  gas  prices  and 
consumption, partially offset by higher sales volumes. 

Per-barrel  non-fuel  operating  expenses  at  Foster  Creek  decreased  in  2020  primarily  due  to  higher  sales  volumes 
and  COVID-19  safety  measures  implemented  in  the  second  quarter  resulting  in  less  repairs  and  maintenance 
activity, partially offset by higher workforce costs. 

Per-barrel non-fuel operating expenses at Christina Lake decreased in 2020 primarily due to higher sales volumes, 
and lower costs for the 2020 planned turnaround compared with costs for the planned turnaround in 2019, partially 
offset by higher workforce and chemical costs. 

Netbacks (1) 

Netback  is  a  non-GAAP  measure  commonly  used  in  the  oil  and  gas  industry  to  assist  in  measuring  operating 
performance  on  a  per-unit  basis.  Our  Netback  calculation  is  aligned  with  the  definition  found  in  the  Canadian  Oil 
and  Gas  Evaluation  Handbook  (“COGE  Handbook”).  Netbacks  reflect  our  margin  on  a  per-barrel  of  oil  equivalent 
basis. Netback is defined as gross sales less royalties, transportation and blending and operating expenses divided 
by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized 
when the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact 
of purchased condensate. Condensate is blended with the heavy oil to transport it to market. For a reconciliation of 
our Netbacks see the Advisory section of this MD&A. 

Foster Creek 

Christina Lake 

($/bbl) 

Sales Price 

Royalties 

Transportation and Blending 

Operating Expenses 

Netback Excluding Realized Risk Management   

Realized Risk Management Gain (Loss) 

Netback Including Realized Risk Management   

2020 (2)

30.80       
1.57       
11.05       
9.24       
8.94       
(1.83 )     
7.11       

8.44       
11.70       
9.14       

2019     
57.21        42.63       
6.25       
8.34       
8.97       
27.93        19.07       
(0.16 )      (11.49 )     
7.58       
27.77       

27.04       
2.90       
6.95       
6.79       
10.40       
(1.93 )     
8.47       

2018      2020 (2)

2019     
2018   
50.91        33.42   
1.37   

9.42       
6.64       
7.33       

6.60   
27.52        20.20   
(0.19 )      (11.66 ) 
27.33       
8.54   

5.25   

(1)
(2)

Netbacks reflect our margin on a per-barrel basis of unblended crude oil.  
The netbacks do not reflect non-cash write-downs or reversals of product inventory. 

Our  average  Netback,  excluding  realized  risk  management  gains  and  losses,  decreased  in  2020  compared  with 
2019,  primarily  due  to  lower  realized  sales  prices,  partially  offset  by  lower  royalties,  operating  costs  and 
transportation and blending costs, and higher sales volumes. The weakening of the Canadian dollar relative to the 
U.S.  dollar  compared  with  2019  had  a  positive  impact  on  our  overall  reported  sales  price  of  approximately 
$0.30 per barrel. 

DD&A 

We  deplete  crude  oil  and  natural  gas  properties  on  a  unit-of-production  basis  over  total  proved  reserves.  The 
unit-of-production  rate  accounts  for  expenditures  incurred  to  date,  together  with  estimated  future  development 
expenditures  required  to develop  those  proved reserves. This  rate,  calculated  at  an  area  level,  is  then  applied  to 
our sales volume to determine DD&A  each period. We believe that this method of calculating DD&A charges each 
barrel  of  crude  oil  equivalent  sold  with  its  proportionate  share  of  the  cost  of  capital  invested  over  the  total 
estimated life of the related asset as represented by proved reserves. 

In  2020,  DD&A  increased  $141 million  compared  with  2019,  due  to  higher  sales  volumes,  partially  offset  by  a 
decrease in our average depletion rates. Our depletion rate decreased due to lower future development costs and a 
decrease  in  maintenance  capital.  The  average  depletion  rate  for  the  year  ended  December 31, 2020  was 
approximately $10.40 per barrel (2019 – $11.15 per barrel). 

We depreciate our right-of-use (“ROU”) assets on a straight-line basis over the shorter of the estimated useful life 
or the lease term. 

Capital Investment 

($ millions) 

Foster Creek 
Christina Lake 

Other (2)
Capital Investment (3)

2020     

193       
162       
355       
72       
427       

2019     

243       
362       
605       
51       
656       

2018 (1)

379   
445   

824   
46   

870   

(1)
(2)

(3)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 
Includes Narrows Lake and new resource plays. In Q1 2020, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. 
The comparative information has been reclassified. 
Includes expenditures on PP&E and E&E assets. 

(cid:21)(cid:19)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
    
  
 
 
  
  
  
  
  
 
  
  
  
  
  
  
In  2020,  Oil  Sands  capital  investment  focused  on  sustaining  programs  related  to  existing  production  at  Foster 
Creek  and  Christina  Lake  as  well  as  the  stratigraphic  test  well  program.  Other  capital  investment  related  to 
advancing  key  initiatives  and  technology  development  costs.  In  2019,  capital  investment  primarily  related  to 
sustaining and stratigraphic test well programs and the completion of Christina Lake phase G construction. 

Drilling Activity 

Foster Creek 
Christina Lake 

Other (2)

Gross Stratigraphic 
Test Wells

Gross Production
Wells (1)

2020     

2019     

2018     

2020     

2019     

2018  

38       
42       

80       

75       

155       

14       
18       

32       

26       

58       

43       
63       
106       
20       
126       

-       
-       

-       

-       

-       

-       
11       
11       
-       
11       

14  
38  

52  

-  

52   

(1)
(2)

Steam-assisted gravity drainage (“SAGD”) well pairs are counted as a single producing well.  
Includes Narrows Lake and new resource plays. In Q1 2020, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. 
The comparative information has been reclassified. 

Stratigraphic  test  wells  were  drilled  to  help  identify  well  pad  locations  for  sustaining  wells  and  future  expansion 
phases,  and  to  further  progress  the  evaluation  of  emerging  assets.  In  2020,  we  increased  the  number  of  gross 
stratigraphic test wells drilled by increasing the scope of the program and incorporating more multi-leg wells, which 
have a reduced surface impact. 

CONVENTIONAL 

In 2020, we: 

(cid:120)

(cid:120)

(cid:120)

(cid:120)
(cid:120)

Produced  a  total  of  89,932 BOE  per  day,  down  from  2019  due  to  natural  declines  partially  offset  by  added 
production from the Marten Hills area, prior to its divestiture on December 2, 2020; 
Generated  Operating  Margin  of  $196 million,  a  decrease  from  2019  due  to  reduced  sales  volumes,  lower 
realized prices, and higher royalties, partially offset by lower operating costs; 
Reduced operating costs by approximately six percent to $318 million compared with $337 million in 2019, by 
optimizing operations, focusing on critical repairs and maintenance activities and leveraging our infrastructure; 
Earned a Netback of $5.16 per BOE; and  
Divested our Marten Hills assets and entered into a Gross Overriding Royalty agreement and an equity position 
in the purchaser to benefit from its future development. 

Financial Results 

($ millions) 
Gross Sales 

Less: Royalties 

Revenues 
Expenses 

Transportation and Blending 
Operating 
(Gain) Loss on Risk Management 

Operating Margin 

Depreciation, Depletion and Amortization 
Exploration Expense 

Segment Income (Loss) 

2020     

635       
40       
595       

81       
318       
-       
196       
880       
82       
(766 )     

2019     

691       
30       
661       

82       
337       
-       
242       
319       
64       
(141 )     

2018 (1)

904   
73   
831   

90   
403   
26   
312   
412   
2,117   
(2,217 ) 

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

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Operating Margin Variance 

Revenues 

Price 

Heavy Oil ($/bbl)

Light and Medium Oil ($/bbl)

NGLs ($/bbl)

Natural Gas ($/mcf)

Total Oil Equivalent ($/BOE)

2020     
31.45       
42.78       
22.04       
2.37       
17.84       

2019     

-       
65.70       
26.36       
2.01       
17.95       

2018   

-   

66.71   

38.56   

1.72   

19.31   

For  the  year  ended December 31, 2020,  revenues  declined  due  to  decreased  average  realized  liquids  sales  prices 
and lower natural gas sales volumes, partially offset by higher natural gas sales prices and liquids sales volumes. 
In 2020, prior to its divestiture, we had heavy oil production from Marten Hills of approximately 2,700 barrels per 
day.  In 2020,  revenues  included  $49 million  of  processing  fee  revenue  related  to  our  interests  in  natural  gas 
processing facilities (2019 – $53 million). We do not include processing fee revenue in our per-unit pricing metrics 
or our Netbacks. 

Production Volumes 

Liquids 

Crude Oil (barrels per day)

NGLs (barrels per day)

Natural Gas (MMcf per day)

Total Production (BOE/d)

Natural Gas Production (percentage of total)

Liquids Production (percentage of total)

2020     

2019     

2018   

7,244       
19,513       
26,757       
379       
89,932       

70       
30       

4,911       
21,762       
26,673       
424       
97,423       

73       
27       

5,916   

26,538   

32,454   

527   

120,258   

73   

27   

Production in 2020 decreased due to natural declines, partially offset by Marten Hills heavy oil production, prior to 
its divestiture. 

Royalties 

The Conventional assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties 
benefit from a number of different programs that reduce the royalty rate on crude oil and natural gas production. 
Natural gas wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account 
for capital and direct operating costs incurred to process and transport the Crown’s share of raw gas at producer-
owned gas plants as well as transport the Crown’s share of residue gas, NGLs or oil through producer-owned sales 
pipelines. 

In  2020,  our  effective  royalty  rate  was  7.9 percent  (2019  –  5.1 percent).  The  higher  royalty  rate  is  due  to  a 
reduction in capital and operating expenses in 2019 resulting in a reduced GCA recovery. 

Expenses 

Transportation 

Our  transportation  costs  reflect  charges  for  the  movement  of  crude  oil,  NGLs  and  natural  gas  from  the  point  of 
production  to  where  the  product  is  sold.  The  majority  of  our  Conventional  production  is  sold  into  the  Alberta 
market. Per-unit transportation costs averaged $2.46 per BOE (2019 – $2.31 per BOE), due to lower sales volumes 
and increased pipeline costs. 

(cid:21)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
 
  
         
      
   
  
  
 
  
  
  
 
  
    
  
  
    
  
  
    
  
  
Operating 

Total  operating  costs  decreased  to  $318 million  (2019  –  $337 million)  through  continuing  efforts  to  optimize  our 
operations and workforce, focusing on critical repair and maintenance activities and leveraging our infrastructure to 
lower the cost structure.  

Per-unit operating costs increased to an average of $8.99 per BOE (2019 – $8.79 per BOE) primarily due to lower 
sales volumes partially offset by lower workforce costs, decreased property tax and lease costs primarily for lower 
lease rentals and from regulatory cost relief, and lower repairs and maintenance as a result of lower activity and 
deferrals. 

Netbacks 

($/BOE) 

Sales Price 
Royalties 

Transportation and Blending
Operating Expenses

Netback Excluding Realized Risk Management

Realized Risk Management Gain (Loss) 

Netback Including Realized Risk Management

2020     
17.84       
1.23       
2.46       
8.99       
5.16       
(0.01 )     
5.15       

2019     
17.95       
0.83       
2.31       
8.79       
6.02       
(0.01 )     
6.01       

2018 (1)

19.31   
1.67   

1.97   
8.58   

7.09   

(0.59 ) 

6.50   

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

DD&A and Exploration Expense 

We  deplete  crude  oil  and  natural  gas  properties  on  a  unit-of-production  basis  over  proved  reserves.  The 
unit-of-production rate accounts for expenditures incurred to date, together with future development expenditures 
required  to  develop  those  proved  reserves.  This  rate,  calculated  at  an  area  level,  is  then  applied  to  our  sales 
volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel 
of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life 
of  the  related  asset  as  represented  by  proved  reserves.  The  average  depletion  rate  was  approximately 
$9.85 per BOE for the year ended December 31, 2020 (2019 – $9.15 per BOE). 

For  the  year  ended  December 31, 2020,  total  Conventional  DD&A  was  $880 million  (2019  –  $319 million).  The 
increase was due to impairment charges of $555 million, as a result of the decline in forward crude oil and natural 
gas prices and a change in our future development plans, and higher DD&A rates. 

Exploration  expense  of  $82 million  was  recorded  for  the  year  ended  December 31, 2020  (2019  –  $64 million)  as 
the carrying value of certain E&E assets were not considered to be recoverable. 

Divestiture 

On  December 2, 2020,  we  sold  our  Marten  Hills  assets  in  northern  Alberta  to  Headwater  Exploration  Inc. 
(“Headwater”)  for  total  consideration  of  $138 million,  excluding  the  retained  gross  overriding  royalty  interest 
(“GORR”). A before-tax gain of $79 million was recorded on the sale (after-tax – $65 million). Total consideration 
received  consists  of  $33 million  cash,  50 million  common  shares  valued  at  $97 million  and  15 million  share 
purchase warrants valued at $8 million at the date of close. The share purchase warrants have a three-year term 
and  an  exercise  price  of  $2.00 per share.  We  retained  a  GORR  in  the  Marten  Hills  assets  which  was  reclassified 
from E&E to PP&E for $41 million at the date of close. The investment in Headwater is held in other assets. 

Capital Investment 

In  2020,  we  invested  $78 million  compared  with  $103 million  in  2019.  Capital  investment  focused  on  the 
disciplined development of our Conventional assets, which encompassed maintaining safe and reliable operations, 
acquiring seismic data, start-up of a recompletion program to optimize existing production and commencement of a 
drilling program targeting low-risk, high-return development. 

($ millions) 

Seismic 

Drilling and Completions 

Facilities 
Other 
Capital Investment (2)

2020     
5       
27       
20       
26       
78       

2019 (1)   
-       
32       
34       
37       
103       

2018 (1)

-   
123   

58   
47   

228   

(1)

(2)

In  Q1 2020,  Marten  Hills  was  reclassified  from  the  Oil  Sands  segment  to  the  Conventional  segment.  The  comparative  information  has  been 
reclassified. 
Includes expenditures on PP&E and E&E assets. 

Drilling Activity 

In 2020 there were six net wells drilled, one net well completed and three net wells were tied-in and brought on 
production. In 2019, there were 11 net wells drilled, two net wells completed and three net wells tied-in. 

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REFINING AND MARKETING 

In 2020, we: 

(cid:120)

(cid:120)

(cid:120)

(cid:120)

Managed to economic crude oil runs of 372,000 barrels per day, lower than 2019 in response to the economic 
slowdown due to COVID-19; 
Reported Operating Margin of negative $388 million, a decrease of $1,125 million compared with 2019, due to 
lower  global  crude  oil  and  refined  product  pricing,  which  led  to  decreased  market  crack  spreads  and  lower 
crude advantage, and decreased crude oil runs, partially offset by lower operating costs; 
Recorded  an  impairment  charge  of  $450 million,  as  additional  DD&A  expense,  associated  with  the  Borger 
cash-generating unit (“CGU”); and 
Completed  the  temporary  ramp  down  of  our  crude-by-rail  program  in  the  second  quarter  until  pricing 
fundamentals supported its continuation in the fourth quarter. 

Financial Results 

($ millions) 

Revenues 

Purchased Product 

Inventory Write-Down (Reversal) 

Gross Margin 
Expenses 

Operating 
(Gain) Loss on Risk Management 

Operating Margin 

Depreciation, Depletion and Amortization 

Segment Income (Loss) 

2020     
6,051       
5,397       
239       
415       

824       
(21 )     
(388 )     
739       
(1,127 )     

2019 (1)   
10,513       
8,795       
49       
1,669       

948       
(16 )     
737       
280       
457       

2018 (1) (2)

11,183   

9,201   

60   

1,922   

927   
(1 ) 

996   

222   

774   

(1)
(2)

The comparative period has been reclassified to conform with current period treatment of non-cash inventory write-downs and reversals. 
On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

Refinery Operations (1)  

Crude Oil Capacity (Mbbls/d)

Crude Oil Runs (Mbbls/d)

Heavy Crude Oil 

Light/Medium 

Refined Products (Mbbls/d)

Gasoline 

Distillate 

Other 

Crude Utilization (percent)

2020     

2019     

2018   

495       
372       
149       
223       
385       
195       
127       
63       
75       

482       
443       
177       
266       
466       
223       
167       
76       
92       

460   

446   

191   

255   

470   

233   

156   

81   

97   

(1)

Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent. 

On  a  100 percent  basis,  the  Refineries  had  total  processing  capacity  re-rated  on  January 1, 2020  to 
495,000 gross barrels per day of crude oil. The ability to process a wide slate of crude oils allows the Refineries to 
economically  integrate  heavy  crude  oil  production.  Processing  less  expensive  crude  oil  relative  to  WTI  creates  a 
feedstock  cost  advantage,  illustrated  by  the  discount  of  WCS  relative  to  WTI.  The  amount  of  heavy  crude  oil 
processed, such as WCS and Christina Dilbit Blend, is dependent on the quality and quantity of available crude oil 
with the total input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the 
percentage of total crude oil processed in the Refineries relative to the total capacity. 

Crude oil runs and refined product output decreased in 2020 compared with 2019 as both Refineries implemented 
crude rate reductions in response to the reduced demand due to COVID-19. In 2019, operational performance was 
impacted by unplanned outages, planned maintenance and turnaround activities at both Refineries. 

Crude-By-Rail Terminal 

Our crude-by-rail program was suspended in the first quarter in response to the low price market environment. The 
suspension  was  completed  during  the  second  quarter  and  lifted  in  the  fourth  quarter  as  market  conditions 
improved. In 2020, we loaded an average of 32,213 barrels per day (22,891 barrels per day of our volumes) from 
our  Bruderheim 
65,293 barrels per day 
compared  with 
(45,324 barrels per day of our volumes) in 2019. 

crude-by-rail 

terminal 

average 

an 

of 

Gross Margin 

While market crack spreads are an indicator of margin from processing crude oil into refined products, the refining 
realized  crack  spread,  which  is  the  gross  margin  on  a  per-barrel  basis,  is  affected  by  many  factors,  such  as  the 
variety  of  feedstock  crude  oil  processed;  refinery  configuration  and  the  proportion  of  gasoline,  distillate  and 

(cid:21)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

  
  
  
  
  
       
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
secondary  product  output;  the  time  lag  between  the  purchase  of  crude  oil  feedstock  and  the  processing  of  that 
crude oil  through  the  Refineries;  and  the  cost  of  feedstock.  Our feedstock costs  are valued on  a  FIFO  accounting 
basis. 

In  2020,  Refining  and  Marketing  gross  margin  decreased  $1,254 million  resulting  from  decreased  market  crack 
spreads and crude advantage due to lower global crude oil and refined product pricing, and reduced crude oil runs. 

In  the  year  ended  December 31, 2020,  the  cost  of  Renewable  Identification  Numbers  (“RINs”)  was  $177 million 
(2019  –  $99 million).  RIN  costs  increased,  primarily  due  to  higher  pricing,  partially  offset  by  lower  volume 
obligations.  In 2020, RINs  prices  have  been  volatile  and  have  steadily  increased  as RIN  generation  declined year 
over year, and at the same time RIN demand increased following a federal court decision to reduce the number of 
small refiners eligible for hardship exemptions. 

Operating Expense 

Primary  drivers  of  operating  expenses  in  2020  were  labour,  maintenance,  and  utilities.  Operating  expenses 
decreased primarily due to lower maintenance activity compared with 2019 and lower utility costs. 

DD&A 

Refining  and  the crude-by-rail  terminal  assets  are depreciated on  a  straight-line  basis  over  the  estimated  service 
life of each component of the facilities, which range from  three  to 60 years. The service lives of these assets are 
reviewed on an annual basis. ROU assets are depreciated on a straight-line basis over the shorter of the estimated 
useful  life  of  the  asset  or  the  lease  term.  Refining  and  Marketing  DD&A  was  $739 million  compared  with 
$280 million in 2019. The increase in DD&A is primarily due to an impairment charge of $450 million related to the 
Borger CGU. 

Capital Investment 

($ millions) 

Wood River Refinery 

Borger Refinery 

Marketing 

Capital Investment 

2020     

158       
85       
33       
276       

2019     

128       
100       
52       
280       

2018 (1)   

119   

85   

4   

208   

(1)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

Capital expenditures in 2020 focused primarily on yield enhancement, reliability and maintenance projects, as well 
as storage infrastructure projects. 

CORPORATE AND ELIMINATIONS 

In 2020, our risk management activities resulted in: 
(cid:120)

Unrealized  risk  management  losses  of  $56 million  (2019 –  $149 million)  due  to  the  realization  of  settled 
positions and changes in commodity prices compared with the prices at the end of the prior year; and 
Realized  foreign  exchange  risk  management  losses  of  $5 million  (2019 –  gain  of  $1 million  and  loss  of 
$1 million on interest rate swap contracts). 

(cid:120)

Transactions  typically  span  across  periods  in  order  to  execute  the  optimization  strategy  and  these  transactions 
reside across both realized and unrealized risk management. 

Expenses 

($ millions) 
General and Administrative (2)
Finance Costs 

Interest Income 
Foreign Exchange (Gain) Loss, Net 
Transaction Costs 

Re-measurement of Contingent Payment 

(Gain) Loss on Divestiture of Assets 
Other (Income) Loss, Net 

2020     

292       
536       
(9 )     
(181 )     
29       
(80 )     
(81 )     
40       
546       

2019     

331       
511       
(12 )     
(404 )     
-       
164       
(2 )     
9       
597       

2018 (1)

1,020   
627   

(19 ) 
854   
-   

50   

795   
13   

3,340   

(1)
(2)

On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 
Onerous contract provisions of $629 million in 2018 have been reclassified to G&A. 

General and Administrative 

Primary  drivers  of  our  general  and  administrative  expenses  were  workforce  costs,  employee  long-term  incentive 
costs and operating costs associated with our real estate portfolio. In 2020, G&A expenses were $39 million lower 

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primarily  due  to  lower  employee  long-term  incentive  costs  and  operating  costs  associated  with  our  real  estate 
portfolio, partially offset by an onerous contract provision of $18 million. 

Finance Costs 

Finance  costs  increased  by $25 million  primarily  due  to  a discount of  $25 million on  the  repurchase  of  unsecured 
notes compared with $63 million in 2019. 

The  weighted  average  interest  rate  on  outstanding  debt  for  the  year  ended  December 31, 2020  was  4.9 percent 
(2019 – 5.1 percent). 

Foreign Exchange 

($ millions) 

Unrealized Foreign Exchange (Gain) Loss 

Realized Foreign Exchange (Gain) Loss 

2020     
(131 )     
(50 )     
(181 )     

2019     
(827 )     
423       
(404 )     

2018   

649   

205   

854   

In 2020, unrealized foreign exchange gains of $131 million were recorded primarily as a result of the translation of 
our  U.S.  dollar  denominated  debt.  The  Canadian  dollar  relative  to  the  U.S.  dollar  as  at  December 31, 2020  was 
two percent stronger compared with December 31, 2019, resulting in unrealized gains. 

Transaction Costs 

Prior  to  December  31,  2020,  we  incurred  transaction  costs  of  $29  million  for  costs  related  to  the  Arrangement, 
excluding common share, preferred share and warrant issuance costs.

Re-measurement of Contingent Payment 

Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips Company and 
certain of its subsidiaries (“ConocoPhillips”) during the five years subsequent to the closing date of the acquisition 
from  ConocoPhillips  of  their  50 percent  interest  in  the  FCCL  Partnership  on  May 17, 2017  (“the  Conoco 
Acquisition”), for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The 
quarterly payment is $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum 
payment  terms.  The  calculation  includes  an  adjustment  mechanism  related  to  certain  significant  production 
outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. 

The  contingent  payment  is  accounted  for  as  a  financial  option.  The  fair  value  of  $63 million  as  at 
December 31, 2020  was  estimated  by  calculating  the  present  value  of  the  future  expected  cash  flows  using  an 
option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in 
fair value recognized in net earnings. For the year ended December 31, 2020, a non-cash re-measurement gain of 
$80 million was recorded. 

Average  WCS  forward  pricing  for  the  remaining  term  of  the  contingent  payment  is  $42.93 per  barrel.  Estimated 
quarterly  WCS  forward  prices  for  the  remaining  term  of  the  agreement  range  between  approximately 
$42.40 per barrel and $43.80 per barrel. 

Other (Income) Loss, Net 

For the year ended December 31, 2020, recorded a $100 million loss related to the Keystone XL pipeline project. 

The  Government  of  Canada  passed  the  CEWS  as  part  of  its  COVID-19  Economic  Response  Plan.  The  program  is 
effective  from  March 15, 2020  to  June  2021.  For  the  year  ended  December 31, 2020,  we  recorded  $40 million  in 
other income from the CEWS program. 

In  2020,  we  recognized  $24 million  of  lease  income  (2019  -  $17 million).  Lease  income  is  earned  on  tank 
subleases, operating leases related to our real estate ROU assets in which we are the lessor, and from the recovery 
of  non-lease  components  for  operating  costs  and  unreserved  parking  related  to  our  net  investment  in  finance 
leases. Finance leases are included in other assets as net investment in finance leases. 

DD&A 

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, 
leasehold  improvements,  office  furniture,  and  certain  ROU  assets.  Costs  associated  with  corporate  assets  are 
depreciated  on  a  straight-line  basis  over  the  estimated  service  life  of  the  assets,  which  range  from  three  to 
25 years.  The  service  lives  of  these  assets  are  reviewed  on  an  annual  basis.  ROU  assets  are  depreciated  on  a 
straight-line basis over the shorter of the estimated useful life of the asset or the lease term. DD&A in 2020 was 
$161 million (2019 – $107 million), of which $52 million of previously capitalized PP&E costs relating to information 
technology assets were written off due to synergies identified as a result of the Arrangement. 

(cid:21)(cid:25)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
  
  
  
  
 
 
 
Income Tax 

 ($ millions) 

Current Tax 

Canada 
United States 

Current Tax Expense (Recovery) 

Deferred Tax Expense (Recovery) 

Total Tax Expense (Recovery) 

2020     

2019     

2018   

(14 )     
1       
(13 )     
(838 )     
(851 )     

14       
3       
17       
(814 )     
(797 )     

(128 ) 
2   

(126 ) 

(884 ) 

(1,010 ) 

The  following  table  reconciles  income  taxes  calculated  at  the  Canadian  statutory  rate  with  the  recorded  income 
taxes: 

 ($ millions) 

Earnings (Loss) From Continuing Operations Before Income Tax 

Canadian Statutory Rate (percent)

Expected Income Tax Expense (Recovery) From Continuing Operations 

Effect of Taxes Resulting From: 

Statutory and Other Rate Differences 

Non-Taxable Capital (Gains) Losses 
Non-Recognition of Capital (Gains) Losses 

Adjustments Arising from Prior Year Tax Filings 

Alberta corporate rate reduction 
Recognition of U.S. Tax Basis 

Other 

Total Tax Expense (Recovery) From Continuing Operations 

 Effective Tax Rate (percent) 

2020     
(3,230 )     
24.0       
(775 )     

2019     
1,397       
26.5       
370       

2018   

(3,926 ) 

27.0   

(1,060 ) 

19       
(42 )     
(42 )     
(8 )     
(7 )     
-       
4       
(851 )     

26.3       

(52 )     
(38 )     
(39 )     
4       
(671 )     
(387 )     
16       
(797 )     

(57 ) 

89   
87   

3   

-   
(78 ) 

6   

(1,010 ) 

(57.1 )     

25.7   

Tax  interpretations,  regulations  and  legislation  in  the  various  jurisdictions  in  which  Cenovus  and  its  subsidiaries 
operate  are  subject  to  change.  We  believe  that  our  provision  for  income  taxes  is  adequate.  There  are  usually  a 
number of tax matters under review and with consideration of the current economic environment, income taxes are 
subject  to  measurement  uncertainty.  The  timing  of  the  recognition  of  income  and  deductions  for  the  purpose  of 
current tax expense is determined by relevant tax legislation. 

For the year ended December 31, 2020, a deferred tax recovery was recorded due to an impairment of the Borger 
CGU,  Conventional  CGUs  and  current  period  operating  losses  that  will  be  carried  forward,  excluding  unrealized 
foreign  exchange  gains  and  losses  on  long-term  debt.  In  2020,  the  Government  of  Alberta  accelerated  the 
reduction in the provincial corporate tax rate from 12 percent to eight percent.  

In  2019,  the  Government  of  Alberta  enacted  a  reduction  in  the  provincial  corporate  tax  rate  from 12 percent  to 
eight percent  over  four years.  As  a  result,  the  Company  recorded  a  deferred  income  tax  recovery  of  $671 million 
for  the  year  ended  December 31, 2019.  In  addition,  the  Company  recorded  a  deferred  income  tax  recovery  of 
$387 million  due  to  an  internal  restructuring  of  the  Company’s  U.S.  operations  resulting  in  a  step-up  in  the  tax 
basis of the Company’s refining assets. 

In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down 
of  the  Conventional  E&E  assets  and  a  $78 million  recovery  arising  from  an  adjustment  to  the  tax  basis  of  the 
Company’s refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable 
gain on its interest in WRB Refining LP (“WRB”), which due to an election filed with the U.S. tax authorities, was 
added to the tax basis of WRB’s assets. The maximum recovery related to the carry back of losses to recover tax 
paid was reached in 2018. 

Our  effective  tax  rate  is  a  function  of  the  relationship  between  total  tax  expense  (recovery)  and  the  amount  of 
earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different 
tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates 
and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves, 
differences  between  the  provision  and  the  actual  amounts  subsequently  reported  on  the  tax  returns,  and  other 
permanent differences. 

Capital Investment 

Capital  expenditures  of  $60 million  for  2020  focused  primarily  on  supporting  investments  in  technology  and 
infrastructure to modernize our workplace, improve our cost structure and reduce costs and risk. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:21)(cid:26)

  
         
      
   
  
  
  
  
  
  
  
  
  
       
       
   
  
  
  
  
  
  
  
  
  
DISCONTINUED OPERATIONS 

On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta 
for cash proceeds of $512 million, before closing adjustments. After-tax earnings from discontinued operations for 
the  year  ended  December 31, 2018  were  $27 million.  An  after-tax  gain  on  discontinuance  of  $220 million  was 
recorded on the sale. 

QUARTERLY RESULTS 

Our  results  over  the  last  four  quarters  were  impacted  by  the  volatility  in  commodity  prices  primarily  due  to  the 
impacts  of  COVID-19  and  OPEC  and  non-OPEC  production  output  decisions.  Light  oil  benchmark  prices  were  low 
and  volatile  throughout  the  majority  of  2020,  compared  with  the  price  of  WTI  in  2019.  WTI  fell  19 percent  to 
average US$46.17 per barrel in the first quarter compared with US$56.96 per barrel in the fourth quarter of 2019 
and  dropped  further  to  average  US$27.85 per barrel  in  the  second  quarter  with  a  recovery  to  average 
US$42.66 per barrel  in  the  fourth  quarter.  Average  WTI  and  WCS  benchmark  prices  decreased  25 percent  and 
19 percent, respectively in the fourth quarter of 2020 compared with 2019. As a result, our Operating Margin from 
continuing  operations  was  $625 million  in  the  fourth  quarter  of  2020,  a  decrease  from  $864 million  in  the  fourth 
quarter of 2019. Net Loss was $153 million compared with Net Earnings of $113 million in 2019. 

Selected Operating and Consolidated Financial Results 

($ millions, except per share 
amounts) 

Average Commodity Prices 

Brent 
WTI 
WCS 
Chicago Market Crack Spread 

Production Volumes 

Liquids (barrels per day)
Natural Gas (MMcf per day)
Total Production (BOE per day)

Refinery Operations 

Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)

Q4   

2020 
Q3   

Q2   

Q1   

Q4   

2019 

Q3   

Q2   

Q1   

   45.24     
   42.66     
   33.36     
7.05     

43.37     
40.93     
31.84     
7.89     

33.27     
27.85     
16.38     
6.44     

50.96     
46.17     
25.64     
8.79     

62.50     
56.96     
41.13     
12.27     

62.00     
56.45     
44.21     
16.72     

68.34     
59.83     
49.18     
21.44     

63.88   
54.90   
42.53   
13.57   

  405,280      411,788      400,050      416,802      400,329      380,699      371,390      370,983   
458   
  467,202      471,799      465,415      482,594      467,448      448,496      443,318      447,270   

371     

395     

432     

403     

360     

392     

407     

338     
350     

382     
397     

325     
332     

442     
460     

456     
477     

465     
485     

474     
501     

375   
402   

Revenues 

   3,426     

3,659     

2,174     

3,968     

4,838     

4,736     

5,603     

5,004   

Operating Margin (1)

625     

594     

291     

(589 )   

864     

1,080     

1,277     

1,239   

Cash From (Used in) Operating 
Activities 

Adjusted Funds Flow (2)

Operating Earnings (Loss) 

Per Share (3) ($)

Net Earnings (Loss) 
Per Share (3) ($)

Capital Investment (4)

Dividends 

Cash Dividends 
Per Share ($)

250     

732     

(834 )   

125     

740     

834     

1,275     

436   

341     

414     

(462 )   

(146 )   

687     

928     

1,082     

1,005   

(551 )   
(0.45 )   

(153 )   
(0.12 )   

(452 )   
(0.37 )   

(194 )   
(0.16 )   

(414 )   
(0.34 )   

(1,187 )   
(0.97 )   

(164 )   
(0.13 )   

(235 )   
(0.19 )   

(1,797 )   
(1.46 )   

113     
0.09     

284     
0.23     

187     
0.15     

267     
0.22     

1,784     
1.45     

69   
0.06   

110   
0.09   

242     

148     

147     

304     

317     

294     

248     

317   

-     
-     

-     
-     

-     
61   
-      0.0625      0.0625      0.0500      0.0500      0.0500   

77     

62     

77     

60     

(1)

(2)

(3)
(4)

Additional  subtotal  found  in  Note  1  of  the  Consolidated  Financial  Statements  and  interim  Consolidated  Financial  Statements,  and  defined  in  this 
MD&A. 
Non-GAAP measure defined in this MD&A. The comparative periods have been reclassified to conform with the current period treatment of non-cash 
inventory write-downs and reversals. 
Represented on a basic and diluted per share basis. 
Includes expenditures on PP&E and E&E assets. 

Fourth Quarter 2020 Results Compared With the Fourth Quarter 2019 

Production Volumes 

Total  production  in  the  fourth  quarter  of  2020  was  in  line  with  2019.  The  fourth  quarter  reflects  increased 
production  levels  in  response  to  an  improved  pricing  environment  facilitated  by  the  purchase  of  production 
curtailment  credits  and  lifting  of  the  mandatory  curtailment  level  at  the  beginning  of  December  2020.  This  was 
partially offset by a planned turnaround and maintenance at Christina Lake and operational outages due to process 

(cid:21)(cid:27)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

  
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
  
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
     
     
     
     
     
     
     
   
  
  
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
     
     
     
     
     
     
     
   
  
  
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
 
  
  
     
     
     
     
     
     
     
   
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
  
  
  
    
  
    
  
    
  
    
  
    
  
    
  
   
  
    
  
  
     
     
     
     
     
     
     
   
  
  
  
  
treatment  upsets  at  Foster  Creek.  In  the  fourth  quarter  of  2019,  production  was  limited  due  to  mandatory 
production  curtailments  set  by  the  Government  of  Alberta,  offset  by  curtailment  relief  equivalent  to  incremental 
increases in rail shipments from the Special Production Allowance (“SPA”). 

In  the  fourth  quarter  of  2020,  we  sold  121,595 barrels per day,  approximately  25 percent,  of  our  Oil  Sands 
production at sales locations outside of Alberta compared with 181,366 barrels per day, approximately 35 percent, 
in the fourth quarter of 2019. 

Conventional production in the fourth quarter of 2020 decreased  eight percent to 86,167 BOE per day mainly due 
to  natural  declines  from  lower  sustaining  capital  investment.  Production  from  the  Marten  Hills  assets  was 
approximately 2,000 barrels per day for the quarter. 

Refining and Marketing Operations 

Crude oil runs  of 338,000 gross barrels per day and refined product output of 350,000 gross barrels per day were 
lower  compared  with  the  same  period  in  2019  due  to  economic  crude  rate  reductions  in  response  to  reduced 
demand as a result of COVID-19. In the fourth quarter of 2019 operations were impacted by planned turnaround 
activities  and  a  crude  supply  constraint  at  Wood  River  as  a  result  of  a  Keystone  pipeline  leak,  partially  offset  by 
optimization of the total crude input slate. 

In the fourth quarter of 2020, our crude-by-rail program was reinstated from the temporary suspension announced 
earlier 
loaded  at  our  Bruderheim  crude-by-rail  terminal  averaged 
29,144 barrels per day  (20,423 barrels per day  of  our  volumes)  in  the  fourth  quarter  of  2020  compared  with 
89,630 barrels per day (71,708 barrels per day of our volumes) in the same period of 2019. 

in  the  year.  Total  rail  volumes 

Revenues 

Total  revenues  decreased  $1,412 million  in  the  fourth  quarter  of  2020  compared  with  the  same  period  of  2019. 
Refining and Marketing revenues decreased $1,210 million primarily due to lower refined product pricing consistent 
with  the  declines  in  the  average  refined  product  benchmark  prices  and  lower  refined  product  output  due  to  the 
economic  crude  rate  reductions,  and  decreased  revenues  from  third-party  crude  oil  and  natural  gas  sales 
undertaken by the marketing group. Upstream revenues decreased by $256 million primarily due to lower realized 
liquids  sales  pricing  of  $38.57 per barrel  compared  with  $47.12 per barrel  in  2019,  partially  offset  by  lower 
royalties and decreased sales volumes. 

Operating Margin From Continuing Operations Variance 

(1)

Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending 
expense. The crude oil price excludes the impact of condensate purchases.  

Operating Margin 

Operating Margin decreased in the fourth quarter of 2020 due to: 
(cid:120)
(cid:120)

A lower average liquids sales price as a result of decreased crude oil benchmark prices; 
Lower  Operating  Margin  from  our  Refining  and  Marketing  segment  due  to  lower  market  crack  spreads, 
decreased crude oil runs, lower crude advantage; and 
Increased upstream operating expenses. 

(cid:120)

These decreases were partially offset by lower royalties primarily due to our lower realized crude oil sales price and 
a decrease in our transportation and blending costs due to a decrease in rail transportation costs. 

Cash From Operating Activities and Adjusted Funds Flow 

Total Cash From Operating Activities and Adjusted Funds Flow decreased in the fourth quarter of 2020 compared 
with  the  same  period  in  2019,  primarily due  to  lower  Operating  Margin,  as  discussed  above,  transaction  costs  of 
$29 million and changes in non-cash working capital. Adjusted Funds Flow was further reduced by a $100 million 
loss related to the Keystone XL pipeline project. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:21)(cid:28)

 
 
 
 
The change in non-cash working capital in the fourth quarter of 2020 was primarily due to an increase in accounts 
receivable  and  inventory,  a  decrease  in  income  tax  payable,  and  an  increase  in  income  tax  receivable,  partially 
offset by an increase in accounts payable. For 2019, the change in non-cash working capital was primarily due to 
an increase in accounts payable and a decrease in income tax receivable, partially offset by an increase in accounts 
receivable and inventory. 

Operating Earnings (Loss) 

Operating  Loss  increased  in  the  three  months  ended  December 31, 2020  compared  with  2019  primarily  due  to 
higher  DD&A  due  to  $298 million  in  impairments  and  write-downs,  lower  Cash  From  Operating  Activities  and 
Adjusted  Funds  Flow,  as  discussed  above,  and  higher  non-cash  employee  long-term  incentive  costs  mainly  as  a 
result  of  the  accelerated  vesting  of  our  Employee  Stock  Option  Plan,  performance  share  units  (“PSUs”)  and 
restricted share units (“RSUs”) held by non-executive employees due to the closing of the Arrangement, partially 
offset by non-operating realized foreign exchange losses of $nil compared with $122 million in 2019. 

Net Earnings (Loss) 

Net Loss of $153 million increased for the three months ended December 31, 2020 compared with Net Earnings of 
$113 million in 2019. The change was primarily due to higher Operating Loss, as discussed above, partially offset 
by  non-operating  unrealized  foreign  exchange  gains  of  $358 million  compared  with  $258 million  in  2019  and  a 
deferred income tax recovery of $182 million compared with $24 million in 2019. 

Capital Investment 

Capital  investment  from  continuing  operations  in  the  fourth  quarter  of  2020  was  $242 million,  $75 million  lower 
compared  with  the  fourth  quarter  of  2019,  primarily  due  to  the  reduction  of  our  capital  investment  program  in 
response to COVID-19. 

OIL AND GAS RESERVES 

We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy crude oil, light and medium 
oil, NGLs, conventional natural gas and shale gas proved and probable reserves. 

Reserves 

As at December 31, 2020 
(before royalties)

Proved 

Probable 

Proved plus Probable 

As at December 31, 2019 
(before royalties)

Proved 

Probable 

Proved plus Probable 

Light and 
Medium 
Oil 
(MMbbls)(cid:3)(cid:3)(cid:3)
7       

NGLs 
(MMbbls)(cid:3)(cid:3)(cid:3)
50       

6       

13       

31       

81       

Bitumen(cid:3)
(MMbbls)(cid:3)(cid:3)

4,812       
1,520       
6,332       

Conventional(cid:3)
Natural
Gas (1)

(Bcf)(cid:3)(cid:3)  

Total(cid:3)
(MMBOE)(cid:3)(cid:3)

965       

5,030   

601       

1,656   

1,566       

6,686   

Light and 
Medium 
Oil 
(MMbbls)(cid:3)(cid:3)(cid:3)

NGLs 
(MMbbls)(cid:3)(cid:3)(cid:3)

Conventional(cid:3)
Natural
Gas (1)
(Bcf)(cid:3)(cid:3)

Total(cid:3)
(MMBOE)(cid:3)

Bitumen (2) 
(MMbbls)(cid:3)(cid:3)(cid:3)

4,826       
1,594       
6,420       

9       

8       

17       

60       

37       

97       

1,242       

5,103  

783       

1,768  

2,025       

6,871   

(1)
(2)

Includes shale gas reserves that are not material.  
Includes heavy crude oil reserves that are not material. 

Developments in 2020 compared with 2019 include: 

(cid:120)

(cid:120)

(cid:120)

(cid:120)

Bitumen  proved  and  proved  plus  probable  reserves  decreasing  14 million  barrels  and  88 million  barrels, 
respectively, as additions from improved performance in Oil Sands were more than offset by the Marten Hills 
disposition and current year production; 
Light and medium oil proved and proved plus probable reserves decreasing two million barrels and four million 
barrels, respectively, as minor additions were more than offset by technical revisions attributed to  updates to 
the Conventional development plan, reduced product pricing and current year production; 
NGLs  proved  and  proved  plus  probable  reserves  decreasing  10 million  barrels  and  16 million  barrels, 
respectively, as minor additions and a minor acquisition were more than offset by reductions due to technical 
revisions  attributed  to  updates  to  the  Conventional  development  plan,  reduced  product  pricing  and  current 
year production; and 
Conventional  natural  gas  proved  and  proved  plus  probable  reserves  decreasing  277 billion  cubic  feet  and 
459 billion  cubic  feet,  respectively,  as  minor  additions  and  a  minor  acquisition  were  more  than  offset  by 

(cid:22)(cid:19)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
 
  
  
  
  
     
  
  
     
  
  
     
  
  
     
  
  
  
  
  
 
 
 
 
 
  
  
  
  
     
  
  
     
  
  
     
  
  
     
  
  
  
  
  
 
reductions  due  to  technical  revisions  attributed  to  updates  to  the  Conventional  development  plan,  reduced 
product pricing and current year production. 

The reserves data is presented as at December 31, 2020 using an average of forecasts (“IQRE Average Forecast”) 
by  McDaniel &  Associates  Consultants Ltd.  (“McDaniel”),  GLJ  Ltd.  (“GLJ”)  and  Sproule  Associates  Limited 
(“Sproule”). The IQRE Average Forecast prices and costs are dated January 1, 2021. Comparative information as at 
December 31, 2019 uses the January 1, 2020 IQRE Average Forecast prices and costs. 

As a result of the close of the Arrangement on January 1, 2021, including reported reserves from Husky, our total 
proved  reserves  and  total  proved  plus  probable  reserves  are  anticipated  to  increase  by  approximately 
1.2 billion BOE and 1.8 billion BOE, respectively. 

Additional  information  with  respect  to  the  evaluation  and  reporting  of  our  reserves  in  accordance  with  National 
Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) is contained in our AIF for the 
year  ended  December 31, 2020.  Our  AIF  is  available  on  SEDAR  at  sedar.com,  on  EDGAR  at  sec.gov  and  on  our 
website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this 
MD&A in the Risk Management and Risk Factors section and the Advisory section in this MD&A. 

Information  concerning  Husky  and  its  reserves  data  and  other  oil  and  gas  information  as  of  December  31,  2020 
may be found in the Husky AIF and the Husky MD&A, each of which is filed and available on SEDAR under Husky’s 
profile at sedar.com. 

LIQUIDITY AND CAPITAL RESOURCES 

($ millions) 

Cash From (Used in) 

Operating Activities 

Investing Activities 

Net Cash Provided (Used) Before Financing Activities 

Financing Activities 
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents 
Held in Foreign Currency 

Increase (Decrease) in Cash and Cash Equivalents 

As at December 31, 
Cash and Cash Equivalents 
Debt 

2020     

2019     

2018   

273       
(863 )     
(590 )     
837       

(55 )     
192       

2020     

378       
7,562       

3,285       
(1,432 )     
1,853       
(2,413 )     

(35 )     
(595 )     

2019     

186       
6,699       

2,154   

(613 ) 

1,541   

(1,410 ) 

40   

171   

2018   
781   
9,164   

As at December 31, 2020, we were in compliance with all of the terms of our debt agreements. 

Cash From (Used in) Operating Activities 

For  the  year  ended  December 31, 2020,  cash  generated  by  operating  activities  decreased  mainly  due  to  lower 
Operating Margin, transaction costs of $29 million, partially offset by funding from the CEWS program and sublease 
income, and lower current taxes, as discussed in the Corporate and Eliminations section of this MD&A, and changes 
in non-cash working capital, as discussed in the Operating and Financial Results section of this MD&A. 

Excluding 
December 31, 2020 compared with $842 million at December 31, 2019. 

the  current  portion  of 

the  contingent  payment,  our  working  capital  was $653 million  at 

We anticipate that we will continue to meet our payment obligations as they come due. 

Cash From (Used in) Investing Activities 

Cash  used  in  investing  activities  was  lower  in  2020  compared  with  2019  primarily  due  to  decreased  capital 
investment in 2020. 

Cash From (Used in) Financing Activities 

In the first quarter of 2020, we repurchased US$100 million of unsecured notes for cash of US$81 million. In the 
third quarter of 2020 we issued US$1.0 billion in 5.375 percent senior unsecured notes due in 2025 and used the 
proceeds to repay $1.4 billion of borrowings on our committed credit facility. 

In  2019,  cash  was  used  in  financing  activities  primarily  for  the  repayment  of  debt.  We  repaid  US$1.8 billion  of 
unsecured notes for cash consideration of US$1.7 billion ($2.3 billion). 

Total  debt,  including  short-term  borrowings,  as  at  December 31, 2020  was  $7,562 million  (December 31, 2019  – 
$6,699 million). 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:22)(cid:20)

 
  
       
       
   
  
  
  
  
  
  
  
    
        
        
  
  
  
 
Common Share Dividends 

On  April 2, 2020  we  announced  the  temporary  suspension  of  our  common  share  dividend  in  response  to  the  low 
global  crude  oil  price  environment.  Prior  to  the  suspension,  we  paid  common  share  dividends  of  $77 million  or 
0.0625 per  common  share  in  the  first  quarter  of  2020  (year  ended  December 31, 2019  –  $260 million  or 
$0.2125 per common share). The declaration of dividends is at the sole discretion of the Board and is considered 
quarterly. The Board declared a first quarter dividend of $0.0175 per common share, payable on March 31, 2021 to 
common shareholders of record as of March 15, 2021. 

Cumulative Redeemable Preferred Share Dividend 

The  Board  declared  a  first  quarter  dividend  on  the  Series  1,  2,  3,  5,  and  7  preferred  shares,  payable  on 
March 31, 2021, in the amount of $8 million. 

Available Sources of Liquidity 

The following sources of liquidity are available at December 31, 2020: 

($ millions) 
Cash and Cash Equivalents 
Committed Credit Facilities 

Revolving Credit Facility (cid:177) Tranche A 
Revolving Credit Facility (cid:177) Tranche B 

Uncommitted Demand Facilities 

Cenovus Energy Inc. 
WRB Refining LP (Cenovus's proportionate share) 

Term     
Not applicable       

Amount 
Available   
378   

November 2023       
November 2022       

3,300   
1,200   

Not applicable       
Not applicable       

600   
70   

In  light  of  the  current  challenging  economic  conditions,  we  expect  to  fund  our  near-term  cash  requirements 
through  cash  from  operating  activities  and  prudent  use  of  our  balance  sheet  capacity  including  draws  on  our 
committed  credit  facilities  and  our  uncommitted demand  facilities  and  other  corporate and  financial  opportunities 
that may be available to us. 

Committed Credit Facilities 

As  at  December 31, 2020,  we  had  a  total  committed  credit  facility  of  $4.5 billion  that  consisted  of  a  $1.2 billion 
tranche  maturing  on  November 30, 2022  and  a  $3.3 billion  tranche  maturing  November 30, 2023.  During  the 
second quarter, we added a committed credit facility with capacity of $1.1 billion, with a term of 364 days that was 
renewable for one year at our request and upon approval by the lenders, to further support our financial resilience. 
On  December 31, 2020,  we  cancelled  the  $1.1 billion  committed  credit  facility.  As  at  December 31, 2020,  no 
amount was drawn on the committed credit facility (December 31, 2019 - $265 million). 

Uncommitted Demand Facilities 

As  at  December 31, 2020,  Cenovus  had  uncommitted  demand  facilities  of  $1.6 billion  in  place,  of  which 
$600 million may be drawn for general purposes or the full amount can be available to issue letters of credit. As at 
December 31, 2020, the Company had drawn no amounts (December 31, 2019 - $nil) on these facilities and there 
were outstanding letters of credit aggregating to $441 million (December 31, 2019 - $364 million).  

WRB has uncommitted demand facilities of US$300 million (the Company’s proportionate share  - US$150 million) 
available to cover short-term working capital requirements. As at December 31, 2020, US$190 million was drawn 
on 
the  Company’s  proportionate  share 
(December 31, 2019 – $nil). 

facilities,  of  which  US$95 million  ($121 million)  was 

these 

Base Shelf Prospectus 

Cenovus has in place a base shelf prospectus that allows us to offer, from time to time, up to US$5.0 billion, or the 
equivalent  in  other  currencies,  of  debt  securities,  common  shares,  preferred  shares,  subscription  receipts, 
warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base 
shelf  prospectus will  expire  in October 2021. On  July 30, 2020,  we completed  a public  offering  in  the U.S.,  under 
the U.S. base shelf prospectus, of senior unsecured notes in the aggregate principal amount of US$1.0 billion due 
in 2025. As at December 31, 2020, US$3.7 billion remained available under the base shelf prospectus for permitted 
offerings. 

Financial Metrics 

We  monitor  our  capital  structure  and  financing  requirements  using,  among  other  things,  non-GAAP  financial 
metrics  consisting  of  Net  Debt  to  Adjusted  EBITDA  and  Net  Debt  to  Capitalization.  We  define  our  non-GAAP 
measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of 
cash  and  cash  equivalents  and  short-term  investments.  We  define  Capitalization  as  Net  Debt  plus  Shareholders’ 
Equity.  We  define  Adjusted  EBITDA  as  net  earnings  before  finance  costs,  interest  income,  income  tax  expense 
(recovery),  DD&A,  E&E  write-down,  goodwill  impairments,  asset  impairments  and  reversals,  unrealized  gains 
(losses)  on  risk  management,  foreign  exchange  gains  (losses),  revaluation  gain,  re-measurement  of  contingent 

(cid:22)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

       
   
       
   
 
payment,  gains  (losses)  on  divestiture  of  assets,  and  other  income  (loss),  net,  calculated  on  a  trailing  twelve-
month basis. These measures are used to steward our overall debt position and as measures of our overall financial 
strength. 

As at December 31, 
Net Debt to Capitalization (1) (percent)(cid:3)
Net Debt to Adjusted EBITDA (times)(cid:3)

2020     

30       

11.9x     

2019     
25     
1.6x     

2018 
32 
5.8x 

(1)
(2)

Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity. 
On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

A reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA can be found in Note 24 of 
the Consolidated Financial Statements. 

Cenovus  targets  a  Net  Debt  to  Adjusted  EBITDA  ratio  of  less  than  2.0 times  over  the  long-term.  This  ratio  may 
periodically  be  above  the  target  due  to  factors  such  as  persistently  low  commodity  prices.  Our  objective  is  to 
maintain  a  high  level  of  capital  discipline  and  manage  our  capital  structure  to  help  ensure  the  Company  has 
sufficient  liquidity  through  all  stages  of  the  economic  cycle.  To  ensure  financial  resilience,  Cenovus  may,  among 
other  actions,  adjust  capital  and  operating  spending,  draw  down  on  our  credit  facilities  or  repay  existing  debt, 
adjust  dividends  paid  to  shareholders,  repurchase  our  common  shares  for  cancellation,  issue  new  debt,  or  issue 
new shares.  

As at December 31, 2020, Cenovus’s Net Debt to Adjusted EBITDA was 11.9 times. Net Debt to Adjusted EBITDA 
increased  compared  with  December 31, 2019  as  a  result  of  an  increase  in  our  borrowings,  as  mentioned  in  the 
Cash From (Used In) Financing Activities above, and a reduction in our trailing twelve-month adjusted EBITDA. 

We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenants as defined 
in  our committed credit facility  agreements.  Under  the  terms of Cenovus’s committed credit  facility  at  the  end  of 
the year, we were required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 
65 percent. We were well below this limit at December 31, 2020. 

Additional  information  regarding  our  financial  measures  and  capital  structure  can  be  found  in  the  notes  to  the 
Consolidated Financial Statements. 

Share Capital and Stock-Based Compensation Plans 

As  at  December 31, 2020,  there  were  approximately  1,229 million  common  shares  outstanding  (2019 – 
1,229 million common shares). Refer to Note 30 of the Consolidated Financial Statements for more details. 

Refer to Note 32 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, 
RSU and deferred share unit (“DSU”) Plans. 
Our outstanding share data is as follows: 

As at January 31, 2021 
Common Shares (1)
Common Share Warrants 
Preferred Shares Series 1 
Preferred Shares Series 2 
Preferred Shares Series 3 
Preferred Shares Series 5 
Preferred Shares Series 7 
Stock Options (2)
Other Stock-Based Compensation Plans 

Units 
Outstanding

(thousands)   
     2,017,404     
65,418     
10,436     
1,564     
10,000     
8,000     
6,000     
30,499       
3,715       

Units 
Exercisable
(thousands)

N/A   
N/A   
N/A   
N/A   
N/A   
N/A   
N/A   
23,305   
1,293   

(1)
(2)

ConocoPhillips continued to hold 208 million common shares issued as partial consideration related to the Conoco Acquisition. 
Includes  Cenovus  Replacement  Options  (defined  below)  issued  pursuant  to  the  Arrangement  in  replacement  of  all  issued  and  outstanding  Husky 
stock options. 

Capital Investment Decisions 

Our approach on the financial framework of the combined company will be consistent with the parameters we have 
set for Cenovus in prior years. We will continue to evaluate all opportunities based on a US$45.00 per barrel WTI 
price with  the  objective  of  maintaining  a  prudent  and  flexible  capital  structure  and strong  balance  sheet  metrics. 
This approach positions us to be financially resilient in times of lower cash flows. Balance sheet strength continues 
to be a top priority and we plan to continue to direct our Free Funds Flow towards debt reduction. We continue to 
target a Net Debt to EBITDA ratio not to exceed two times. 

Our  2021  capital  program  for  the  combined  company  is  forecast  to  be  between  $2.3 billion  and  $2.7 billion.  The 
budget  is  focused  on  maintaining  safe  and  reliable  operations  while  positioning  the  Company  to  drive  enhanced 
shareholder  value  and  includes  sustaining  capital  of  approximately  $2.1 billion  to  deliver  upstream  production  of 
approximately 755,000 BOE per day and downstream throughput of approximately 525,000 barrels per day. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:22)(cid:22)

 
  
 
 
  
    
    
    
    
    
    
    
    
($ millions) 
Adjusted Funds Flow (1)
Total Capital Investment 
Free Funds Flow (1) (2)
Cash Dividends 

2020     

147       
841       
(694 )     
77       
(771 )     

2019     
3,702       
1,176       
2,526       
260       
2,266       

2018   

1,721   
1,363   

358   

245   

113   

(1)
(2)

The comparative period has been reclassified to conform with current period treatment of non-cash inventory write-downs and reversals. 
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment. 

We remain committed to maintaining and improving our current investment-grade credit ratings. This includes our 
continued  focus  on  allocating  free  funds  flow  to  reduce  Net  Debt  to  less  than  $10  billion  and  targeting  a  longer-
term Net Debt level at or below $8 billion. 

The  combined  company’s  adjusted  funds  flow  is  expected  to  fully  fund  sustaining  capital  and  shareholder 
first  quarter  dividend  of  $0.0175 per common share,  payable  on 
distributions.  The  Board  declared  a 
March 31, 2021,  to  common  shareholders  of  record  as  of  March 15, 2021.  The  Board  declared  a  first  quarter 
dividend on the Series 1, 2, 3, 5, and 7 preferred shares, payable on March 31, 2021, in the amount of $8 million. 

Contractual Obligations and Commitments 

Cenovus  has  obligations  for  goods  and  services  entered  into  in  the  normal  course  of  business.  Obligations  are 
primarily  related  to  transportation  agreements,  our  risk  management  program  and  an  obligation  to  fund  our 
defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less 
than one year are excluded. For further information, see the notes to Consolidated Financial Statements. 

As  at December 31, 2020,  total  commitments were $23 billion,  of  which $21 billion  are for  various  transportation 
and  storage  commitments.  Terms  are  up  to  20 years  subsequent  to  the  date  of  commencement  and  should  help 
align  with  the  Company’s  future  transportation  requirements  with  anticipated  production  growth.  Transportation 
and storage commitments include future commitments relating to storage tank leases of $31 million, that have not 
yet commenced. 

($ millions) 

2021     

2022     

2023     

2024     

2025     Thereafter   (cid:3)(cid:3)

Total   

Expected Payment Date 

Commitments 

Transportation and Storage (1)(cid:3)
Real Estate (2)(cid:3)
Capital Commitments 
Other Long-Term Commitments 

Total Commitments (3)(cid:3)
Other Obligations 

   1,014       
34       
1       
104       

954        1,341        1,444        1,107        15,537        21,397   
797   
3   
322   
   1,153        1,037        1,411        1,517        1,175        16,226        22,519   

604       
-       
85       

36       
2       
45       

38       
-       
32       

41       
-       
32       

44       
-       
24       

Long-term Debt (Principal and Interest) 
Decommissioning Liabilities 
Contingent Payment 
Lease Liabilities (Principal and Interest) (4)(cid:3)   

Total Commitments and Obligations 

385        1,024       
45       
28       
237       

8,627        12,943   
2,429        2,639   
64   
1,412        2,476   
   1,869        2,371        2,601        2,108        2,998        28,694        40,641   

346        1,620       
41       
-       
162       

941       
41       
-       
208       

41       
36       
254       

42       
-       
203       

-       

(1)

(2)

(3)
(4)

Includes  transportation  commitments  of  $14 billion  (December 31, 2019  –  $13 billion)  that  are  subject  to  regulatory  approval  or  have  been 
approved but are not yet in service.  
Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed 
payments for which a provision has been provided. 
Contracts undertaken on behalf of WRB are reflected at our 50 percent interest. 
Lease contracts related to office space, railcars, storage assets, drilling rigs and other refining and field equipment. 

We continue to focus on mid-term strategies to broaden market access for our crude oil production. We continue to 
support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our 
crude oil production to market by rail, and assessing options to maximize the value of our crude oil. 

As at December 31, 2020, there were outstanding letters of credit  aggregating $441 million issued as security for 
performance under certain contracts (December 31, 2019 – $364 million). 

Liquidity and Capital Resources Subsequent to the Arrangement 

Share Capital and Stock-Based Compensation 

At  the  closing  of  the  Arrangement  on  January 1, 2021,  we  acquired  all  of  the  issued  and  outstanding  Husky 
common shares in consideration for the issuance of 0.7845 Cenovus common shares and 0.0651 Cenovus warrants 
(“Cenovus Warrants”) for each Husky common share. All the issued and outstanding Husky preferred  shares were 
exchanged for  Cenovus  preferred  shares with  substantially  identical  terms,  and  all  issued  and  outstanding  Husky 
stock  options  were  exchanged  for  Cenovus  replacement  stock  options  (“Cenovus  Replacement  Options”).  Each 
Cenovus Replacement Option entitles the holder to acquire 0.7845 of a Cenovus common share at an exercise price 
per  share  of  a  Husky  stock  option  divided  by  0.7845.  Refer  to  Notes  30  and  39  of  the  Consolidated  Financial 
Statements for more details. 

(cid:22)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

  
  
  
  
  
  
 
 
 
  
  
  
  
  
  
  
  
     
  
  
     
  
  
     
  
  
     
  
  
     
  
  
  
  
  
  
  
  
       
       
       
       
       
       
   
  
  
  
  
  
  
  
  
  
  
       
       
       
       
       
       
   
  
  
  
  
  
  
  
  
The  Arrangement  resulted  in the  accelerated vesting  of  certain  stock-based compensation  plans  of  the Company. 
Refer  to  Notes  32  and  39  of  the  Consolidated  Financial  Statements  for  more  details.  In  accordance  with  their 
terms,  the  PSUs  and  RSUs  may  be  settled,  at  the  discretion  of  Cenovus,  in  Cenovus  common  shares,  cash,  or  a 
combination of both based on the 30-day volume weighted average trading price prior to the date of closing. The 
obligations associated all PSUs and RSUs that were settled in connection with the completion of the Arrangement 
were paid in cash in January 2021. 

In  connection  with  the  Arrangement,  a  DSU  holder  that  ceased  to  be  a  Cenovus  director  or  employee  will  be 
entitled to the settlement and redemption of  their DSUs, in cash based on the five day volume weighted average 
trading prior to the date of redemption, in accordance with the terms of the related DSU Plan.  

Liquidity and Commitments 

At  closing  of  the  Arrangement  on  January 1, 2021,  Cenovus  obtained  access  to  additional  sources  of  capital 
including:  $735 million  in  cash  and  cash  equivalents,  $3.7 billion  available  on  Husky’s  committed  credit  facilities 
and  $508 million  available  on  Husky’s  uncommitted  demand  facilities.  Husky’s  committed  credit  facilities  have  a 
capacity of $4.0 billion and its uncommitted demand facilities have a capacity of $975 million, of which $850 million 
may be drawn for general purposes, or the full amount can be available to issue letters of credit. 

We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor 
Service (“Moody’s”) and DBRS Limited and re-establishing investment grade ratings at Fitch Ratings (“Fitch”). The 
cost  and  availability  of  borrowing,  and  access  to  sources  of  liquidity  and  capital  is  dependent  on  current  credit 
ratings as determined by independent rating agencies and market conditions. 

The  Arrangement  resulted  in  the  assumption  of  Husky’s  known  non-cancellable  contracts  and  other  commercial 
commitments.  On  January  1,  2021,  total  commitments  assumed by Cenovus  were  $19 billion,  of which  $2 billion 
were for various transportation commitments that are subject to regulatory approval or have been approved, but 
are not yet in service. 

Additional  information  concerning  Husky's  liquidity  and  commitments  as  of  December  31,  2020  may  be  found 
under  the  sections  Sources  of  Liquidity  and  Contractual  Obligations,  Commitments  and  Off-Balance  Sheet 
Arrangements in the Husky MD&A, which is filed and available on SEDAR under Husky’s profile at sedar.com. 

Legal Proceedings 

We  are  involved  in  a  limited number of  legal  claims  associated  with  the  normal course of  operations.  We believe 
that  any  liabilities  that  might  arise  from  such  matters,  to  the  extent  not  provided  for,  are  not  likely  to  have  a 
material effect on our Consolidated Financial Statements. 

Contingent Payment 

In  connection with  the  Conoco  Acquisition  and related  to  our  Oil  Sands production,  we agreed  to  make quarterly 
payments  to  ConocoPhillips  during  the  five  years  subsequent  to  May 17, 2017  for  quarters  in  which  the  average 
WCS crude oil price exceeds $52 per barrel during the quarter. As at December 31, 2020, the estimated fair value 
of  the  contingent  payment  was  $63 million.  As  at  December 31, 2020,  no  amount  was  payable  under  the 
agreement. See the Corporate and Eliminations section of this MD&A for more details.

RISK MANAGEMENT AND RISK FACTORS 

We  are  exposed  to  a  number  of  risks  through  the pursuit of  our  strategic objectives. Some  of  these risks  impact 
the energy industry as a whole and others are unique to our operations. The impact of any risk or a combination of 
risks  may  adversely  affect,  among  other  things,  Cenovus’s  business,  reputation,  financial  condition,  results  of 
operations  and  cash  flows,  which  may  reduce  or  restrict  our  ability  to  pursue  our  strategic  priorities,  respond  to 
changes in our operating environment, pay dividends to our shareholders and fulfill our obligations (including debt 
servicing requirements) and may materially affect the market price of our securities. 

Our  Enterprise  Risk  Management  (“ERM”)  program  drives  the  identification,  measurement,  prioritization,  and 
management  of  Cenovus’s  risk  and  is  integrated  with  our  Operations  Management  Systems.  In  addition,  we 
continuously monitor our risk profile as well as industry best practices. 

Risk Governance 

The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the 
roles and responsibilities of all staff. Building on the ERM Policy, we have established risk management standards, 
a risk management framework and risk assessment tools, including risk matrices. Our risk management framework 
contains  the  key  attributes  recommended  by  the  International  Organization  for  Standardization  (“ISO”)  in  its 
ISO 31000 –  Risk  Management  Guidelines.  The  results  of  our  ERM  program  are  documented  in  an  Annual  Risk 
Report presented to the Board as well as through regular updates. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:22)(cid:24)

Risk Factors 

The  following  discussion  describes  the  financial,  operational,  regulatory,  environmental,  reputational  and  other 
risks  related  to  Cenovus.  Each  risk  identified  in  this  MD&A  may  individually,  or  in  combination  with  other  risks, 
have  a  material  impact  on  our  business,  financial  condition,  results  of  operations,  cash  flows,  or  reputation  and 
should be considered when purchasing securities of Cenovus. 

Pandemic Risk 

The COVID-19 pandemic and measures taken in response by governments and health authorities around the world 
have  resulted  in  a  significant  slow-down  in  global  economic  activity  that  has  reduced  the  demand  for,  and 
adversely affected the prices of, commodities that are closely linked to Cenovus’s financial performance, including 
crude oil, refined products (such as jet fuel, diesel and gasoline), natural gas and electricity, and also increases the 
risk  that  storage  for  crude  oil  and  refined  products  could  reach  capacity  in  certain  geographic  locations  in  which 
Cenovus operates variant strains of COVID-19 have been identified. While some economies have started to re-open 
and vaccines have been developed, resurgences in cases of COVID-19 have occurred in certain locations and the 
risk of additional resurgences in other locations remains high. This creates ongoing uncertainty that has resulted in 
and  could  result  in  further  restrictions  on  movement  and  businesses  being  re-imposed  or  imposed  on  a  stricter 
basis,  which  could  negatively  impact  demand  for  commodities  and  commodity  prices  and  negatively  impact  our 
business, results of operations and financial condition. It is impossible at this point to predict precisely the duration 
or extent of the impacts of the COVID-19 pandemic on Cenovus's employees, customers, partners and business or 
when economic activity will normalize. 

The COVID-19 pandemic may increase our exposure to, and magnitude of, each of the risks identified in the Risk 
Management  and  Risk Factors  section of  this MD&A.  Our business, financial  condition, results of  operations,  cash 
flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund dividend payments and/or 
business  plans  may,  in  particular,  without  limitation,  be  adversely  impacted  as  a  result  of  the  pandemic  and/or 
decline in commodity prices as a result of: 

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The  shut-down  of  facilities  or  the  delay  or  suspension  of  work  on  major  capital  projects  due  to  workforce 
disruptions or labour shortages caused by workers becoming infected with COVID-19, or government or health 
authority mandated restrictions on travel by workers or closure of facilities, workforce camps or worksites; 
Disruptions  to  global supply  chains,  such  as suppliers  and third-party vendors  experiencing  similar  workforce 
disruptions or being ordered to cease operations;  
Reduced  cash  flows  resulting  in  less  funds  from  operations  being  available  to  fund  our  capital  expenditure 
budget; 
Reduced commodity prices resulting in a reduction in the volumes and value of our reserves. See "Commodity 
Prices" below; 
Commodity storage constraints resulting in the curtailment or shutting in of production; 
A decrease in refined product volumes, the demand for refined products, or refinery utilization rates; 
Counterparties being unable to fulfill their contractual obligations to us on a timely basis or at all; 
The  inability  to  deliver  products  to  customers  or  otherwise  get  products  to  market  caused  by  border 
restrictions,  road  or  port  closures  or  pipeline  shut-ins,  including  as  a  result  of  pipeline  companies  suffering 
workforce disruptions or otherwise being unable to continue to operate;  
The capabilities of our information technology systems and the potential heightened threat of a cyber-security 
breach arising from the number of employees, customers, and partners working remotely; and 
Our ability to obtain additional capital including, but not limited to, debt and equity financing  being adversely 
impacted  as  a  result  of  unpredictable  financial  markets,  commodity  prices  and/or  a  change  in  market 
fundamentals. 

The  extent  to  which  COVID-19  impacts  our  business,  results  of  operations  and  financial  condition  will  depend  on 
future  developments,  which  are  highly  uncertain  and  are  difficult  to  predict,  including,  but  not  limited  to,  the 
severity, duration, spread or resurgence of COVID-19 or any variants thereof; the timing, extent and effectiveness 
of  actions  taken  to  contain  or  treat  COVID-19  or  its  variants,  including  the  availability,  distribution  rate  and 
effectiveness  of  any  vaccines;  and  the  speed  and  extent  to  which  normal  economic  and  operating  conditions 
resume. The potential impacts of COVID-19 to our business, results of operations and financial condition could be 
more significant in the current year as compared with 2020. Even after the COVID-19 pandemic has subsided, we 
may  continue  to  experience  materially  adverse  impacts  to  our  business  as  a  result  of  the  pandemic's  global 
economic impact. 

There are no comparable recent events that provide guidance as to the effect the spread of COVID-19 as a global 
pandemic  may  have,  and,  as  a  result,  the  ultimate  impact  of  the  outbreak  is  highly  uncertain  and  subject  to 
change. Management does not yet know the full extent of the impacts on our business and operations or the global 
economy as a whole. 

We  have  taken  proactive  steps  to  protect  the  health  and safety of our  staff  and  the  continuity  of  our business  in 
response  to  the  COVID-19  pandemic.  We  continue  to  follow  guidance  received  from  the  Federal,  Provincial  and 
state  governments  and  public  health  officials.  We  also  have  a  comprehensive  Business  Continuity  Plan  to  ensure 
continued safe and reliable operations in the event of a COVID-19 outbreak at any of our workplaces. Despite our 
best efforts, the COVID-19 pandemic may result in new legal disputes, including class action claims. 

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Financial Risk 

Financial  risk  is  the  risk  of  loss  or  lost  opportunity  resulting  from  financial  management  and  market  conditions. 
Financial  risks  include,  but  are  not  limited  to:  fluctuations  in  commodity  prices,  development  or  operating  costs; 
risks  related  to  Cenovus’s  hedging  activities;  exposure  to  counterparties;  availability  of  capital  and  access  to 
sufficient liquidity; risks related to Cenovus’s credit ratings; and fluctuations in foreign exchange and interest rates. 
In addition, we identify risks related to our ability to pay a dividend to shareholders; and risks related to internal 
control over financial reporting (“ICFR”). Changes in financial management and/or market conditions could  impact 
a  number  of  factors  including,  but  not  limited  to,  Cenovus’s  cash  flows,  Cenovus's  ability  to  maintain  desirable 
ratios  of  debt  (and  Net  Debt)  to  Adjusted  EBITDA  as  well  as  debt  (and  Net  Debt)  to  capitalization,  Cenovus’s 
financial  condition,  results  of  operations  and  growth,  the  maintenance  of  our  existing  operations  and  business 
plans, financial strength of our counterparties, access to capital and cost of borrowing.  

Excess Crude Oil Supply Risk 

It is not known how long low commodity price conditions will continue, however if the situation continues, worsens 
or is exacerbated further by the impact of COVID-19, and global crude oil prices remain low for a prolonged period, 
our  production,  project  development,  profitability,  cash  flows,  ability  to  access  additional  capital,  and  securities 
trading price, among other things, could be adversely impacted. While OPEC members agreed to certain production 
cuts  through  April  2022  and  have  reconfirmed  their  commitment  to  a  stable  oil  market  amid  the  global  demand 
reduction caused by the pandemic, the stated reductions have since been varied and  there can be no assurances 
that  OPEC  members  and  other  oil  exporting  nations  will  abide  by  the  agreed  reductions  or  continue  to  agree  to 
actions  to  stabilize  oil  prices.  Uncertainty  regarding  the  future  actions  of  such  nations  may  lead  to  increased 
commodity price volatility. See "Commodity Prices" below. 

Commodity Prices 

Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural 
gas  and  NGLs.  Crude  oil  prices  are  impacted  by  a  number  of  factors  including,  but  not  limited  to:  global  and 
regional  supply  of  and  demand for crude  oil; global  economic  conditions  including factors  impacting  global  trade; 
the  actions  of  OPEC  and  other  oil  exporting  nations  including,  without  limitation,  compliance  or  non-compliance 
with  quotas  agreed  upon  by  OPEC  members  and  decisions  by  OPEC  not  to  impose  production  quotas  on  its 
members; actions by the Government of Alberta including, without limitation, imposing, amending, or lifting crude 
oil  production  curtailments  or  SPA  for  crude-by-rail,  and  compliance  or  non-compliance  with  imposed  crude  oil 
production curtailments or SPA for crude-by-rail; enforcement of government or environmental regulations; public 
sentiment towards the use of non-renewable resources, including crude oil; political stability and social conditions 
in  oil  producing  countries,  market  access  constraints  and  transportation  interruptions  (pipeline,  marine  or  rail); 
prices and availability of alternate fuel sources; outbreak of war; outbreak or continuation of a pandemic; terrorist 
threats; technological developments; the occurrence of natural disasters; and weather conditions.  

Cenovus’s  natural  gas  and  NGL  production  is  currently  located  in  Western  Canada  and  Asia  Pacific.  Western 
Canadian  natural  gas  prices  are  impacted  by  a  number  of  factors  including,  but  not  limited  to:  North  American 
supply  and  demand;  developments  related  to  the  market  for  liquefied  natural  gas;  prices  and  availability  of 
alternate  sources of  energy; government or environmental regulations;  public  sentiment  towards  the  use of  non-
renewable resources, including natural gas and NGLs; market access constraints and transportation interruptions; 
economic conditions; technological developments; the occurrence of natural disasters; and weather conditions. 

Refined product prices are impacted by a number of factors including, but not limited to: global and regional supply 
and  demand  for  refined  products;  market  competitiveness;  levels  of  refined  product  inventories;  refinery 
availability;  planned  and  unplanned  refinery maintenance;  current  and  potential  future environmental regulations 
pertaining  to  the  production  and  use  of  refined  products;  prices  and  availability  of  alternate  sources  of  energy; 
public  sentiment  towards  the  use  of  refined  products;  prices  and  the  availability  of  alternate  fuel  sources; 
technological developments; the occurrence of natural disasters; and weather conditions. In addition, and relating 
to the level of future demand (and corresponding price levels) for each of crude oil, refined products and natural 
gas, there has been a significant increase in focus recently on the timing for and pace of the transition to a lower-
carbon economy. See “Climate Change Transition – Demand and Commodity Prices” below. All of these factors are 
beyond  our  control  and  can  result  in  a  high  degree  of  price  volatility.  Fluctuations  in  currency  exchange  rates 
further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in 
Canadian dollars. 

Our financial performance is also impacted by discounted or reduced commodity prices for our oil sands production 
relative  to  certain  international  benchmark  prices,  due,  in  part,  to  constraints  on  the  ability  to  transport  and  sell 
products  to  domestic  or  international  markets  and  the  quality  of oil  produced.  Of  particular  importance  to  us  are 
diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy 
crude oil. Bitumen is more expensive for refineries to process and therefore generally trades at a discount to the 
market price for light and medium crude oil and heavy crude oil. 

The  financial  performance  of  our  refining  operations  is  impacted  by  the  relationship,  or  margin,  between  refined 
product prices and the prices of refinery feedstock. Refining margins are subject to  seasonal factors as production 
changes  to  match  seasonal  demand.  Sales  volumes,  prices,  inventory  levels  and  inventory  values  will  fluctuate 

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accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact 
on our business. 

Fluctuations in the price of commodities, associated price differentials and refining margins may impact our ability 
to meet guidance targets, the value of our assets, our cash flows and our ability to maintain our business and fund 
projects. A substantial decline in these commodity prices or extended period of low commodity prices may result in 
an inability to meet all of our financial obligations as they come due, a delay or cancellation of existing or future 
drilling, development or construction programs, curtailment in production (independent of any crude oil production 
curtailment  mandated  by  the  Government  of  Alberta  then  in  effect),  unutilized  long-term  transportation 
commitments  and/or  low  utilization  levels  at  Cenovus’s  refineries.  Fluctuations  in  commodity  prices,  associated 
price  differentials  and  refining  margins  impact  our  financial  condition,  results  of  operations,  cash  flows,  growth, 
access to capital and cost of borrowing.  

The commodity price risks noted above, as well as other risks such as market access constraints and transportation 
restrictions,  reserves  replacement  and  reserves  estimates,  and  cost  management  that  are  more  fully  described 
herein,  and  may  have  a  material  impact  on our business,  financial  condition,  results  of  operations,  cash flows  or 
reputation, may be considered to be indicators of impairment. Another indication of impairment is the comparison 
of the carrying value of our assets to our market capitalization. 

As discussed in this MD&A, we conduct an assessment, at each reporting date, of the carrying value of our assets 
in accordance with IFRS. If crude oil, refined product and natural gas prices decline significantly and remain at low 
levels for an extended period of time, or if the costs of our development of such resources significantly increases, 
the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected. 

We  partially  mitigate  our  exposure  to  commodity  price  risk  through  the  integration  of  our  business,  financial 
instruments, physical contracts, market access commitments and generally through our access to committed credit 
facilities. In certain instances, Cenovus will use derivative instruments to manage exposure to price volatility on a 
portion of its refined product, oil and gas production, inventory or volumes in long-distance transit. For details of 
our financial instruments, including classification, assumptions made in the calculation of fair value and additional 
discussion  on  exposure  of  risks  and  the  management  of  those  risks,  see  Notes  35  and  36  of  the  Consolidated 
Financial Statements and “Hedging Activities” below. 

Additionally,  the  factors discussed  under  the  headings  "Pandemic Risk"  and "Excess  Crude  Oil Supply  Risk"  could 
continue to negatively impact commodity prices. If crude oil, refined product and natural gas prices remain at low 
levels for an extended period, or if the costs of development of our resources significantly increases, the carrying 
value of our assets may be subject to impairment and our net earnings could be adversely affected. 

Development and Operating Costs 

Our financial outlook and performance is significantly affected by the cost of developing, sustaining and operating 
our  assets.  Development  and  operating  costs  are  affected  by  a  number  of  factors  including,  but  not  limited  to: 
development,  adoption  and  success  of  new  technologies;  inflationary  price  pressure;  changes  in  regulatory 
compliance  costs;  scheduling  delays;  failure  to  maintain  quality  construction  and  manufacturing  standards;  and 
supply  chain  disruptions,  including  access  to  skilled  labour.  Electricity,  water,  diluent,  chemicals,  supplies, 
reclamation,  abandonment  and  labour  costs  are  examples  of  operating  costs  that  are  susceptible  to  significant 
fluctuation. 

Hedging Activities 

Cenovus’s  Market  Risk  Management  Policy,  which  has  been  approved  by  the  Board,  allows  Management  to  use 
derivative  instruments  including  exchange-traded  future  contracts,  commodity  put  and  call  options  and  other 
approved instruments as needed to help mitigate the impact of changes in crude oil and natural gas prices, crude 
oil differentials, diluent or condensate supply prices and differentials, refined product and crack spread margins, as 
well as fluctuations in foreign exchange rates and interest rates. Cenovus may also use firm commitments for the 
purchase or sale of crude oil, natural gas and refined products. Cenovus also uses derivative instruments in various 
operational markets to help optimize our supply costs or sales of our production.  

The use of such hedging activities exposes us to risks which may cause significant loss. These risks include, but are 
not  limited  to:  changes  in  the  valuation  of  the  hedge  instrument  being  not  well  correlated  to  the  change  in  the 
valuation of the underlying exposures being hedged; change in price of the underlying commodity; lack of market 
liquidity;  insufficient  counterparties  to  transact  with;  counterparty  default;  deficiency  in  systems  or  controls; 
human error; and the unenforceability of contracts. 

There  is  risk  that  the  consequences  of  hedging  to  protect  against  unfavourable  market  conditions  may  limit  the 
benefit to us of commodity price increases or changes in interest rates and foreign exchange rates. We may also 
suffer financial loss due to hedging arrangements if we are unable to produce oil, natural gas or refined products to 
fulfill our delivery obligations related to the underlying physical transaction. 

We  partially  mitigate  our  exposure  to  commodity  price  risk  through  the  integration  of  our  business,  financial 
instruments, physical contracts and market access commitments. For details of our financial instruments, including 
classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and 
the management of those risks, see Notes 3, 35 and 36 of the Consolidated Financial Statements. 

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Impact of Financial Risk Management Activities 

In 2020, for Cash Flow derivatives, we incurred a realized loss due to the settlement of benchmark prices relative 
to our risk management contract prices. For Optimization derivatives, the realized loss was from our decisions to 
store  rather  than  sell  our  physical  crude  oil  and  condensate  volumes  as  well  as  hedging  activity  related  to  the 
transportation  of  crude  and  condensate.  Cenovus  uses  its  marketing  and  transportation  initiatives,  including 
storage  and  pipeline  assets  to  optimize  product  mix,  delivery  points,  transportation  commitments  and  customer 
diversification, to inventory physical positions. At the time we make the decision to store crude oil and condensate 
volumes,  the  prices  available  for  future  periods  we  plan  to  sell  in  can  be  locked  in  and  the  improved  margin 
realized  in  the  future  periods,  which  are  superior  to  short-term  prices.  The  risk  management  gains  and  losses 
offset corresponding fluctuations in revenues generated from the underlying physical sales. 

Unrealized  losses  were  recorded  on  our  crude  oil  financial  instruments  in  the  twelve  months  ended 
December 31, 2020 primarily due to changes in commodity prices compared with prices at the end of the year and 
the realization of settled positions. 

Transactions  typically  span  across  periods  in  order  to  execute  the  optimization  strategy,  and  these  transactions 
reside across both realized and unrealized risk management. 

Sensitivities – Risk Management Positions 

The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in 
commodity  prices,  with  all  other variables  held constant. Management  believes  the  price fluctuations  identified  in 
the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices on our open 
risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax 
as follows: 

Crude Oil Commodity Price 
Crude Oil Differential Price 

± US$5.00 per bbl Applied to WTI and Condensate Hedges 
± US$2.50 per bbl Applied to Differential Hedges Tied to Production    

Sensitivity Range 

Increase     
(44 )     
(2 )     

Decrease   
44   
2   

For  further  information  on  our  risk  management  positions,  see  Notes  35  and  36  of  the  Consolidated  Financial 
Statements. 

Risks Associated with Derivative Financial Instruments 

Financial instruments expose us to the risk that a counterparty will default on its contractual obligations. This risk 
is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting 
arrangements, as outlined in our Board-approved Credit Policy. 

Financial  instruments  also  expose  us  to  the  risk  of  a  loss  from  adverse  changes  in  the  market  value  of  financial 
instruments  or  if  we  are  unable  to  fulfill  our  delivery  obligations  related  to  the  underlying  physical  transaction. 
Financial  instruments  may  limit  the  benefit  to  us  if  commodity prices,  interest or  foreign  exchange  rates  change. 
These risks are managed through hedging limits authorized according to our Market Risk Management Policy. 

Exposure to Counterparties 

In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders and other 
counterparties for the provision and sale of goods and services. If such counterparties do not fulfill their contractual 
obligations on a timely basis or at all, we may suffer financial losses, delays of our development plans or we may 
have to forego other opportunities which could materially impact our financial condition or operational results. 

Credit, Liquidity and Availability of Future Financing 

The future development of our business may be dependent on our ability to obtain additional capital including, but 
not  limited  to,  debt  and  equity  financing.  Among  other  things,  unpredictable  financial  markets,  a  sustained 
commodity  price  downturn,  a  change  in  market  fundamentals,  business  operations,  investor  or  lender  sentiment 
towards  our  business  and/or  the  industry  in  which  we  operate  or  credit  rating,  or  significant  unanticipated 
expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital, on 
terms  acceptable  to  Cenovus  or  at  all,  could  affect  our  ability  to  make  future  capital  expenditures,  to  maintain 
desirable ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization and to 
meet all of our financial obligations as they come due, potentially creating a material adverse effect on our financial 
condition, results of operations, ability to comply with various financial and operating covenants, credit ratings and 
reputation. 

Our  ability  to  service  our  debt  will  depend  upon,  among  other  things,  our  future  financial  and  operating 
performance, which will be affected by prevailing economic, business, market and other conditions, some of which 
are  beyond  our  control.  If  our  operating  and  financial  results  are  not  sufficient  to  service  current  or  future 
indebtedness, Cenovus may take actions such as reducing or suspending dividends, reducing or delaying business 
activities,  investments  or  capital  expenditures,  selling  assets,  restructuring  or  refinancing  our  debt,  or  seeking 
additional capital that could have less favourable terms.  

Our  liquidity  risk  is  mitigated  through  actively  managing  cash  and  cash  equivalents,  cash  flow  provided  by 
operating activities, available credit facilities, and accessing the capital markets. 

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We  are  required  to  comply  with  various  financial  and  operating  covenants  under  our  credit  facilities  and  the 
indentures  governing  our  debt  securities.  We  routinely  review  our  covenants  to  ensure  compliance.  In  the  event 
that  we  do  not  comply  with  such  covenants,  our  access  to  capital  could  be  restricted  or  repayment  could  be 
accelerated.

Credit Ratings 

Our company and our capital structure are regularly evaluated by credit rating agencies. Credit  ratings are based 
on  our  financial  and  operational  strength  and  a  number  of  factors  not  entirely  within  our  control,  including 
conditions affecting the oil and gas industry generally, industry risks associated with climate change and an energy 
transition and the state of the economy. There can be no assurance that one or more of our credit ratings will not 
be downgraded or withdrawn entirely by a rating agency.  

A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to 
sources  of  liquidity  and  capital.  A  failure  by  Cenovus  to  maintain  current  credit  ratings  could  affect  our  business 
relationships with counterparties, operating partners and suppliers.  

If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post collateral in 
the  form  of  cash,  letters  of  credit  or  other  financial  instruments  in  order  to  establish  or  maintain  business 
arrangements.  Additional  collateral  may  be  required  due  to  further  downgrades  below  certain  ratings  thresholds. 
Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having 
contractual business arrangements terminated. 

Foreign Exchange Rates 

Fluctuations  in  foreign  exchange  rates between  various currencies  may  affect  our  results.  Global  prices for  crude 
oil,  refined  products,  and  natural  gas  are  generally  set  in  U.S.  dollars,  while  many  of  our  operating  and  capital 
costs are in Canadian dollars. A change in the value of the Canadian dollar relative to the U.S. dollar will increase 
or  decrease  revenues,  as  expressed  in  Canadian  dollars,  received  from  the  sale  of  oil  and  refined  products,  and 
from some of our natural gas sales. In addition, a change in the value of the Canadian dollar against the U.S. dollar 
will  result  in  an  increase  or  decrease  in  our  U.S.  dollar  denominated  debt  and  related  interest  expense,  as 
expressed  in  Canadian  dollars.  We  may periodically enter into  transactions  to  manage our  exposure  to exchange 
rate  fluctuations.  However,  the  fluctuations  in  exchange  rates  are  beyond  our  control  and  could  have  a  material 
adverse effect on our cash flows, results of operations and financial condition. 

Interest Rates 

We may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings. 
An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded, 
both  of  which  could  negatively  impact  financial  results.  Additionally,  we  are  exposed  to  interest  rate  fluctuations 
upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates. 

We may periodically enter into transactions to manage our exposure to interest rate fluctuations. 

Dividend Payment and Repurchase of Securities 

The payment of dividends, continuation of Cenovus’s dividend reinvestment plan and any potential repurchase by 
Cenovus  of  its  securities  is  at  the  discretion  of  the  Board,  and  is  dependent  upon,  among  other  things,  financial 
performance,  debt  covenants,  satisfying  solvency  testing,  our  ability  to  meet  financial  obligations  as  they  come 
due, working capital requirements, future tax obligations, future capital requirements, commodity prices and other 
business and risk factors set forth in this MD&A. 

Disclosure Controls and Procedures and ICFR  

Based  on  their  inherent  limitations,  disclosure  controls  and  procedures  and  ICFR  may  not  prevent  or  detect 
misstatements,  and  even  those  controls  determined  to  be  effective  can  only  provide  reasonable  assurance  with 
respect  to  financial  statement  preparation  and  presentation.  Failure  to  adequately  prevent,  detect  and  correct 
misstatements could have a material adverse effect on our business, financial condition, results of operations, cash 
flows, and our reputation. 

Operational Risk 

Operational  risks  are  those risks  that  affect our  ability  to continue  operations  in  the  ordinary  course of business. 
Our operations are subject to risks generally affecting the energy industry. To partially mitigate our risks, we have 
a  system  of  standards,  practices  and  procedures  to  identify,  assess  and  mitigate  safety,  operational  and 
environmental  risk  across  our  operations.  In  addition,  we  attempt  to  partially  mitigate  operational  risks  by 
maintaining a comprehensive insurance program in respect of our assets and operations. However, there can be no 
assurance  as  to  the  amount,  if  any,  or  timing  of  recovery  under  our  insurance  policies  in  connection  with  losses 
associated with these events and risks. Although we maintain insurance for a number of risks and hazards, we may 
not be insured or fully insured against all losses or liabilities that could arise from our assets or operations. 

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Health and Safety 

The operation of our properties is subject to hazards of finding, recovering, transporting, refining, processing and 
marketing  hydrocarbons  including,  but  not  limited  to:  blowouts;  fires;  explosions;  railcar  incident  or  derailment; 
gaseous leaks; migration of harmful substances; loss of containment; releases or spills, including releases or spills 
from  shipping  vessels  at  terminals  or  hubs  and  as  a  result  of  pipeline  or  other  leaks;  corrosion;  epidemics  or 
pandemics; and catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, 
acts of vandalism and terrorism; and other accidents or hazards that may occur at or during transport to or from 
commercial or industrial sites. Any of these hazards can interrupt operations, impact our reputation, cause loss of 
life or personal injury, result in loss of or damage to equipment, property, information technology systems, related 
data  and  control  systems,  cause  environmental  damage  that  may  include  polluting  water,  land  or  air,  and  may 
result in fines, civil suits, or criminal charges against Cenovus, any of which may have a material adverse effect on 
our business, financial condition, results of operations, cash flows, and our reputation. 

Aviation Incidents 

Cenovus’s  Offshore  operations  in  Canada  and  China  rely  on  regular  travel  by  helicopter.  A  helicopter  incident 
resulting  in  loss  of  life,  facility  shutdown  or  regulatory  action  could  have  a  material  adverse  effect  on  our 
operations. This risk is managed through an aviation management process. Aviation Safety Reviews are conducted 
by  third  party  specialist  contractors  to  verify  that  helicopter  service  providers  meet  Cenovus’s  and  industry 
standards with respect to aviation safety. The reviews include evaluation of aircraft type, effectiveness of the safety 
and maintenance management systems and competency and training programs for critical roles in the operation of 
helicopters. Helicopters chartered to support Offshore operations must be fit for service and as such are fitted with 
multiple redundant systems to address a wide range of potential in-flight emergencies. Additional measures specific 
to  our  challenging  operating  environments  are  specified  in  our  design  requirements  including  anti-icing  and 
floatation  systems  effective  for  the  maximum  allowable  sea  height  operating  limits.  Pilots  are  trained  to  address 
potential emergency situations through regular real-time and simulator training aligned with industry best practice. 

Ice Management 

Although  extensive  measures  are  in  place  to  prevent  incidents  related  to  sea  ice  and  icebergs,  our  offshore 
operations are at risk of incidents caused by icebergs which may interrupt operations, impact our reputation, cause 
loss  of  life,  personal  injury,  or  damage  to  equipment  or  the  environment,  and  may  result  in  regulatory  action  or 
litigation  against  us.  We  have  several  policies  in  place  to  protect  people,  equipment  and  the  environment  in  the 
event of extreme weather conditions and adverse ice conditions. We have developed Adverse Weather Guidelines 
for  the  SeaRose  floating  production,  storage  and  offloading  vessel  and  continue  to  manage  physical  risk  through 
engineering for extreme weather events.  

Our  Atlantic  operations  have  a  robust  ice  management  program,  which  uses  a  range  of  resources  including  an 
industry  shared  ice  surveillance  aircraft,  as  well  as  synergistic  relationships  with  government  agencies  including 
Environment  and  Climate  Change  Canada,  the  Canadian  Coast  Guard  and  Canadian  Ice  Service.  In  addition, 
Atlantic  operators  employ  a  series  of  supply  and  support  vessels  to  actively  manage  ice  and  icebergs.  We  also 
maintain a series of relationships with contractors on a stand-by basis, allowing the quick mobilization of additional 
resources as required. We regularly assess all aspects of our ice management program in order to ensure that the 
program continues  to evolve as more information about the characteristics of ice and icebergs  becomes available 
and as new technologies are developed.  

Market Access Constraints and Transportation Restrictions 

Our production is transported through various pipelines, marine and rail networks and our refineries are reliant on 
various pipelines and rail networks to receive feedstock. Disruptions in, or restricted availability of, pipeline service 
and/or marine or rail transport, could adversely affect crude oil, refined products and natural gas sales, projected 
production growth, upstream or refining operations and cash flows. 

Interruptions or restrictions in the availability of these pipeline, marine and rail systems may also limit the ability to 
deliver production volumes and could adversely impact commodity prices, sales volumes and/or the prices received 
for our  products.  These  interruptions  and  restrictions  may be caused  by,  among  other  things,  the  inability  of  the 
pipeline, marine or rail networks  to operate, or may be related to capacity constraints as the supply of feedstock 
into  the  system  exceeds  the  infrastructure  capacity.  There  can  be  no  certainty  that  investments  in  new  pipeline 
projects, which would result in an increase in long-term takeaway capacity, will be made by applicable third party 
pipeline  providers  that  any  applications  to  expand  capacity  will  receive  the  required  regulatory  approval,  or  that 
any  such  approvals  will  result  in  the  construction  of  the  pipeline  project  or  that  such  projects  would  provide 
sufficient  transportation  capacity  and  access  to  refining  capacity.  There  is  also  no  certainty  that  short-term 
operational constraints on the pipeline system, arising from pipeline interruption and/or increased supply of crude 
oil, will not occur. 

There  is  no  certainty  that  crude-by-rail,  marine  transport  and  other  alternative  types  of  transportation  for  our 
production  will  be  sufficient  to  address  any  gaps  caused  by  operational  constraints  on  the  pipeline  system.  In 
addition,  our  crude-by-rail  and  marine  shipments  may  be  impacted  by  service  delays,  inclement  weather,  railcar 
availability, railcar derailment or other rail or marine transport incidents and could adversely impact crude oil sales 
volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal 

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injury,  loss  of  equipment  or  property,  or  environmental  damage.  In  addition,  rail  and  marine  regulations  are 
constantly being reviewed to ensure the safe operation of the supply chain. Should regulations change, the costs of 
complying with those regulations will likely be passed on to rail and/or marine shippers and may adversely affect 
our ability to transport crude-by-rail and/or marine transport or the economics associated with rail transportation. 
Finally,  planned  or  unplanned  shutdowns  or  closures  of  our  refineries  or  of  our  refinery  customers  may  limit  our 
ability to deliver product with negative implications on sales and cash from operating activities. 

Operational Considerations 

Our  operations  are subject  to  all of  the risks  normally  incidental  to:  (i)  the  storing,  transporting,  processing,  and 
marketing  of  crude  oil,  refined  products,  natural  gas  and  other  related  products;  (ii)  drilling  and  completion  of 
crude oil and natural gas wells; (iii) the operation and development of crude oil and natural gas properties; and (iv) 
the  operation  of  refineries,  terminals,  pipelines  and  other  transportation  and  distribution  facilities.  These  risks 
include  but  are  not  limited  to:  encountering  unexpected formations  or pressures;  premature declines  of  reservoir 
pressure  or  productivity;  fires;  explosions;  blowouts;  loss  of  containment;  gaseous  leaks;  power  outages; 
migration of harmful substances into water systems; oil spills; uncontrollable flows of crude oil, natural gas or well 
fluids; failure to follow operating procedures or operate within established operating parameters; adverse weather 
conditions;  pollution;  freeze-ups  and  other  similar  events;  the  breakdown  or  failure  of  equipment,  pipelines  and 
facilities,  information  systems  and  processes;  the  performance  of  equipment  at  levels  below  those  originally 
intended  (whether  due  to  misuse,  unexpected  degradation  or  design,  construction  or  manufacturing  defects); 
releases or spills from offshore operations, shipping vessels or other marine transport incidents; railcar incidents or 
derailments;  failure  to  maintain  adequate supplies of spare  parts;  the compromise of  information  technology  and 
control  systems  and  related  data;  operator  error;  labour  disputes;  disputes  with  interconnected  facilities  and 
carriers; operational disruptions or apportionment on third-party systems or refineries, which may prevent the full 
utilization  of  the  Company’s  facilities  and  pipelines;  spills  at  truck  terminals  and  hubs;  spills  associated  with  the 
loading  and  unloading  of  potentially  harmful  substances  onto  trucks; loss  of  product;  unavailability  of  feedstock; 
price and quality of feedstock; epidemics or pandemics; and catastrophic events, including, but not limited to, war, 
extreme weather events, natural disasters, acts of sabotage and other similar events. 

Producing and refining oil, bitumen and diluted bitumen requires high levels of investment and involves particular 
risks and uncertainties. Our oil sands operations are susceptible to reduced production, slowdowns, shutdowns, or 
restrictions on our ability to produce higher value products due to the interdependence of our component systems. 
Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and 
the  costs  associated with  refining  oil  can  entail  significant capital  outlays.  The operating  costs  associated  with  oil 
production  are  largely  fixed  in  the short-term  and,  as  a  result,  operating  costs  per  unit  are  largely dependent on 
levels of production. 

We  do  not  insure  against  all  potential  occurrences  and  disruptions  in  respect  of  our  assets  or  operations,  and  it 
cannot be guaranteed that our insurance coverage will be available or sufficient to fully cover any claims that may 
arise from such occurrences or disruptions. Our operations could also be interrupted by natural disasters or other 
events  beyond  our  control.  The  occurrence  of  an  event  that  is  not  fully  covered  by  our  insurance  program  could 
have a material adverse effect on our business, financial condition, results of operation and cash flows. 

Reserves Replacement and Reserve Estimates 

If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will 
decline materially from their current levels. Our financial condition, results of operations and cash flows are highly 
dependent  upon  successfully  producing  from  current  reserves  and  acquiring,  discovering  or  developing  additional 
reserves. 

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our 
control.  In  general,  estimates  of  economically  recoverable  crude  oil  and  natural  gas  reserves  and  the  future  net 
cash  flows  and  revenue  derived  therefrom  are  based  on  a number of  variable  factors  and  assumptions  including, 
but not limited to: product prices; future operating and capital costs; historical production from the properties and 
the  assumed  effects  of  regulation  by  governmental  agencies,  including  royalty  payments  and  taxes,  and 
environmental and emissions related regulations and taxes; initial production rates; production decline rates; and 
the  availability,  proximity  and  capacity  of  oil  and  gas  gathering  systems,  pipelines,  rail  transportation  and 
processing facilities, all of which may cause actual results to vary materially from estimated results. 

All  such  estimates  are  to  some degree  uncertain  and classifications of reserves  are  only  attempting  to define  the 
degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural 
gas  reserves  attributable  to  any  particular  group  of  properties,  classification  of  such  reserves  based  on  risk  of 
recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same 
engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and 
operating expenditures with respect to our reserves may vary from current estimates and such variances may be 
material. 

Estimates  with  respect  to  reserves  that  may  be  developed  and  produced  in  the  future  are  often  based  on 
volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. 

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Subsequent  evaluation  of  the  same  reserves  based  on  production  history  will  result  in  variations,  which  may  be 
material, in the estimated reserves. 

The  production  rate  of  oil  and  gas  properties  tends  to  decline  as  reserves  are  depleted  while  the  associated 
operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil 
and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce 
oil  and  natural  gas;  drilling  success;  completing  long-lead  time  capital  intensive  projects  on  budget  and  on 
schedule;  and  the  application  of  successful  exploitation  techniques  on  mature  properties.  Our  business,  financial 
condition, results of operations and cash flows are highly dependent upon successfully producing current reserves 
and adding additional reserves. 

Cost Management 

Our  operating  costs  could  escalate  and  become  uncompetitive  due  to  inflationary  cost  pressures,  equipment 
limitations,  escalating  supply  costs,  commodity  prices,  higher  steam-to-oil  ratios  in  our  oil  sands  operations,  and 
additional government or environmental regulations. Our inability to manage costs may impact project returns and 
future  development  decisions,  which  could  have  a  material  adverse  effect  on  our  financial  condition,  results  of 
operations and cash flows. 

The  cost  or  availability  of  oil  and  gas  field  equipment  may  adversely  affect  our  ability  to  undertake  exploration, 
development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of 
supply  of  equipment  and  services  including  drilling  rigs,  geological  and  geophysical  services,  engineering  and 
construction services and construction materials. These materials and services may not be available when required 
at  reasonable  prices.  Without  compromising  safety,  overall  quality  and  environmental  impacts,  we  continually 
develop  our  approved  suppliers  base  to  provide  undisrupted  access  to  materials,  equipment  and  services,  while 
maintaining  a  competitive  cost  baseline  via  cost  escalation  mitigation  strategies.  A  failure  to  secure  equipment 
necessary to our operations for the expected price, on the expected timeline, or at all, may have an adverse effect 
on our financial condition, results of operations, and cash flows. 

Competition 

The Canadian and international energy industry is highly competitive in all aspects, including accessing capital, the 
exploration  for,  and  the  development  of,  new  and  existing  sources  of  supply,  the  acquisition  of  crude  oil  and 
natural gas interests and the refining, distribution and marketing of  oil and gas products. We compete with other 
producers  and  refiners,  some  of  which  may  have  lower  operating  costs  or  greater  resources  than  our  company 
does. Competing producers may develop and implement recovery techniques and technologies which are superior 
to  those  we  employ.  The  oil  and  gas  industry  also  competes  with  other  industries  in  supplying  energy,  fuel  and 
related  products  to  consumers,  including  renewable  energy  sources  which  may  become  more  prevalent  in  the 
future. 

Project Execution 

Cenovus manages a variety of oil, natural gas and refining projects across its global portfolio, including the current 
rebuild  of  our  Superior  Refinery.  The  wide  range  of  risks  associated  with  project  development  and  execution,  as 
well as the commissioning and integration of new facilities with existing assets, can impact the economic viability of 
the  Company’s  projects.  These  risks  include,  but  are  not  limited  to:  our  ability  to  obtain  the  necessary 
environmental and regulatory approvals; our ability to obtain favourable terms or to be granted access within land-
use  agreements;  risks  relating  to  schedule,  resources  and  costs,  including  the  availability  and  cost  of  materials, 
equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of 
weather  conditions;  risk  related  to  the  accuracy  of  project  cost  estimates;  our  ability  to  finance  capital  and 
expenses; our ability to source or complete strategic transactions; the effect of COVID-19 on project execution and 
timelines; and the effect of changing government regulation and public expectations in relation to the impacts of oil 
and  gas  operations  on  the  environment.  The  commissioning  and  integration  of  new  facilities  within  our  existing 
asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could 
have a material adverse effect on our financial condition, results of operations and cash flows and may affect our 
safety and environmental record thereby negatively affecting our reputation and social license to operate. 

Partner Risks 

Some of our assets are not operated or controlled by us or are held in partnership with others, including through 
joint  ventures.  Therefore,  our  results  of  operations  and  cash  flows  may  be  affected  by  the  actions  of  third-party 
operators or partners and our ability to control and manage risks may be reduced. We rely on the judgment and 
operating  expertise  of  our  partners  in  respect  of  the  operation  of  such  assets  and  to  provide  information  on  the 
status of such assets and related results of operations; however, we are, at times, dependent upon our partners for 
the successful execution of various projects. 

Our  partners  may  have  objectives  and  interests  that  do  not  align  with  or  may  conflict  with  our  interests.  No 
assurance  can  be  provided  that  the  future  demands  or  expectations  of  Cenovus  relating  to  such  assets  will  be 
satisfactorily  met  in  a  timely  manner  or  at  all.  If  a  dispute  with  a  partner  or  partners  were  to  occur  over  the 
development and operation of a project or if  a partner or partners were unable to fund their contractual share of 

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the capital expenditures, a project could be delayed and Cenovus could be partially or totally liable for its partner’s 
share of the project. 

SAGD Technology 

Current  technologies  used  for  the  recovery  of  bitumen  can  be  energy  intensive,  including  SAGD  which  requires 
significant  consumption  of  natural  gas  in  the  production  of  steam  used  in  the  recovery  process.  The  amount  of 
steam required in the production process varies and therefore impacts costs. The performance of the reservoir can 
also  affect  the  timing  and  levels  of  production  using  SAGD  technology.  A  large  increase  in  recovery  costs  could 
cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect 
on  our  business,  financial  condition,  results  of  operations  and  cash  flows.  There  are  risks  associated  with  growth 
and  other  capital  projects  that  rely  largely  or  partly  on  new  technologies,  the  incorporation  of  such  technologies 
into  new  or  existing  operations  and  acceptance  of  new  technologies  in  the  market.  The  success  of  projects 
incorporating new technologies cannot be assured. 

Information Systems 

We rely heavily on information technology, such as computer hardware and software systems, to properly operate 
our business. In the event we are unable to regularly deploy software and hardware, effectively upgrade systems 
and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the 
operation of such systems could be interrupted or result in the loss, corruption, or release of data.  

In  the  ordinary  course  of  business,  we  collect,  use  and  store  sensitive  data,  including  intellectual  property, 
proprietary business information and personal information of our employees and third parties. Despite our security 
measures, our information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or 
cyberterrorists  or  breaches  due  to  employee  error,  malfeasance  or  other  disruptions,  including  natural  disasters 
and  acts  of war.  Any  such  breach  could compromise  information  used or  stored on our  systems  and/or  networks 
and  result  in  the  loss,  theft  or  exposure  of  confidential  information  related  to  retail  credit  card  information, 
personnel files, exploration activities, corporate actions, executive officer communications and financial results. Any 
such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws 
that protect the privacy of personal information, regulatory penalties, operational disruption, site shut-down, leaks 
or other negative consequences, including damage to our reputation, which could have a material adverse effect on 
our business, financial condition, results of operations and cash flows. 

There  is  also  a  risk  of  cyber-related  fraud  whereby  perpetrators  attempt  to  take  control  of  electronic 
communications  or  attempt  to  impersonate  internal  personnel  or  business  partners  to  divert  payments  and 
financial  assets  to  accounts  controlled  by  the  perpetrators.  If  a  perpetrator  is  successful  in  bypassing  Cenovus’s 
cyber-security  measures  and  business  process  controls,  such  cyber-related  fraud  could  result  in  financial  losses, 
remediation and recovery costs, and an adverse reputational impact. 

Security and Terrorist Threats 

Security  threats  and  terrorist  or  activist  activities  may  impact  our  personnel,  which  could  result  in  injury,  death, 
extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack 
or activist incident targeted at a facility, terminal, pipeline, rail network, office or offshore vessel/installation owned 
or operated by Cenovus or any of our partners could result in the interruption or cessation of key elements of our 
operations. Outcomes of such incidents could have a material adverse effect on our results of operations, financial 
condition and business strategy. The risk to employees and board members due to ongoing social unrest in Hong 
Kong  is  being  managed  through  reduced  travel  and  increased  awareness  and  monitoring  of  the  situation.  The 
potential  for  detention  and/or  incarceration  of  our  employees/contractors  entering  or  working  in  China  remains, 
and as a result, review and reconsideration for travel into China has become a business/corporate process. 

Leadership and Talent 

Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our 
talent.  If  we  are  unable  to  retain  key  personnel  and  critical  talent  or  to  attract  and  retain  new  talent  with  the 
necessary  leadership,  professional  and  technical  competencies,  it  could  have  a  material  adverse  effect  on  our 
financial condition, results of operations and pace of growth. 

Litigation 

From time to time, we may be the subject of demands, disputes and litigation arising out of our operations. Claims 
under  such  litigation  may  be  material  or  may  be  indeterminate.  Various  types  of  claims  may  be  made  including, 
without  limitation,  failure  to  comply  with  applicable  laws  and  regulations,  environmental  damages,  breach  of 
contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, 
derivative  actions,  patent  infringement  and employment-related  matters.  We  may be  required  to  incur significant 
expenses  or  devote  significant  resources  in  defense  against  any  such  litigation,  which  could  result  in  an 
unfavourable decision, including fines, sanctions, monetary damages, temporary suspensions of operations, or the 
inability  to engage  in  certain operations  or  transactions.  The  outcome of  such  claims  can  be difficult  to  assess  or 
quantify and may have a material adverse effect on our reputation, financial condition and results of operations. In 

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addition,  we  may  be  subject  to  or  impacted  by  climate  change  related  litigation.  See  “Climate  Change  Related 
Litigation” for discussion. 

Indigenous Land and Rights Claims  

Opposition  by  Indigenous  groups  to  conduct  our  operations,  development  or  exploratory  activities  in  any  of  the 
jurisdictions  in  which  we  conduct  business  may  negatively  impact  us  in  terms  of  public  perception,  diversion  of 
Management’s  time  and  resources,  legal  and  other  advisory  expenses,  and  could  adversely  impact  our  progress 
and ability to explore and develop properties. 

Some  Indigenous  groups  have  established  or  asserted  Indigenous  treaty,  title  and  rights  to  portions  of  Canada. 
There  are  outstanding  Indigenous  and  treaty  rights  claims,  which  may  include  Indigenous  title  claims,  on  lands 
where we operate, and such claims, if successful, could have a material adverse impact on our operations or pace 
of  growth.  No  certainty  exists  that  any  lands  currently  unaffected  by  claims  brought  by  Indigenous  groups  will 
remain unaffected by future claims. 

The  Canadian  federal  and  provincial  governments  have  a  duty  to  consult  with  Indigenous  people  when 
contemplating actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain 
circumstances,  accommodate  their  concerns.  The  scope  of  the  duty  to  consult  by  federal  and  provincial 
governments varies with the circumstances and is often the subject of ongoing litigation. The fulfillment of the duty 
to consult Indigenous people and any associated accommodations may adversely affect our ability to, or increase 
the timeline to, obtain or renew, permits, leases, licences and other approvals, or to meet the terms and conditions 
of those approvals. In addition, the federal government has introduced legislation to implement the United Nations 
Declaration on the Rights of Indigenous Peoples (“UNDRIP”). Other Canadian jurisdictions have also introduced or 
passed  similar  legislation,  or  begun  considering  the  principles  and  objectives  of  UNDRIP,  or  may  do  so  in  the 
future. The means and timelines associated with UNDRIP’s implementation by government is uncertain; additional 
processes  may  be  created  or  legislation  amended  or  introduced  associated  with  project  development  and 
operations, further increasing uncertainty with respect to project regulatory approval timelines and requirements. 

Regulatory Risk 

The oil and gas industry and refining industry in general and our operations in particular are subject to regulation 
and  intervention  under  federal,  provincial,  territorial,  state  and  municipal  legislation  in  the  countries  in  which  we 
conduct  operations,  development  or  exploratory  activities  in  matters  such  as,  but  not  limited  to:  land  tenure; 
permitting  of  production  projects;  royalties;  taxes  (including  income  taxes);  government  fees;  production  rates; 
environmental  protection  controls;  protection  of  certain  species  or  lands;  provincial  and  federal  land  use 
designations; the reduction of greenhouse gases (“GHGs”) and other emissions; the export of crude oil, natural gas 
and  other  products;  the  transportation  of  crude-by-rail  or  marine  transport;  the  awarding  or  acquisition  of 
exploration and production, oil sands or other interests; the imposition of specific drilling obligations; control over 
the  development,  abandonment  and  reclamation  of  fields  (including  restrictions  on  production)  and/or  facilities; 
and  possibly  expropriation  or  cancellation  of  contract  rights.  The  implementation  of  new  regulations  or  the 
modification of existing regulations could impact our existing and planned projects or increase capital investment, 
operating expenses or compliance costs, which could adversely impact our financial condition, results of operations 
and cash flows. 

Regulatory Approvals 

Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that 
we  will  be  able  to  obtain  all  necessary  licences,  permits  and  other  approvals  that  may  be  required  to  carry  out 
certain exploration, development and operating activities on our properties. In addition, obtaining certain approvals 
from  regulatory  authorities  can  involve,  among  other  things,  stakeholder  and  Indigenous  consultation, 
environmental  impact  assessments  and  public  hearings.  Regulatory  approvals  obtained  may  be  subject  to  the 
satisfaction  of  certain  conditions  including,  but  not  limited  to:  security  deposit  obligations;  ongoing  regulatory 
oversight  of  projects;  mitigating  or  avoiding  project  impacts;  environmental  and  habitat  assessments;  and  other 
commitments  or  obligations.  Failure  to  obtain  applicable  regulatory  approvals  or  satisfy  any  of  the  conditions 
thereto on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and 
increased costs. 

Abandonment and Reclamation Cost Risk  

Cenovus  is  subject  to  oil  and  gas  asset  abandonment,  reclamation  and  remediation  (“A&R”)  liabilities  for  our 
operations, development and exploratory activities, including those imposed by regulation under federal, provincial, 
territorial,  state  and  municipal  legislation  in  the  countries  in  which  we  conduct  operations,  development  or 
exploratory activities. 

In  Alberta,  the  A&R  liability  regime  includes  the  Orphan  Well  Fund,  which  is  administered  by  the  Orphan  Well 
Association  (the  “OWA”).  The  OWA  administers  orphaned  assets  and  is  funded  through  a  levy  imposed  on 
licensees, including Cenovus, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, 
wells  and  unreclaimed  sites  in  Alberta.  The  aggregate  value  of  the  A&R  liabilities  assumed  by  the  OWA  has 
increased  in  recent  years  and  will  remain  at  elevated  levels  until  a  significant  number  of  orphaned  wells  are 
decommissioned by the OWA. In June of 2020, the OWA's powers were expanded to more effectively manage and 

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accelerate the clean-up of orphaned wells and associated infrastructure. For instance, in certain circumstances the 
OWA  would  be  allowed  to  act  as  an  operator  and  take  over  production  of  abandoned  wells.  While  the  Alberta 
Energy  Regulator’s  (“AER’s”)  Site  Rehabilitation  Program  is  funding  up  to  $1  billion  of  eligible  abandonment  and 
reclamation projects through December 31, 2022, it is uncertain how this program, or the recent expansion of the 
OWA’s capabilities, will impact future orphan well liabilities being placed on the OWA. The OWA may seek additional 
funding for such liabilities from industry participants, including Cenovus. 

The  AER  has  broad  discretion  relating  to  liability  management  ratings,  licence  eligibility  and  licence  transfers.
Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within their asset 
bases,  may  be  negatively  affected  by  increased  financial  requirements,  including  potential  counterparties  to 
Cenovus.  This  may  result  in  future  insolvencies  and  additional  orphaned  assets.  In  addition,  this  may  impact 
Cenovus’s  ability  to  transfer  our  licences,  approvals  or  permits,  and  may  result  in  increased  costs  and  delays  or 
require changes to or abandonment of projects and transactions. 

Cenovus  has  an  ongoing  environmental  monitoring  program  at  owned  and  leased  retail  locations  and  performs 
remediation where  required. The  costs of  such remediation  depend  on  a  number of  uncertain factors  such  as  the 
extent and type of remediation required. Due to uncertainties inherent in the estimation process, it is possible that 
existing  estimates  may  need  to  be  revised  and  that  conditions  may  exist  at  various  retail  locations  that  require 
future  expenditures.  Such  future  costs  may  not  be  determinable  due  to  the  unknown  timing  and  extent  of 
corrective actions that may be required. 

For  Offshore,  the  present  value  cost for  decommissioning and  abandonment  of  the  offshore wells  and facilities  is 
estimated  based  on  known  regulations,  procedures  and  costs  today  for  undertaking  the  decommissioning,  the 
majority  of  which  is  projected  to  be  incurred  in  the  2030s.  It  is  possible  that  these  costs  may  change  materially 
before  decommissioning  due  to  regulatory  changes,  technological  changes,  acceleration  of  decommissioning 
timelines, and inflation among other variables. 

While the impact on Cenovus of any legislative, regulatory or policy decisions relating to the A&R liability regulatory 
regime in the jurisdictions in which we conduct operations, development or exploratory activities cannot be reliably 
or  accurately  estimated,  any  cost  recovery  or  other  measures  taken  by  applicable  regulatory  bodies  may  impact 
Cenovus  and  materially  and  adversely  affect,  among  other  things,  our  business,  financial  condition,  results  of 
operations and cash flows. 

Royalty Regimes 

Our cash flows may be directly affected by changes to royalty regimes. The governments of the jurisdictions where 
we have producing assets receive royalties on the production of hydrocarbons from lands in which they respectively 
own  the  mineral  rights  and  which  Cenovus  produces  under  agreement  with  each  respective  government. 
Government  regulation  of  royalties  is  subject  to  change  for  a  number  of  reasons,  including,  among  other  things, 
political  factors.  In  Canada,  there  are  certain  provincial  mineral  taxes  payable  on  hydrocarbon  production  from 
lands  other  than Crown  lands.  The potential  for  changes  in  the royalty  and  mineral  tax regimes  applicable  in  the 
jurisdictions in which Cenovus operates, or changes to how existing royalty regimes are interpreted and applied by 
the applicable governments, creates uncertainty relating to the ability to accurately estimate future royalty rates or 
mineral  taxes  and  could  have  a  significant  impact  on  our  business,  financial  condition,  results  of  operations  and 
cash flows. An increase in the royalty rates or mineral taxes in jurisdictions where we have producing assets would 
reduce  our  earnings  and  could  make,  in  the  respective  jurisdiction,  future  capital  expenditures  or  existing 
operations  uneconomic. A  material  increase  in royalties  or mineral  taxes  may reduce  the  value  of our  associated 
assets. 

Canada-United States-Mexico Agreement (“CUSMA”) 

On  July 1, 2020,  the  new  CUSMA  entered  into  force,  replacing  the  North  American  Free  Trade  Agreement 
(“NAFTA”). According to a Government of Canada technical summary of negotiated outcomes related to the energy 
sector, under CUSMA, the rule of origin applicable to heavy oil containing diluent has been relaxed to allow up to 
40 percent of non-originating diluent  that is added for the purpose of transportation  in pipelines without affecting 
the  originating  status  of  the  product,  which  will  allow  Canadian  products  to  more  easily  qualify  for  duty-free 
treatment when imported into the U.S. The related CUSMA side letter on energy between Canada and the U.S. also 
promotes regulatory transparency and non-discrimination in access to or  use of energy infrastructure, which may 
potentially benefit the Canadian heavy oil industry. While it is not yet known how certifications can be successfully 
substantiated, this is an improvement to the NAFTA origin rule. 

The  investor-state  dispute  settlement  provisions  will  no  longer  be  available  to  protect  future  investments  of 
Canadians  in  the  U.S.  or  U.S.  investments  in  Canada.  For  three  years  after  the  termination  of  NAFTA,  existing 
"legacy investments" will maintain their access to the investor-state dispute settlement under NAFTA Chapter 11. 

Labour Risk 

Cenovus  depends  on  unionized  labour  for  the  operation  of  certain  facilities  and  may  be  subject  to  adverse 
employee  relations  and  labour  disputes,  which  may  disrupt  operations  at  such  facilities.  As  of  February  1,  2021, 
approximately  6.1 percent  of  our  employees  were  represented  by  unions  under  existing  collective  bargaining 
agreements  with  Cenovus's  newly  acquired  operating  subsidiaries.  We  cannot  assure  that  strikes  or  work 

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stoppages  will  not  occur.  Any  prolonged  work  stoppages  may  have  a  material  adverse  effect  on  our  business, 
reputation, financial condition, results of operations and cash flows. 

In  addition,  we  may  not  be  able  to  renew  or  renegotiate  our  subsidiaries'  collective  bargaining  agreements  on 
satisfactory  terms  or  at  all  and  a  failure  to  do  so  may  increase  our  costs.  Moreover,  employees  who  are  not 
currently represented by unions may seek union representation in the future and efforts may be made from time to 
time to unionize other portions of our workforce. Any renegotiation of our existing collective bargaining agreements 
may result  in  terms  that  are less  favourable  to Cenovus, which  may  materially  and  adversely  affect our  financial 
condition, results of operations and cash flows. 

Future unionization efforts or changes in legislation and regulations may result in labour shortages, higher labour 
costs,  as  well  as  wage,  benefit,  and  other  employment  consequences,  especially  during  critical  maintenance  and 
construction periods, all of which may increase our costs, reduce our revenues or limit our operational flexibility.  

International Developments and Geopolitical Risk 

Cenovus's business includes Asia Pacific Assets in the South China Sea and the Madura Strait offshore Indonesia, 
and  includes  cooperation  agreements  with  China  National  Offshore  Oil  Corporation  or  its  subsidiaries  (collectively 
“CNOOC”), which also operates certain of these assets.  

As  a  result,  Cenovus  is  exposed  to  the  financial  and  operational  risks  associated  with  uncertain  international 
relations.  Political  developments  impacting  international  trade,  including  trade  disputes  and  increased  tariffs, 
particularly between the U.S. and China and Canada and China, may negatively impact markets and cause weaker 
macroeconomic conditions or drive political or national sentiment, weakening demand for crude oil, natural gas and 
refined products. For example, U.S. government trade policy has resulted in, and could result in more, U.S. trading 
partners adopting responsive trade policy and may make it more difficult or costly for Cenovus to operate in and 
export our products to those countries.  

Moreover, our operations may be materially adversely affected by political, economic or social instability or events, 
including  the  renegotiation  or  nullification  of  agreements  and  treaties,  the  imposition  of  onerous  regulations, 
embargoes,  sanctions,  and  fiscal  policy,  changes  in  laws  governing  existing  operations,  financial  constraints, 
including  currency  restrictions  and  exchange  rate  fluctuations,  unreasonable  taxation  and  the  behaviour  of 
international  public  officials,  joint  venture  partners  or  third-party  representatives.  Specifically,  our  Asia  Pacific 
assets expose Cenovus to the effects of the changing U.S.-China and Canada-China relations, including escalating 
tensions and possible retaliations. It is possible that additional actions taken by the U.S. and Canada may limit or 
restrict foreign companies' ability to participate in projects and operate in certain sectors of the Chinese economy, 
including the energy sector. 

On  November 12, 2020,  the  former  President  of  the  United  States  signed  an  executive  order  prohibiting  U.S. 
persons from engaging in transactions in the publicly traded securities of specified companies with alleged ties to 
the Chinese military. The prohibition is intended to be effective from January 11, 2021 to November 21, 2021. On 
December 3, 2020, CNOOC was added to the list of companies with alleged ties to the Chinese military. Although 
the  executive  order  does  not  limit  Cenovus's  offshore  operations  in  Asia,  further  U.S.  sanctions  against  CNOOC 
may affect such operations, depending on the nature of such sanctions.  

A new U.S. presidential administration took office in January 2021 and may implement domestic and foreign policy 
that could have a significant impact on Cenovus's financial condition or results of operations. We cannot accurately 
predict  the  implementation  of  U.S.  or  Canadian  policy  affecting  any  current  or  future  activities  by  CNOOC, 
Cenovus's  other  international  partners  or  Cenovus.  Similarly,  we  cannot  accurately  predict  whether  U.S. 
restrictions will be further tightened or the impact of government action on Cenovus's offshore operations in Asia. 
It is possible that the U.S. or Canadian government may subject CNOOC or Cenovus's other international partners 
to restrictions or sanctions, which may adversely impact our offshore operations in Asia. 

Moreover, it is possible that our partnership with CNOOC may deter certain investors from investing in Cenovus, or 
encourage certain investors to divest their existing holdings in Cenovus, which could have a negative impact on our 
share price and our ability to raise capital.  It is also possible that as a result of our partnership with CNOOC, we 
may be subject to negative media attention which may affect investors' perception of Cenovus in Canada, the U.S. 
and globally, and which may negatively affect our share price. 

In addition, Cenovus may be affected by changes to bilateral relationships, the frameworks and global norms that 
govern international trade, and other geopolitical developments. This includes acute shocks (such as civil unrest or 
sanctions) and chronic stresses (such as political or business disputes and other forms of conflict, including military 
conflict) that may pose longer-term threats to our business. Unilateral action by, or changes in relations between, 
countries in which we operate, including the U.S. and China, and such countries’ approach to multilateralism and 
trade  protectionism  can  impact  our  ability  to  access  markets,  technology,  talent  and  capital.  Disruptions  or 
unanticipated changes of this nature may affect our ability to sell our products for optimum value or access inputs 
required for effective operations and has the potential to adversely affect our financial performance. 

Geopolitical  events,  such  as  a  shift  in  the  relationship,  an  escalation  or  imposition  of  sanctions,  tariffs  or  other 
trade  tensions  between  the  U.S.  and  China  and  Canada  and  China,  may  affect  the  supply,  demand  and  price  of 
crude oil, natural gas and refined products and therefore our financial performance. The timing, extent and fallout 

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of the ongoing tensions between the U.S. and China and Canada and China remains uncertain and the impact on 
our business is unknown. 

Shifts in global power relations may also introduce greater uncertainty with respect to issues requiring global co-
ordination  (such  as  climate  change,  trade  agreements,  tax  regulation,  freedom  of  navigation  and  technology 
regulation), as well as raise questions on the efficacy of and trust in international institutions, including those that 
underpin international trade. These types of changes may cause restrictions or impose costs on our business, and 
may inhibit our future opportunities or affect our financial condition. 

Cenovus's financial performance, operations and business may be adversely affected by any of the foregoing risks 
associated  with  international  relations  and  specifically  those  risks  arising  from  evolving  U.S.-China  and  Canada-
China relations. The nature, extent and magnitude of the effect of dynamic trade relations on Cenovus cannot be 
accurately  predicted  and  may  have  a  material  adverse  impact  on  our  business,  prospects,  financial  condition, 
results of operations, cash flows, and reputation. 

Climate-Related Risks 

There is growing international concern regarding climate change and there has been a significant increase in focus 
on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance 
companies, environmental and governance organizations, institutional investors, social and environmental activists, 
and  individuals,  are  increasingly  seeking  to  implement,  among  other  things,  regulatory  and  policy  changes, 
changes in investment patterns, and modifications in energy consumption habits and trends which, individually and 
collectively  are  intended  to  or  have  the  effect  of  accelerating  the  reduction  in  the  global  consumption  of  carbon-
based energy, the conversion of energy usage to less carbon-intensive forms and the general migration of energy 
usage away from carbon-based forms of energy. 

Climate  change  and  its  associated  impacts  may  increase  our  exposure  to,  and  magnitude  of,  each  of  the  risks 
identified in the Risk Management and Risk Factors section of this MD&A. Overall, Cenovus is not able to estimate 
at  this  time  the  degree  to  which  climate  change  related  regulatory,  climatic  conditions,  and  climate-related 
transition  risks  could  impact  the  Company’s  financial  and  operating  results.  Our  business,  financial  condition, 
results  of  operations,  cash  flows,  reputation,  access  to  capital,  access  to  insurance,  cost  of  borrowing,  access  to 
liquidity,  ability  to  fund  dividend  payments  and/or  business  plans  may,  in  particular,  without  limitation,  be 
adversely impacted as a result of climate change and its associated impacts. 

Transition Risks – Policy & Legal 

Climate Change Regulation 

Cenovus operates in several jurisdictions that regulate or have proposed to regulate air pollutants, including GHG 
emissions. Some of these regulations are in effect while others remain in  various phases of review, discussion or 
implementation.  Uncertainties  exist  relating  to  the  timing  and  effects  of  these  emerging  regulations,  other 
contemplated  legislation,  including  how  they  may  be  harmonized,  making  it  difficult  to  accurately  determine  the 
cost impacts and effects on our suppliers. Additional changes to climate change legislation may adversely affect our 
business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated 
at  this  time.  In  December 2020,  the  Government  of  Canada  proposed  increasing  the  carbon  tax  to  $170/tonne 
carbon  dioxide  equivalent  (“CO2e”)  by  2030.  To  reach  that  level,  the  price  imposed  on  carbon  will  rise  from  the 
2022  rate  of  $50/tonne  CO2e  by  $15/tonne  CO2e  each  year  until  2030.  If  made  into  law,  this  may  have  a 
significant  impact  on  Cenovus.  Notably,  several  Canadian  provinces  have  launched  constitutional  challenges  to 
Canada's  national  carbon-pricing  regime  that  were  heard  by  the  Supreme  Court  of  Canada  ("SCC")  in 
September 2020; however, as of December 31, 2020, the SCC's decision had not yet been issued. To the extent a 
province's carbon pricing system does not meet the federal stringency requirements, the federal "backstop" price 
of carbon applies. As of December 2020, the federal backstop applied in Alberta, Manitoba, New Brunswick, Ontario 
and to electricity generation and natural gas transmission pipelines in Saskatchewan. 

In  Alberta,  facilities  emitting  over  100,000  tonnes  of  GHG  emissions  annually  are  subject  to  the  Technology 
Innovation  and  Emissions  Reductions  Regulation  (“TIER”),  which  is  considered  equivalent  to  the  federal  carbon-
pricing system for 2020. Facilities also have the choice to opt in to TIER, thereby avoiding the federal fuel charge.  

The  Government  of Canada  is  also  committed  to  reducing  methane  emissions from  the  crude oil  and  natural gas 
sector  by  40-45  percent  from  2012  levels  by  2025.  Regulatory  requirements  for  fugitive  equipment  leaks  and 
venting from well completion and compressors came into force on January 1, 2020. Further restrictions on facility 
production  venting  restrictions  and  venting  limits  for  pneumatic  equipment  come  into  force  on  January  1,  2023. 
Provinces may introduce provincial regulations, and if found to be at least equivalent with the federal scheme, shall 
be  enabled  through  a  federal  equivalency  agreement  process.  Alberta,  British  Columbia  and  Saskatchewan  have 
such equivalency agreements in place. 

The  U.S.  does  not  have  federal  legislation  establishing  targets  for  the  reduction  of,  or  limits  on,  GHG  emissions. 
However,  the  federal  Environmental  Protection  Agency  (“EPA”)  has  and  may  continue  to  promulgate  regulations 
concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program 
(“GHGRP”)  requires  any  facility  releasing  more  than  25,000  tonnes  of  CO2e  emissions  per  year  to  report  those 
emissions  on  an  annual  basis.  In  addition  to  reporting  direct  CO2e  emissions,  the  GHGRP  requires  refineries  to 

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of the ongoing tensions between the U.S. and China and Canada and China remains uncertain and the impact on 

our business is unknown. 

Shifts in global power relations may also introduce greater uncertainty with respect to issues requiring global co-

ordination  (such  as  climate  change,  trade  agreements,  tax  regulation,  freedom  of  navigation  and  technology 

regulation), as well as raise questions on the efficacy of and trust in international institutions, including those that 

underpin international trade. These types of changes may cause restrictions or impose costs on our business, and 

may inhibit our future opportunities or affect our financial condition. 

Cenovus's financial performance, operations and business may be adversely affected by any of the foregoing risks 

associated  with  international  relations  and  specifically  those  risks  arising  from  evolving  U.S.-China  and  Canada-

China relations. The nature, extent and magnitude of the effect of dynamic trade relations on Cenovus cannot be 

accurately  predicted  and  may  have  a  material  adverse  impact  on  our  business,  prospects,  financial  condition, 

results of operations, cash flows, and reputation. 

Climate-Related Risks 

There is growing international concern regarding climate change and there has been a significant increase in focus 

on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance 

companies, environmental and governance organizations, institutional investors, social and environmental activists, 

and  individuals,  are  increasingly  seeking  to  implement,  among  other  things,  regulatory  and  policy  changes, 

changes in investment patterns, and modifications in energy consumption habits and trends which, individually and 

collectively  are  intended  to  or  have  the  effect  of  accelerating  the  reduction  in  the  global  consumption  of  carbon-

based energy, the conversion of energy usage to less carbon-intensive forms and the general migration of energy 

usage away from carbon-based forms of energy. 

Climate  change  and  its  associated  impacts  may  increase  our  exposure  to,  and  magnitude  of,  each  of  the  risks 

identified in the Risk Management and Risk Factors section of this MD&A. Overall, Cenovus is not able to estimate 

at  this  time  the  degree  to  which  climate  change  related  regulatory,  climatic  conditions,  and  climate-related 

transition  risks  could  impact  the  Company’s  financial  and  operating  results.  Our  business,  financial  condition, 

results  of  operations,  cash  flows,  reputation,  access  to  capital,  access  to  insurance,  cost  of  borrowing,  access  to 

liquidity,  ability  to  fund  dividend  payments  and/or  business  plans  may,  in  particular,  without  limitation,  be 

adversely impacted as a result of climate change and its associated impacts. 

Transition Risks – Policy & Legal 

Climate Change Regulation 

Cenovus operates in several jurisdictions that regulate or have proposed to regulate air pollutants, including GHG 

emissions. Some of these regulations are in effect while others remain in  various phases of review, discussion or 

implementation.  Uncertainties  exist  relating  to  the  timing  and  effects  of  these  emerging  regulations,  other 

contemplated  legislation,  including  how  they  may  be  harmonized,  making  it  difficult  to  accurately  determine  the 

cost impacts and effects on our suppliers. Additional changes to climate change legislation may adversely affect our 

business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated 

at  this  time.  In  December 2020,  the  Government  of  Canada  proposed  increasing  the  carbon  tax  to  $170/tonne 

carbon  dioxide  equivalent  (“CO2e”)  by  2030.  To  reach  that  level,  the  price  imposed  on  carbon  will  rise  from  the 

2022  rate  of  $50/tonne  CO2e  by  $15/tonne  CO2e  each  year  until  2030.  If  made  into  law,  this  may  have  a 

significant  impact  on  Cenovus.  Notably,  several  Canadian  provinces  have  launched  constitutional  challenges  to 

Canada's  national  carbon-pricing  regime  that  were  heard  by  the  Supreme  Court  of  Canada  ("SCC")  in 

September 2020; however, as of December 31, 2020, the SCC's decision had not yet been issued. To the extent a 

province's carbon pricing system does not meet the federal stringency requirements, the federal "backstop" price 

of carbon applies. As of December 2020, the federal backstop applied in Alberta, Manitoba, New Brunswick, Ontario 

and to electricity generation and natural gas transmission pipelines in Saskatchewan. 

In  Alberta,  facilities  emitting  over  100,000  tonnes  of  GHG  emissions  annually  are  subject  to  the  Technology 

Innovation  and  Emissions  Reductions  Regulation  (“TIER”),  which  is  considered  equivalent  to  the  federal  carbon-

pricing system for 2020. Facilities also have the choice to opt in to TIER, thereby avoiding the federal fuel charge.  

The  Government  of Canada  is  also  committed  to  reducing  methane  emissions from  the  crude oil  and  natural gas 

sector  by  40-45  percent  from  2012  levels  by  2025.  Regulatory  requirements  for  fugitive  equipment  leaks  and 

venting from well completion and compressors came into force on January 1, 2020. Further restrictions on facility 

production  venting  restrictions  and  venting  limits  for  pneumatic  equipment  come  into  force  on  January  1,  2023. 

Provinces may introduce provincial regulations, and if found to be at least equivalent with the federal scheme, shall 

be  enabled  through  a  federal  equivalency  agreement  process.  Alberta,  British  Columbia  and  Saskatchewan  have 

such equivalency agreements in place. 

The  U.S.  does  not  have  federal  legislation  establishing  targets  for  the  reduction  of,  or  limits  on,  GHG  emissions. 

However,  the  federal  Environmental  Protection  Agency  (“EPA”)  has  and  may  continue  to  promulgate  regulations 

concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program 

(“GHGRP”)  requires  any  facility  releasing  more  than  25,000  tonnes  of  CO2e  emissions  per  year  to  report  those 

emissions  on  an  annual  basis.  In  addition  to  reporting  direct  CO2e  emissions,  the  GHGRP  requires  refineries  to 

estimate  the  CO2e  emissions  from  the  potential  subsequent  combustion  of  the  refinery’s  products.  The  Biden 
Administration  has  indicated  that  it  will  rejoin  the  Paris  Agreement  and  seek  to  implement  its  objectives  with 
respect to GHG emissions, including short-term global emissions reductions and net-zero global emissions by mid-
century,  and  that  it  will  begin  the  process  of  developing  U.S.  emission  reduction  targets  under  the  Paris 
Agreement.  It  is  too  early  to  assess  what  impact  these  actions  may  have  on  our  business,  financial  condition  or 
results of operations. 

Negative consequences which could arise as a result of changes to the current regulatory environment include, but 
are  not  limited  to,  changes  in  environmental  and  emissions  regulation  of  current  and  future  projects  by 
governmental  authorities,  which  could result  in changes  to  facility  design  and operating  requirements,  potentially 
increasing the cost of construction, operation and abandonment. Other possible effects from emerging regulations 
may  also  include,  but  are  not  limited  to:  increased  compliance  costs;  permitting  delays;  and  substantial  costs  to 
generate  or  purchase  emission  credits  or  allowances,  all  of  which  may  increase  operating  expenses.  Further, 
emission allowances or offset credits may not be available for acquisition or may not be available on an economic 
basis, required emissions reductions may not be technically or economically feasible to implement, in whole or in 
part,  and  failure  to  have  access  to  resources  or  technology  to  meet  emissions  reduction  requirements  or  other 
compliance  mechanisms  may  have  a  material  adverse  effect  on  our  business  resulting  in,  among  other  things, 
fines, permitting delays, penalties and the suspension of operations. 

The  extent  and  magnitude  of  any  adverse  impacts  of  current  or  additional  programs  or  regulations  beyond 
reasonably  foreseeable  requirements  cannot  be  reliably  or  accurately  estimated  at  this  time,  in  part  because 
specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the 
additional  measures  being  considered  and  the  timeframes  for  compliance.  Consequently,  no  assurances  can  be 
given that the effect of future climate change regulations will not be significant to Cenovus. 

Low Carbon Fuel Standards 

Existing  and  proposed  environmental  legislation  and  regulation  developed  by  certain  U.S.  states,  Canadian 
provinces, the Canadian federal government and members of the European Union, regulating carbon fuel standards 
could result in increased costs and reduced revenue for Cenovus. The potential regulation may negatively affect the 
marketing of Cenovus’s bitumen, crude oil or refined products, and may require us to purchase emissions credits in 
order to affect sales in such jurisdictions. 

Environment  and  Climate  Change  Canada  published  a  proposed  regulatory  framework  in  2017  for  the  Clean  Fuel 
Standard  under  the  Canadian  Environmental  Protection  Act,  1999,  followed  by  a  Regulatory  Design  Paper  in 
December 2018  and  a  Proposed  Regulatory  Approach  in  June 2019.  The  proposed  regulations  for  the  Clean  Fuel 
Standard  were  published  in  December  2020  and  final  regulations  are  planned  to  be  published  in  late  2021,  with 
new regulations under the Clean Fuel Standard targeted to come into force in 2022. The federal government has 
indicated  that  over  time,  the  new  Clean  Fuel  Standard  would  replace  the  current  Renewable  Fuels  Regulations, 
which currently require producers and importers of gasoline, diesel fuel and heating distillate to acquire a certain 
number  of  renewable  fuel  compliance  units  commensurate  with  the  volumes  of  fuel  they  produce  or  import.  The 
proposed  new  regulatory  framework  would  impose  lifecycle  carbon  intensity  requirements  for  certain  liquid  fuels 
and  establish  rules  relating  to  the  trading  of  compliance  credits.  Carbon  intensity  requirements  under  the  Clean 
Fuel  Standard  regulation  would  become  more  stringent  over  time  and  would  be  differentiated  between  different 
types  of  renewable  fuels  to  reflect  the  associated  emissions  reduction  potential.  Regulated  parties,  which  may 
include fuel producers and importers, would have some flexibility with respect to how to achieve lower carbon fuels 
in Canada. 

The  Clean  Fuel  Standard  regulation  has  the  potential  to  impact  our  business,  financial  condition,  results  of 
operations and cash flows, though at this time it is difficult to predict or quantify any such impacts. 

Renewable Fuel Standards 

Our  U.S.  refining  operations  are  subject  to  various  laws  and  regulations  that  impose  stringent  and  costly 
requirements. The Environmental Protection Agency has implemented the Renewable Fuel Standard program that 
mandates  that  a  certain  volume  of  renewable  fuel  replace  or  reduce  the  quantity  of  certain  petroleum-based 
transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of gasoline or 
diesel fuel,  achieve  compliance  with  targets  set  by  the U.S.  Environmental  Protection Agency  by blending certain 
types of renewable fuel into transportation fuel, or by purchasing RINs from other parties on the open market. The 
mandate  requires  the  volume  of  renewable  fuels  blended  into  finished  petroleum  products  to  increase  over  time 
until 2022. A RIN is a number assigned to each gallon of renewable fuel produced or imported into the U.S. RINs 
were implemented to provide refiners with flexibility in complying with the renewable fuel standards. 

Cenovus and its refinery operating partners comply with the U.S. Renewable Fuel Standard by blending renewable 
fuels  manufactured  by  third  parties  and  by  purchasing  RINs  on  the  open  market,  where  prices  fluctuate.  The 
Company  cannot  predict  the  future  prices  of  RINs  and  renewable  fuel  blendstocks,  and  the  costs  to  obtain  the 
necessary RINs and blendstocks could be material. The Company’s financial position, results of operations and cash 
flows  may  be  materially  impacted  if  we  are  required  to  pay  significantly  higher  prices  for  RINs  or  blendstocks  to 
comply with the RFS mandated standards and are unable to pass the compliance costs on to our customers. 

2020 ANNUAL REPORT  | 49

 
 
 
 
Climate Change Related Litigation 

In recent years there has been an increase in climate change related  demands, disputes, and  litigation in various 
jurisdictions including the U.S. and Canada, asserting various claims, including that energy producers contribute to 
climate change, that such entities are not reasonably managing business risks associated with climate change, and 
that  such  entities  have  not  adequately  disclosed  business  risks  of  climate  change.  While  many  of  the  climate 
change related actions are in preliminary stages of litigation, and in some cases assert novel or untested causes of 
action,  there  can  be  no  assurance  that  legal,  societal,  scientific  and  political  developments  will  not  increase  the 
likelihood of successful climate change related litigation against energy producers, including Cenovus. The outcome 
of  any  such  litigation  is  uncertain  and  may  materially  impact  our  financial  condition  or  results  of  operations. 
Moreover,  unfavourable  outcomes  or  settlements  of  litigation  could  encourage  the  commencement  of  additional 
litigation. We may also be subject to adverse publicity associated with such matters,  which may negatively affect 
public  perception  and  our  reputation,  regardless  of  whether  we  are  ultimately  found  responsible.  We  may  be 
required to incur significant expenses or devote significant resources in defense against any such litigation. 

Transition Risks – Market 

Demand and Commodity Prices 

The  recent  increase  in  focus  on  the  timing  and  pace  of  the  transition  to  a  lower-carbon  economy  and  resulting 
trends will likely affect global energy demand and usage, including the composition of the types of energy generally 
used  by  industry  and  individual  consumers.  However  it  is  not  currently  possible  to  predict  the  timelines  for  and 
precise effects of this transition to a potential lower-carbon economy, which will depend on a multitude of factors 
including the ability to develop adequate replacement sources of energy, technology development and adaptation 
including  in  the  area  of  transportation  electrification,  the  ability  to  conceptualize,  develop  and  commercialize 
technologies for  the  production,  storage  and  distribution  of  adequate  supplies of  alternative  energy,  consumption 
patterns, global growth and industrial activity, in order to predict the longer-term demand trends for carbon-based 
energy sources. All of these factors are beyond our control and could result in a high degree of price volatility for 
each of crude oil, natural gas and refined products. 

Access to Capital and Insurance 

Capital markets are adjusting to the risks that climate change poses and as a result, our ability to access capital 
and secure necessary or prudent insurance coverage may also be adversely affected in the event that institutional 
investors,  credit  rating  agencies,  lenders  and/or  insurers  adopt  more  restrictive  decarbonization  policies.  Certain 
insurance  companies  have  taken  actions  or  announced  policies  to  limit  available  coverage  for  companies  which 
derive  some  or  all  of  their  revenue  from  the  oil  sands  sector.  As  a  result  of  these  policies,  premiums  and 
deductibles for some or all of our insurance policies could increase substantially. In some instances, coverage may 
be reduced or become unavailable. As a result, we may not be able to renew our existing policies, or procure other 
desirable  insurance  coverage,  either  on  commercially  reasonable  terms,  or  at  all.  The  future  development  of  our 
business may be dependent upon our ability to obtain additional capital, including debt and equity financing. 

Transition Risks – Reputation 

Reputation and Public Perception of Alberta Oil Sands 

Development of the Alberta oil sands has received considerable attention on the subjects of environmental impact, 
climate change, GHG emissions and Indigenous engagement. Concerns about oil sands may, directly or indirectly, 
impair  the  profitability  of our  current oil  sands projects,  and  the viability of future oil  sands projects,  by creating 
significant  regulatory,  economic  and  operating  uncertainty.  Increased  public  opposition  to  the  oil  sands  industry 
could lead to constrained access to insurance, liquidity and capital and changes in demand for Cenovus’s products, 
which may impact revenue. 

For example, legislation or policies that limit the purchase of crude oil or bitumen produced from the oil sands may 
be  adopted  in domestic  and/or foreign  jurisdictions,  which,  in  turn,  may  limit  the world  market for  this crude  oil, 
reduce its price and may result in stranded assets or an inability to further develop oil resources. 

Climate Change – Physical Risks  

Extreme climatic conditions may also have material adverse effects on Cenovus’s financial condition and results of 
operations.  Weather  and  climate  affect  demand,  and  therefore,  the  predictability  of  the  demand  for  energy  is 
affected  to  a  large  degree  by  the  predictability  of  weather  and  climate.  In  addition,  Cenovus’s  exploration, 
production and construction operations, and the operations of major customers and suppliers, can be affected by 
floods,  forest  fires,  earthquakes,  hurricanes,  and  other  extreme  weather  events.  This  may  result  in  cessation  or 
diminishment of production, delay of exploration and development activities or delay of plant construction. 

Cenovus  operates  in  some  of  the  harshest  environments  in  the  world,  including  offshore  Newfoundland  and 
Labrador.  Climate  change  may  increase  the  frequency  of  severe  weather  conditions  in  these  locations  including 
winds,  flooding  and  variable  temperatures,  which  are  contributing  to  the  melting  of  northern  ice  and  increased 
creation  of  icebergs.  Icebergs  off  the  coast  of  Newfoundland  and  Labrador  may  threaten  Atlantic  oil  production 
facilities, cause spills, damage assets, disrupt production or have human impacts. 

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Our other crude oil and natural gas production activities are also subject to chronic physical risks such as a shorter 
timeframe for our winter drilling program, changes in the water table and reduced access to water due to drought 
conditions. A systemic change in temperature or precipitation patterns could result in more challenging conditions 
for  the  construction  of  ice  roads,  execution  of  our  winter  drilling  program  and  reclamation  activities  and  could 
reduce the availability of water due to the increasing likelihood of drought conditions. 

Environmental Risk 

All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a 
variety  of  federal,  provincial,  territorial,  state  and  municipal  laws  and  regulations  in  the jurisdictions  in  which  we 
operate (collectively, the “environmental regulations”). Environmental regulations provide that wells, facility sites, 
refineries and other properties and practices associated with our operations be constructed, operated, maintained, 
abandoned,  reclaimed  and  undertaken  in  accordance  with  the  requirements  set  out  therein.  In  addition,  certain 
types of operations, including exploration and development projects and changes to certain existing projects, may 
require the submission and approval of environmental impact assessments or permit applications. 

Cenovus  anticipates  that  further  changes  in  environmental  legislation  could  occur,  which  may  result  in  stricter 
standards  and  enforcement,  larger  fines  and  liabilities,  the  introduction  of  emissions  limits,  increased  compliance 
costs  and  approval  delays  for  critical  licences  and  permits.  The  complexities  of  changes  in  environmental 
regulations make it difficult to predict the potential future impact to Cenovus. 

Compliance  with  environmental  regulations  requires  significant  expenditures.  Our  future  capital  expenditures  and 
operating expenses  could  continue  to  increase  as  a result of,  among  other  things,  developments  in  our business, 
operations,  plans  and  objectives  and  changes  to  existing,  or  implementation  of  new,  environmental  regulations. 
Failure  to  comply  with  environmental  regulations  may  result  in,  among  other  things,  the  imposition  of  fines, 
penalties,  environmental  protection  orders,  suspension  of  operations,  and  could  adversely  affect  our  reputation. 
The  costs  of  complying  with  environmental  regulations  may  have  a  material  adverse  effect  on  our  business, 
financial condition, results of operations and cash flows. The implementation of new environmental regulations or 
the  modification  of  existing  environmental  regulations  affecting  the  crude  oil  and  natural  gas  industry  generally 
could  reduce  demand  for  crude  oil  and  natural  gas  as  well  as  shift  hydrocarbon  demand  toward  relatively  lower 
carbon sources, increase compliance costs, lengthen project implementation times, and have an adverse effect on 
our business, financial condition, results of operations and cash flows. 

Canadian Species at Risk Act 

The  Canadian  federal  Species  at  Risk  Act,  as  well  as  provincial  regulation  regarding  threatened  or  endangered 
species  and  their  habitat  may  limit  the  pace  and  the  amount  of  development  or  activity  in  areas  identified  as 
critical habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal 
government  in  relation  to  their  obligations  under  the  Species  at  Risk  Act  have  raised  issues  associated  with  the 
protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, a suite of 
initiatives  have  been  undertaken  to  support  caribou  recovery,  including  the  Draft  Provincial  Woodland  Caribou 
Range  Plan,  which  was  released  in  2017  but  has  not  yet  been  finalized.  Other  initiatives  include  negotiation  of 
conservation agreements under Section 11 of the Species at Risk Act (which codifies concrete measures to support 
the conservation of the species and the protection of its critical habitat), and the elaboration of sub-regional plans 
for  the  Cold  Lake,  Bistcho  and  Upper Smokey  areas,  to  address recovery outcomes  for certain  caribou  ranges.  If 
plans  and  actions  undertaken  by  the  provinces  are  deemed  insufficient  to  support  caribou  recovery,  the  federal 
legislation includes the ability to implement measures that would preclude further development or modify existing 
operations.  The  extent  and  magnitude  of  any  potential  adverse  impacts  of  legislation  on  in  situ  oil  sands  project 
development  and  operations  cannot  be  estimated,  as  uncertainty  exists  as  to  whether  plans  and  actions 
undertaken by the provinces will be sufficient to support caribou recovery. 

Canadian Federal Air Quality Management System 

The  Multi  Sector  Air  Pollutants  Regulations  (“MSAPR”),  issued  under  the  Canadian  Environmental  Protection  Act, 
1999,  seek  to  protect  the  environment  and  health  of  Canadians  by  setting  mandatory,  nationally-consistent  air 
pollutant  emission  standards.  The  MSAPR  are  aimed  at  equipment-specific  Base-Level  Industrial  Emissions 
Requirements  (“BLIERs”).  Nitrogen  oxide  BLIERs  from  our  non-utility  boilers,  heaters  and  stationary  engines  are 
regulated in accordance with specified performance standards. We anticipate that the MSAPR will result in adverse 
impacts  to  Cenovus  including  but  not  limited  to  capital  investment  required  to  retrofit  existing  equipment  and 
increased operating costs. 

Canadian  Ambient  Air  Quality  Standards  (“CAAQS”)  for  nitrogen  dioxide,  sulphur  dioxide,  fine  particulate  matter 
and  ozone  were  introduced  as  part  of  a  national  Air  Quality  Management  System.  Provinces  may  implement  the 
CAAQS  at  the  regional  air  zone  level  and  air  zone  management  actions  may  include  more  stringent  emissions 
standards applicable to industrial sources from approval holders in regions where Cenovus operates that may result 
in adverse impacts including but not limited to capital investment related to retrofit existing facilities and increased 
operating costs. 

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Review of Environmental and Regulatory Processes 

Increased  environmental  assessment  obligations  imposed  by  federal,  provincial,  territorial,  state  and  municipal 
governments in the jurisdictions in which we conduct operations, development or exploratory activities may create 
risk  of  increased  costs  and  project  development  delays. The  extent  and  magnitude  of  any  adverse  impacts  of 
changes to the legislation or policies on project development and operations cannot be estimated at this time. 

The Canadian federal Bill C-69, an Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, 
to  amend  the  Navigation  Protection Act  (renamed  the  Canadian  Navigable  Water  Act)  and  to make consequential 
amendments to other Acts came into force in August 2019. In addition, Bill C-68, which amended the Fisheries Act, 
came into force at the same time. 

The  Fisheries  Act  amendments  restored  the  previous  prohibition  against  “harmful  alteration,  disruption  or 
destruction of fish habitat” and  the prohibition against causing the death of fish by means other than fishing and 
introduced  several  new  requirements  expanding  the  scope  of  protection  and  role  of  Indigenous  groups  and 
interests.  These  prohibitions  may  result  in  increased  permitting  requirements  and  time  to  obtain  permits  where 
Cenovus’s operations potentially impact fish or fish habitat. 

The  Canadian  Navigable  Waters  Act  expanded  its  scope  to  all  navigable  waters,  created  greater  oversight  for 
navigable  waters,  and  introduced  requirements  expanding  the  scope  of  protection  and  the  role  of  Indigenous 
groups  and  interests.  The  broader  application  of  the  Canadian  Navigable  Waters  Act  may  result  in  increased 
permitting  requirements  and  time  to  obtain  permits  where  Cenovus’s  operations  potentially  impact  navigable 
waters. 

The  Impact  Assessment  Act  (“IAA”)  established  the  Impact  Assessment  Agency  of  Canada,  which  leads  and 
coordinates  impact  assessments  for  all  designated  projects.  The  IAA  expands  the  assessment  considerations 
beyond  the  environment  to  expressly  include  health,  economic,  social,  and  gender  impacts,  as  well  as 
considerations related to sustainability and Canada’s climate change commitments. 

Of  note,  the  revised  Project  List  outlined  in  the  Physical  Activities  Regulations  under  the  IAA  captures  in  situ  oil 
sands facilities with a bitumen production capacity of 2,000 m3/day or more, and expansions of existing in situ oil 
sands facilities  if the expansion would result in an increase in bitumen production capacity of 50 percent or more 
and  a  total  bitumen  production  capacity  of  2,000  m3/day  or  more,  but  provides  an  exemption  for  a  project 
proposed within a province in which there is a legislated limit on GHG emissions produced by the oil sands sector. 
For as long as the provincial government maintains the cap on oil sands emissions in Alberta and the cap has not 
been  reached,  Cenovus’s  in  situ  oil  sands  projects  should  be  exempted  from  the  application  of  the  new  federal 
impact assessment system, provided the above-noted conditions are met. However, other types of projects would 
undergo a federal assessment. 

Water Licences 

Cenovus  utilizes fresh  water  in  certain  operations,  which  is  obtained  under  licenses  issued within  each respective 
jurisdiction’s regulations. If water use fees increase or a change under these licences reduces the amount of water 
available  for  our  use,  production  could  decline  or  operating  expenses  could  increase,  both  of  which  may  have  a 
material adverse effect on our business and financial performance. There can be no assurance that the licences to 
withdraw water will not be rescinded or that additional conditions will not be added to these licences.  There is no 
assurance that if we require new licences or amendments to existing licences, that these licences or amendments 
will  be  granted  on  favourable  terms.  This  may  adversely  affect  our  business,  including  the  ability  to  operate  our 
assets and execute development plans. 

Hydraulic Fracturing 

Certain  stakeholders  have  made  claims  that  hydraulic  fracturing  techniques  are  harmful  to  surface  water  and 
drinking water sources and suggest that additional federal, provincial, state, territorial and/or municipal laws and 
regulations may be needed to more closely regulate the hydraulic fracturing process.  

In addition, some areas of British Columbia and Alberta are experiencing increasing localized frequency of seismic 
activity which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to 
oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has 
been  correlated  with  hydraulic  fracturing  in  Western  Canada,  which  has  prompted  legislative  and  regulatory 
initiatives intended to address these concerns. 

The  Canadian  federal  government  and  certain  provincial  governments  continue  to  review  certain  aspects  of  the 
existing scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. The 
Government  of  British  Columbia  released  an  action  plan  in  2019  based  on  the  results  of  its  scientific  review  of 
hydraulic  fracturing  and  related  impacts  on  water  and seismic  activity,  which  contains  a  number of  actions  to be 
implemented in a phased approach that will include increased monitoring, aquifers mapping and improvements to 
the  regulatory  regime.  In  Alberta,  the  AER  has  implemented  seismic  monitoring  and  reporting  requirements  for 
hydraulic fracturing operations in certain zones in some active oil and gas areas of Alberta. 

Any  new  laws,  regulations  or  permitting  requirements  regarding  hydraulic  fracturing  could  lead  to  limitations  or 
restrictions  to  oil  and  gas  development  activities,  operational  delays,  increased  compliance  costs,  additional 

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operating  requirements,  or  increased  third-party  or  governmental  claims  that  could  increase  our  cost  of  doing 
business  as  well  as  reduce  the  amount  of  natural  gas  and oil  that  Cenovus  is  ultimately  able  to  produce from  its 
reserves. 

Cenovus ESG Focus Areas and Targets 

Generally  speaking,  Cenovus's  ESG  targets  depend  significantly  on  our  ability  to  execute  our  current  business 
strategy, related milestones and schedules, and to successfully integrate the assets of Cenovus and the assets of 
Husky, each of which can be impacted by the numerous risks and uncertainties associated with our business and 
the industry in which we operate, as outlined in the Risk Management and Risk Factors section of this MD&A. We 
recognize that our ability to adapt to and succeed in a lower-carbon economy will be compared against our peers. 
Investors and stakeholders increasingly compare companies based on ESG-related performance, including climate-
related  performance.  Failure  to  achieve  our  ESG  targets,  or  a  perception  among  key  stakeholders  that  our  ESG 
targets  are  insufficient,  could  adversely  affect  our  reputation  and  our  ability  to  attract  capital  and  insurance 
coverage.  

There  is  also  a  risk  that  some  or  all  of  the  expected  benefits  and  opportunities  of  achieving  the  various  ESG 
targets may fail to materialize, may cost more to achieve or may not occur within the anticipated time periods. 
In addition, there are risks that the actions taken by Cenovus in implementing targets and  ambitions relating to 
ESG  focus  areas  may  have  a  negative  impact  on  our  existing  business  and  operations  and  increase  capital 
expenditures, which could have a negative impact on our future operating and financial results.  

ESG Targets May Change Following Completion of the Arrangement 

Completion of the Arrangement between Cenovus and Husky on January 1, 2021 resulted in a combination of the 
business activities previously carried on separately by each of Husky and Cenovus. Cenovus remains committed to 
world-class safety performance and ESG leadership following closing of the Arrangement. This includes completing 
additional analysis to set new ESG targets and ambitions for the combined business. 

The  ESG  targets  and  ambitions  of  the  combined  business  may  not  necessarily  be  the  same  as  the  targets  or 
ambitions  previously  set  by  Cenovus.  This  is  dependent,  in  large  measure,  on  the  completion  of  our  review  and 
analysis of the combined business following the completion of the Arrangement to determine whether such targets 
and  ambitions  remain  appropriate  for  the  combined  business.  In  addition,  the  integration  of  Husky  and  Cenovus 
will  require  the  dedication  of  substantial  effort,  time  and  resources  on  the  part  of  management  and  staff  of  the 
combined company, which may divert focus from planned initiatives, including development and implementation of 
ESG targets and ambitions, towards other operational matters and could result in a disruption to, or delay in, the 
development and implementation of ESG targets and ambitions for the combined company or a shift in resources to 
other operational and business strategies.  

The  below  sections  include  discussion  of  the  ESG  targets  released  by  Cenovus  in  January 2020  which  may  be 
subject  to change  as  a  result  of our  determination of whether such  targets  and  ambitions  remain  appropriate for 
the combined business. 

Greenhouse Gas Emissions and Targets 

Cenovus's  future  results  and  its  ability  to  respond  to  and  manage  transition  and  physical  risks  of  climate  change 
may depend in part on our ability to adapt and apply our business model to a lower-carbon economy and to lower 
scope  1  and  2  GHG  emissions  (see  Definitions  section  of  this  MD&A).  Our  ability  to  lower  scope  1  and  2  GHG 
emissions  on  both  an  absolute  basis  and  in  terms  of  intensity  in  our  operations  and  our  long-term  ambition  of 
reaching net-zero emissions by 2050, are subject to numerous risks and uncertainties and our actions taken in 
implementing such targets may also expose us to certain additional and/or heightened financial and operational 
risks. Furthermore, our long-term ambition of reaching net-zero emissions by 2050 is inherently less certain due 
to the longer timeframe and certain factors outside of our control, including the commercial application of future 
technologies that may be necessary for us to achieve this long-term ambition.  

A  reduction  in  GHG  emissions  relies  on,  among other  things,  Cenovus's  ability  to  develop,  access  and  implement 
commercially  viable  and  scalable  emission  reduction  strategies  and  related  technology  and  products.  In  addition, 
there  are  other  operational  risks  that  may  hinder  our  ability  to  successfully  meet  our  GHG  emission  targets  and 
goals, including: unexpected impediments to, or effects of, the implementation of cogeneration plants at our Foster 
Creek and Christina Lake oil sands facilities and other investments in renewables, including in respect of available 
offsets  and  the  availability  and  status  of  credit  or  offset  for  cogeneration  facilities  and  other  renewables;  the 
effectiveness of air flue exchanges at Foster Creek and Christina Lake; our ability to electrify and otherwise adjust 
our  operations  in  the  Conventional  segment;  the  unavailability  of,  or  limited  benefits  from,  technology  that  is 
expected  to  be  commercially  viable  in  the  near  term  and  their  associated  future  benefits,  including  SAGD 
enhancement technologies, such as solvent-aided process and solvent-driven process technologies, carbon capture, 
utilization and storage technology and downhole technology improvements; and a failure to capture the anticipated 
benefits  of  continued  technological development,  industry collaboration  and  innovation  to find  solutions  to  reduce 
costs and GHG emissions intensity. In the event that we are unable to implement these strategies and technologies 
as  planned  without  negatively  impacting  our  expected  operations  or  cost  structure,  or  such  strategies  or 

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technologies do not perform as expected, we may be unable to meet our 2050 ambition on the current timelines, 
or at all. 

In  addition,  achieving our  GHG  2050  ambition  will  require capital  expenditures  and  Company resources,  with  the 
potential  that  expectations  regarding  the  costs  required  to  achieve  these  targets  and  ambitions  differ  from  our 
original estimates and the differences may be material. Furthermore, a shift of expenditures and resources towards 
such targets and ambition may negatively impact our business and operations. The cost of investing in emissions-
intensity reduction technologies, and the resultant change in the deployment of resources and focus, could have a 
negative impact on our future operating and financial results. 

Our GHG emissions targets and ambitions may also be subject to change as a result of Cenovus’s determination 
of whether such targets and ambitions remain appropriate for the combined business. 

Indigenous Engagement Target 

Cenovus's Indigenous engagement target to spend $1.5 billion with Indigenous owned or operated businesses by 
the end of 2030 is subject to a number of financial, operational and efficiency risks relating to  actions taken in 
implementing such target.  

In  addition,  a  failure  or  delay  in  achieving  our  Indigenous  engagement  target  may  adversely  affect  our 
relationship  with  neighboring  Indigenous  businesses  and  communities  and  our  broader  reputation.  If  we  are 
unable  to  maintain  a  positive  relationship  with  Indigenous  communities  near  our  operations,  our  progress  and 
ability  to  develop  and  operate  properties  in  line  with  our  current  business  and  operational  strategies  may  be 
adversely impacted.  

Our  Indigenous  engagement  target  may  also  be  subject  to  change  as  a  result  Cenovus’s  determination  of 
whether such a target remains appropriate for the combined business. 

Land and Wildlife Target 

Our  land  and  wildlife  targets  are  composed  of  the  reclamation  of  1,500 decommissioned  well  sites  and 
$40 million  in  spend  between  2016  and  2030  to  restore  more  land  within  caribou  ranges  than  disturbed  by 
Cenovus’s activity. Our ability to meet this target is subject to various environmental and regulatory risks, which 
could  impose  significant  costs,  restrictions,  liabilities  and  obligations  on  Cenovus  and  limit  our  capacity  to 
achieve such targets. See Abandonment and Reclamation Cost Risk above. 

Financial  risks  including  an  increase  in  operating  costs,  changes  to  market  conditions  and  access  to  additional 
capital, if needed, could result in our inability to fund, and ultimately meet, our land and wildlife targets on the 
current timelines, or at all. In addition, the development and implementation of range plans in these areas may 
have an impact on the pace and amount of development in these areas and could potentially increase costs for 
restoration  or  offsetting  requirements,  which  could  have  a  material  adverse  effect  on  our  business,  financial 
condition,  reserves  and  results  of  operations.  An  inability  to  develop,  execute  on  and  complete  ongoing 
reclamation  plans  and  proactively  manage  our  interactions  with  wildlife  may  adversely  impact  Cenovus's 
progress and ability to explore and develop properties. 

Our  land  and wildlife  targets  may  also  be subject  to  change as a result of  Cenovus’s  determination  of  whether 
such targets remain appropriate for the combined business. 

Water Stewardship Target 

Cenovus's ability to achieve a freshwater intensity of 0.1 barrels of freshwater per barrel of oil equivalent by the 
end  of  2030  will  depend  on  the  commercial  viability  and  scalability  of  relevant  water  reduction  strategies  and 
related steam and water usage technology and products. There are risks associated with relying largely or partly 
on  new  technologies,  the  incorporation  of  such  technologies  into  new  or  existing  operations  and  acceptance  of 
new  technologies  in  the  market.  In  the  event  we  are  unable  to  effectively  and  efficiently  deploy  the  necessary 
technology,  or  such  strategies  or  technologies  do  not  perform  as  expected,  achieving  our  stated  target  of 
reducing our water intensity could be interrupted, delayed or abandoned.  

Our water stewardship targets may also be subject to change as a result of Cenovus’s determination of whether 
such targets remain appropriate for the combined business. 

Reputation Risk 

We  rely  on  our  reputation  to  build  and  maintain  positive  relationships  with  investors  and  other  stakeholders,  to 
recruit  and  retain  staff,  and  to  be  a  credible,  trusted  company.  Any  actions  we  take  that  influence  public  or  key 
stakeholder  opinions  have  the  potential  to  impact  our  reputation  which  may  adversely  affect  our  share  price, 
development plans and our ability to continue operations. There is increasing opposition from activist organizations 
and  the  public  towards  oil  sands  operations  stemming  from  the  perceived  impact  of  the  industry  on  the 
environment,  climate  change  and  GHG  emissions.  See  Reputation  and  Public  Perception  of  Alberta  Oil  Sands  for 
further discussion. 

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Other Risks 

Risks Related to the Arrangement 

Entry into New Business Activities 

Prior  to  the  Arrangement,  Cenovus's  business  was  focused  on  the  development  and  production  of  bitumen  in 
northeast  Alberta,  natural  gas  and  NGLs  processing  in  the  Conventional  segment,  and  refining,  transporting, 
marketing and selling crude oil, natural gas and NGLs in Canada and the U.S. Husky's business involved upstream 
development and production in Western Canada, offshore China, Indonesia and Atlantic Canada, and upgrading of 
heavy  oil,  refining  crude  oil,  and  marketing  refined  petroleum  products  in  Canada  and  the  U.S.  The  combined 
company's business comprises a combination of these businesses, which results in a different business and asset 
mix  than  the  previous  standalone  businesses  of  Cenovus  and  Husky,  respectively.  The  expansion  of  Cenovus's 
activities into new geographic and operational areas as a result of the Arrangement may present additional risks or 
significantly increase its exposure to one or more of Cenovus's present risk factors. The new business combination 
may also subject Cenovus to different business risks than those which were previously applicable to Cenovus and 
Husky as separate entities. 

Possible Failure to Realize Anticipated Benefits of the Arrangement 

Realizing  the  anticipated  synergies  from  integrating  the  respective  businesses  of  Cenovus  and  Husky  depends  in 
part on, among other things, successfully consolidating functions and integrating operations, systems, procedures 
and  personnel  in  a  timely  and  efficient  manner.  Achieving  the  benefits  of  the  Arrangement  also  depends  on 
Cenovus's  ability  to  effectively capitalize on  its  scale, scope  and  leadership  position  in  the oil  sands  and  wider oil 
and natural gas industry, to realize the anticipated capital and operating synergies and to maximize the potential of 
its improved growth and capital funding opportunities. 

The  integration  of  the  Cenovus  and  Husky  assets  to  realize  the  benefits  of  the  Arrangement  will  require  the 
dedication of substantial management effort, time and resources which may divert Cenovus’s Management's focus 
and resources from other strategic opportunities and operational matters. The integration process may result in the 
loss of key employees and the disruption of ongoing business and employee relationships that may adversely affect 
Cenovus's  ability  to  achieve  the  anticipated  benefits  of  the  Arrangement.  Cenovus  may  also  incur  additional 
expenses related to the Arrangement and the integration of Cenovus and Husky, which may limit Cenovus's ability 
to realize some or all of the anticipated benefits of the Arrangement.  

If  Cenovus  is  not  able  to  successfully  achieve  the  synergies  associated  with  the  Arrangement,  or  the  cost  to 
achieve these synergies is greater than expected, the anticipated benefits of the Arrangement may not be realized 
fully, or at all, may take longer to realize than expected, or may result in unforeseeable adverse effects. There can 
be  no  assurance  that  Cenovus  will  be  able  to  achieve  the  synergies  or  realize  the  anticipated  benefits  of  the 
Arrangement  in  a  timely  manner  or  at  all.  Failing  to  realize  the  anticipated  benefits  of  the  Arrangement  may 
adversely affect Cenovus's financial condition, results of operations, reputation and share price.  

Cenovus’s Ability to Integrate Husky’s Business with its Own 

Given  the  increased  scope  and  complexity  of  our  operations,  Cenovus  may  not  be  able  to  integrate  Husky's 
operations  or  restructure  Cenovus's  previously  existing  business  operations  without  encountering  difficulties  and 
delays.  The  integration  process  could  result  in  disruption  of  existing  relationships  with  suppliers,  employees, 
customers  and  other  constituencies  of  each  company.  Further,  Cenovus  will  be  required  to  maintain  its  financial 
and  strategic  focus  while  integrating  Husky's  business  and  avoid  inconsistencies  in  implementing  uniform 
standards, controls, procedures and policies, as appropriate. Our ability to integrate the businesses will depend in 
part on our ability to access or implement some or all of the personnel and technology necessary to efficiently and 
effectively  operate  Husky's  assets.  There  can  be  no  assurance  that  management  will  be  able  to  successfully 
integrate  the  businesses  to  achieve  any  of  the  synergies  or  other  benefits  that  are  expected  to  result  from  the 
Arrangement.  

The  ongoing  integration  process  involves  numerous  operational,  strategic,  financial,  accounting,  legal,  tax  and 
other  risks  and  uncertainties  associated  with  Cenovus’s  and  Husky's  business  and  operations.  Difficulties  in 
integrating our businesses may result in variations in expected performance,  operational challenges or the failure 
to  realize  anticipated  efficiencies  on  the  expected  timelines  or  at  all.  Cenovus's  and  Husky's  existing  businesses 
may also be negatively impacted by the combination.  

Potential difficulties that may be encountered in the integration process include, among others: (i) the inability to 
successfully  integrate  the  businesses  in  a  manner  that  permits  Cenovus  to  achieve  the  anticipated  revenue  and 
cost savings on the expected timelines or at all; (ii) complexities associated with managing a larger, more complex, 
multinational integrated business; (iii) achieving the anticipated operating synergies on the expected timelines or 
at all; (iv) integrating personnel at all levels of the company over multiple jurisdictions, effectively and efficiently; 
(v)  difficulties  integrating  and  maintaining  relationships  with  Husky's  industry  contacts  and  existing  business 
partners;  and  (vi)  the  disruption  of,  or  the  loss  of  momentum  in,  each  of  Cenovus's  and  Husky's  ongoing 
businesses. Such challenges may prohibit Cenovus from successfully integrating Husky's business with its own or 
may materially delay the integration process. A failure to integrate the business on the expected timeline, or at all, 

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may  have  an  adverse  effect  on  Cenovus's  financial  condition,  results  of  operations,  and  ability  to  realize  the 
anticipated benefits of the Arrangement.  

It is possible that the integration process could result in the loss of key employees to assist in the integration and 
operation  of  Husky  and  Cenovus,  which  may  exacerbate  integration  challenges.  Difficulties  or  delays  in  the 
integration  process  or  the  inability  to  partially  or  fully  integrate  Husky's  business  with  our  own  could  have  a 
material  adverse  effect  on  our  business,  cash  flow,  operating  results,  financial  condition,  reputation  and  share 
price.  

Costs Associated with the Integration of Cenovus’s and Husky’s Businesses 

Cenovus  may  incur significant  costs related  to  formulating  and  implementing ongoing  integration plans,  including 
facilities and systems consolidation costs and other employment-related costs. Cenovus will continue to assess the 
magnitude of these costs and additional unanticipated costs may be incurred in connection with the integration of 
the two companies. While Cenovus has accounted for a certain level of expenses, many factors beyond our control 
may affect the total amount or the timing of expenses associated with the integration process. The elimination of 
duplicative  costs,  as  well  as  the  realization  of other  efficiencies  related  to  the  integration  of  the  businesses,  may 
not offset integration-related costs and achieve a net benefit in the near term, or at all. The costs described above 
and  any  unanticipated  costs  and  expenses  related  to  the  integration  may  have  an  adverse  effect  on  Cenovus's 
financial condition and results of operations. 

Increased Indebtedness  

Cenovus's  increased  indebtedness  could  have  adverse  consequences  for  Cenovus,  including:  reducing  funds 
available for other business purposes; limiting Cenovus's ability to obtain additional financing for working capital, 
capital expenditures, product development, debt service requirements, acquisitions and general corporate or other 
purposes;  restricting  Cenovus's  flexibility  and  discretion  to  operate  its  business;  limiting  Cenovus's  ability  to 
declare dividends; having to dedicate a portion of Cenovus's cash flows from operations to the payment of interest 
on  its  existing  indebtedness  and  not  having  such  cash  flows  available  for  other  purposes;  exposing  Cenovus  to 
increased interest expense on borrowings at variable rates; limiting Cenovus's ability to adjust to changing market 
conditions; placing Cenovus  at  a  competitive  disadvantage compared  with  its  competitors  with  less debt;  making 
Cenovus  more  vulnerable  to  a  downturn  in  general  economic  conditions;  and  reducing  funds  available  for  capital 
expenditures that are important to Cenovus’s business. 

Dilutive Effect 

The  issuance  of  Cenovus  common  shares  pursuant  to  the  Arrangement  had  an  immediate  dilutive  effect  on  the 
ownership interest of existing shareholders of Cenovus. The issuance of additional Cenovus  common  shares upon 
exercise,  from  time  to  time,  of  Cenovus  Warrants  or  Cenovus  Replacement  Options  issued  to  holders  of  Husky 
common  shares  and  Husky  options  prior  to  the  Arrangement  will  have  a  further  dilutive  effect  on  the  ownership 
interest  of  shareholders  of  Cenovus.  Such  issuances  will  have  a  dilutive  effect  on  Cenovus's  earnings  per  share, 
which could adversely affect the market price of Cenovus  common shares and may adversely impact the value of 
Cenovus shareholders' investments.  

It  is  also  expected  that,  from  time  to  time,  Cenovus  will  grant  additional  equity  awards  to  our  employees  and 
directors  under  the  combined  Company's  compensation  plans.  These  additional  equity  awards  will  have  a  further 
dilutive effect on Cenovus's earnings per share, which could also negatively affect the market price of the Cenovus 
common shares. 

Potential Undisclosed and Unforeseen Liabilities Associated with the Arrangement 

In  connection  with  the  Arrangement,  there  may  be  liabilities  that  we  failed  to  discover,  underestimated  or  were 
unable  to  quantify  in  our  due  diligence  conducted  prior  to  the  execution  of  the  Arrangement  Agreement  and 
completion  of  the  Arrangement.  In  addition,  the  Arrangement  may  subject  Cenovus  to  unforeseen  liabilities, 
including  environmental  and  regulatory  liabilities  in  Canada  and  other  foreign  jurisdictions.  Cenovus  may  now  be 
subject  to  claims  related  to  Husky's  operations  and  previous  actions,  including  those  of  its  current  and  former 
directors and employees. We may also be subject to adverse publicity associated with such matters, regardless of 
whether  we  are  ultimately  found  responsible  and  may  be  required  to  incur  significant  expenses  or  devote 
significant resources in defense against any litigation of such claims. The outcome of any such litigation is uncertain 
and may negatively impact our financial condition, results of operations and reputation.  

Pro  Forma  Financial  Information  may  not  be  Indicative  of  Cenovus's  Financial  Condition  or  Results  following  the 
Arrangement 

The  pro  forma  financial  information  contained  in  Cenovus's  public  disclosure  record  is  presented  for  illustrative 
purposes  only  as of  its  respective  dates  and may  not  be  indicative  of  the current  financial  condition  or results of 
operations  of  Cenovus.  The  unaudited  pro  forma  financial  information  was  derived  from  the  respective  historical 
financial statements of Cenovus and Husky, and certain adjustments and assumptions were made as of such dates 
to give effect to the Arrangement. The information upon which these adjustments and assumptions were made was 
preliminary  and  these  kinds  of  adjustments  and  assumptions  are  difficult  to  make  with  complete  accuracy. 
Accordingly,  the  combined  business,  assets,  results  of  operations  and  financial  condition  may  differ  significantly 

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from those indicated in the unaudited  pro forma financial information,  and such variations may negatively impact 
our financial condition, results of operations and share price. 

Pro Forma Reserves Information may not be Indicative of Cenovus's Reserves following the Arrangement  

The pro forma reserves information included in the AIF is based on the reserves reports prepared by McDaniel and 
GLJ  for  Cenovus  (the  "2020 Cenovus  Reserves  Report"),  and  Husky’s  reserves  estimates  have  been  prepared  by 
internal qualified reserves evaluators in accordance with the COGE Handbook, and have been audited and reviewed 
by  Sproule,  an  independent  qualified  reserves  auditor  (the  "2020 Husky  Reserves  Report"),  each  effective 
December 31, 2020 (collectively, the "2020 Reserves Reports"). The reserves information presented in each of the 
2020 Reserve Reports has been aggregated by Cenovus for illustrative purposes. The 2020 Reserves Reports were 
prepared  using  different  assumptions  and  an  independent  reserves  report  effective  December 31, 2020  was  not 
prepared for the combined company. Therefore, the actual reserves of the combined company, if evaluated as of 
December 31, 2020  may  differ from  the  pro forma reserves  presented  in  the AIF.  Cenovus  and  Husky,  as stand-
alone entities, have different operational and financial capabilities, which impacts their ability to develop reserves. 
And finally, there are systemic differences in the future development costs for each of Cenovus and Husky.  

Further,  were  an  independent  reserves  evaluation  to  be  completed  on  our  collective  reserves  as  a  result  of  the 
Arrangement, the assumptions underlying the 2020 Husky Reserves Report may be materially different from those 
assumptions  used  to  evaluate  the  combined  company's  collective  reserves.  Our  actual  reserves  could  vary 
materially  from  these  pro  forma  estimates  and  the  Husky  reserves  acquired  in  connection  with  the  Arrangement 
may be less than expected, which could adversely affect Cenovus's business, operations, financial results and share 
price.  

Engineering,  Reserves,  Economic  and  Environmental  Assessments  in  connection  with  the  Arrangement  may  be 
Inaccurate  

Acquisitions of oil and natural gas properties or companies are based in large part on  engineering, environmental 
and  economic  assessments  made  by  the  acquirer,  independent  engineers  and  consultants.  The  assessments 
include a series of assumptions regarding such factors as recoverability and marketability of crude oil, natural gas 
and  refined  products,  environmental  restrictions  and  prohibitions  regarding  releases  and  emissions  of  various 
substances,  future  commodity  prices  and  operating  costs,  future  capital  expenditures  and  royalties  and  other 
government levies that may be imposed over the producing life of the reserves. Many of these factors are subject 
to change and are beyond our control. All such assessments involve a measure of geologic, engineering, economic, 
environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or 
capital expenditures than anticipated. 

Specifically,  the  2020 Husky  Reserves  Report  was  prepared  in  respect  of  periods  prior  to  completion  of  the 
Arrangement during which the crude oil and natural gas properties of Husky were operated on a stand-alone basis. 
Although Cenovus's Management believes the information contained in the 2020 Husky Reserves Report is reliable, 
Cenovus  has  not  independently  verified  the  historical  information  contained  in  such  report  and  is  unable  to  fully 
assess  Husky's  procedures  for  providing,  assembling  and  reporting  information  to  Sproule  associated  with  Husky 
and its assets. In particular, the reserve and recovery information contained in the 2020 Husky Reserves Report is 
only an estimate and the actual production from, and ultimate reserves of, those properties may be greater or less 
than the estimates contained in such report.  

Inclusion of Historical Information relating to Husky 

The  Arrangement  was  effected  on  January 1, 2021,  and  the  integration  of  Cenovus's  and  Husky's  business  is 
ongoing. Cenovus has not yet completed independently evaluating and updating certain information relating to the 
assets, reserves and businesses acquired in the Arrangement and certain information  contained in this MD&A and 
Cenovus's public disclosure record is based on historical information relating to Husky. Such historical information 
relating  to  Husky  is  derived  from,  among  other  things,  previous  Husky  public  disclosure  and  from  information 
provided by current and former Husky directors, officers and employees. Much of the disclosure relating to Husky 
relates to periods prior to Cenovus's ownership of Husky, and therefore was generated by disclosure controls and 
procedures  that  may  differ  from  those  in  place  at  Cenovus.  Thus,  information  from  the  two  companies  may  not 
have  been  generated  and  reported  using  equivalent  standards.  Further,  Cenovus's  Management's  expectations 
about  the  combined  entity's  future  performance  reflect  the  current  state  of  its  information  about  Husky  and  its 
operations and there can be no assurance that such information is accurate in all material respects. Inaccuracies in 
historical  information  relating  to  Husky  may  cause  Cenovus's  financial  and  operational  results  to  vary  from  our 
expectations, which may in turn adversely affect our financial condition, results of operations and share price.  

Uncertainty related to Customers, Suppliers or Other Third Parties  

As  a  result  of  the  Arrangement,  Cenovus  may  experience  impacts  on  relationships  with  customers,  suppliers  or 
other  third  parties  that  may  harm  Cenovus's  business  and  results  of  operations.  Certain  customers,  suppliers  or 
other third parties may seek to terminate or modify contractual obligations whether or not such contractual rights 
are triggered as a result of the Arrangement. There can be no guarantee that customers, suppliers or other third 
parties will remain with or continue to have a relationship with Cenovus or Husky or do so on the same or similar 
contractual  terms.  If  any  customers,  suppliers  or  other  third  parties  seek  to  terminate  or  modify  contractual 

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obligations  or  discontinue  their  relationships  with  Cenovus  or  Husky,  then  Cenovus's  business  and  results  of 
operations may be adversely affected.  

Any disruptions with third parties could limit our ability to achieve the anticipated benefits of the Arrangement or 
may be detrimental to Cenovus's and Husky's existing businesses, operations and financial conditions.  

Risks Associated with the Cenovus Warrants 

There  can  be  no  assurance  that  an  active  public  market  for  the  Cenovus  Warrants  will  be  sustained.  If  such  a 
market is sustained, the market price of the Cenovus Warrants may be adversely affected by a variety of factors 
relating  to  Cenovus's  business,  including,  without  limitation,  fluctuations  in  Cenovus's  operating  and  financial 
results,  the  results  of  any  public  announcements  made  by  Cenovus  and  Cenovus's  failure  to  meet  analysts' 
expectations. In addition, the market price of the Cenovus common shares will significantly affect the market price 
of the Cenovus Warrants. This may result in significant volatility in the market price of the Cenovus Warrants and 
may negatively impact the value of the Cenovus Warrants. 

Holders of Cenovus Warrants will experience dilution if the combined company issues additional Cenovus  common 
shares in future offerings or under outstanding Cenovus Replacement Options and Cenovus Warrants. Such dilution 
may  adversely  affect  the  market  price  of  the  Cenovus  common  shares  and  may  negatively  impact  the  value  of 
Cenovus shareholders' investments. 

Risks Related to Significant Shareholders of Cenovus 

As  of  January  1,  2021,  Hutchison  Whampoa  Europe  Investments  S.à  r.l.  ("Hutchison"),  L.F.  Investments  S.à  r.l 
("L.F. Investments"), and ConocoPhillips own 15.7 percent, 11.5 percent and 10.3 percent of the common shares 
of Cenovus, respectively. Although each of Hutchison and L.F. Investments are subject to restrictions from selling 
or  transferring  Cenovus  common  shares  through  July 1, 2022  pursuant  to  the  terms  of  their  respective  standstill 
agreement  with  Cenovus,  the  sale  of  Cenovus  common  shares  held  by  any  of  Hutchison,  L.F.  Investments  or 
ConocoPhillips into the market, either through open market trades on the Toronto and New York stock exchanges, 
through  privately  arranged  block  trades,  or  pursuant  to  prospectus  offerings  made  in  accordance  with  the 
respective registration rights agreement that each of Hutchison, L.F. Investments and ConocoPhillips have entered 
into with Cenovus, or market perception regarding ConocoPhillips’ intention to sell Cenovus common shares, could 
adversely affect market prices for Cenovus common shares. 

While  Hutchison  and  L.F.  Investments  are  each  subject  to  certain  voting  covenants  pursuant  to  the  terms  of  a 
standstill agreement they each entered into with Cenovus in connection with the Arrangement, each of Hutchison 
and L.F. Investments may be able to impact certain matters requiring shareholder approval. 

Amount of Contingent Payments Payable to ConocoPhillips 

In connection with the Conoco Acquisition, we agreed to make contingent payments under certain circumstances. 
The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the 
five year  period  following  the  closing  of  the  Conoco  Acquisition  (May 17, 2017),  and  such  payments  may  be 
significant. In addition, in the event that such further payments are made, this could have an adverse impact on 
our reported results and other metrics. 

Tax Laws 

Income tax laws, other laws or government incentive programs may in the future be changed or interpreted in a 
manner that adversely affects Cenovus, its financial results and its shareholders. Tax authorities having jurisdiction 
over  Cenovus  may  disagree  with  the  manner  in  which  we  calculate  our  tax  liabilities  such  that  its  provision  for 
income  taxes  may  not  be  sufficient,  or  such  authorities  could  change  their  administrative  practices  to  Cenovus’s 
detriment  or  the  detriment  of  its  shareholders.  In  addition,  all  of  our  tax  filings  are  subject  to  audit  by  tax 
authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders. 

U.S. Tax Risk 

In  January 2021,  a  new  U.S.  presidential  administration  took  office.  The  new  administration  campaigned  on  a 
platform  that  included  several  tax  provisions  that  could  potentially  be  detrimental  to  Cenovus.  Those  provisions 
included an increase in the U.S. federal corporate tax rate and a new corporate minimum tax. While the ability of 
the new administration to enact tax laws is uncertain, it is possible that Cenovus’s U.S. operations will be subject 
to increased levels of U.S. federal taxation in the future. 

A  discussion  of  additional  risks,  should  they  arise  after  the  date  of  this  MD&A,  which  may  impact  our  business, 
prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found 
in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com.

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CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND 
ACCOUNTING POLICIES 

Management  is  required  to  make  estimates  and  assumptions  and  use  judgment  in  the  application  of  accounting 
policies that could have a significant impact on our financial results. Actual results may differ from estimates and 
those  differences  may  be  material.  The  estimates  and  assumptions  used  are  subject  to  updates  based  on 
experience  and  the  application  of  new  information.  Our  critical  accounting  policies  and  estimates  are  reviewed 
annually  by  the  Audit  Committee  of  the  Board.  Further  details  on  the  basis  of  preparation  and  our  significant 
accounting policies can be found in the notes to the Consolidated Financial Statements. 

Critical Judgments in Applying Accounting Policies 

Critical  judgments  are  those  judgments  made by Management  in  the  process of  applying  accounting policies  that 
have  the  most  significant  effect  on  the  amounts  recorded  in  our  annual  and  interim  Consolidated  Financial 
Statements. 

Joint Arrangements 

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus 
holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the 
assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation 
and  the  Company’s  share  of  the  assets,  liabilities,  revenues  and  expenses  are  recorded  in  the  Consolidated 
Financial Statements. 

In  determining  the  classification  of  its  joint  arrangements  under  IFRS  11,  ”Joint  Arrangements”,  the  Company 
considered the following: 

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(cid:120)

(cid:120)

(cid:120)

(cid:120)

The  intention  of  the  joint  arrangement  was  to  form  an  integrated  North  American  heavy  oil  business.  The 
integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets 
residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life. 
The partnership agreements require the partners (Cenovus and Phillips 66 or respective subsidiaries) to make 
contributions  if  funds  are  insufficient  to  meet  the  obligations  or  liabilities  of  the  partnerships.  The  past  and 
future  development  of  WRB  is  dependent  on  funding  from  the  partners  by  way  of  partnership  notes  payable 
and loans. 
The  WRB  working  interest relationship  is  operated  whereby  the  operating  partner  takes  product on  behalf  of 
the participants and is modified to account for the operating environment of the refining business.  
Phillips 66, as the operator, either directly or through wholly-owned subsidiaries, provide marketing services, 
purchase  necessary  feedstock,  and  arrange  for  transportation  and  storage  on  the  partners’  behalf  as  the 
agreements  prohibit  the  partnership  from  undertaking  these  roles  themselves.  In  addition,  the  partnership 
does not have employees and, as such, are not capable of performing these roles. 
In  the  arrangement,  output  is  taken  by  the  partners,  indicating  that  the  partners  have  the  rights  to  the 
economic benefits of the assets and the obligation for funding the liabilities of the arrangement. 

Exploration and Evaluation Assets 

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether 
it is likely that future economic benefit exists when activities have reached a stage where technical feasibility and 
commercial  viability  cannot  be  reasonably  determined.  Factors  such  as  drilling  results,  future  capital  programs, 
future operating expenses, as well as estimated reserves and resources are considered. In addition, Management 
uses  judgment  to  determine  when  E&E  assets  are  reclassified  to  PP&E.  In  making  this  determination,  various 
factors  are  considered,  including  the  existence  of  reserves,  and  whether  the  appropriate  approvals  have  been 
received from regulatory bodies and the Company’s internal approval process. 

Identification of CGUs 

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that 
are  largely  independent  of  cash  flows  from  other  assets  or  groups  of  assets.  The  classification  of  assets  and 
allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the 
classification include the integration between assets, shared infrastructures, the existence of common sales points, 
geography,  geologic  structure,  and  the  manner  in  which  Management  monitors  and  makes  decisions  about  its 
operations. The recoverability of the Company’s upstream, refining, crude-by-rail terminal, railcars, storage tanks, 
and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant 
impact on impairment losses and reversals. 

Determining the Lease Term 

In  determining  the  lease  term,  Management  considers  all  facts  and  circumstances  that  create  an  economic 
incentive  to  exercise  an  extension  option,  or  not  exercise  a  termination  option.  The  assessment  is  reviewed  if  a 
significant event or a significant change in circumstances occurs which affects this assessment. 

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Key Sources of Estimation Uncertainty 

Critical  accounting  estimates  are  those  estimates  that  require  Management  to  make  particularly  subjective  or 
complex  judgments  about  matters  that  are  inherently  uncertain.  Estimates  and  underlying  assumptions  are 
reviewed  on  an  ongoing  basis  and  any  revisions  to  accounting  estimates  are  recorded  in  the  period  in  which  the 
estimates are revised. The following are the key assumptions about the future and other key sources of estimation 
at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of 
assets and liabilities within the next financial year. 

In  March  2020,  the  World  Health  Organization  declared  a  global  pandemic  following  the  emergence  and  rapid 
spread  of  COVID-19.  The  outbreak  and  subsequent  measures  intended  to  limit  the  pandemic  contributed  to 
significant  declines  and  volatility  in  financial  markets.  The  pandemic  has  adversely  impacted  global  commercial 
activity, including significantly reducing worldwide demand for crude oil. 

The  full  extent  of  the  impact  of  COVID-19  on  the  Company’s  operations  and  future  financial  performance  is 
currently  unknown.  It  will  depend  on  future  developments  that  are  uncertain  and  unpredictable,  including  the 
duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any 
new  information  that  may  emerge  concerning  the  severity  of  the  virus.  These  uncertainties  may  persist  beyond 
when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with 
respect to the Company, its performance, and estimates and assumptions used by Management in the preparation 
of its financial results. 

The outbreak and current market conditions have increased the complexity of estimates and assumptions used to 
prepare the annual Consolidated Financial Statements, particularly related to recoverable amounts.  

In  addition,  the  evolving  worldwide  demand  for  energy  and  global  advancement  of  alternative  sources  of  energy 
that are not sourced from fossil fuels could result in a change in assumptions used in determining the recoverable 
amount  and  could  affect  the  carrying  value  of  the  related  assets.  The  timing  in  which  global  energy  markets 
transition from carbon-based sources to alternative energy is highly uncertain. 

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within 
the next financial year. 

Crude Oil and Natural Gas Reserves 

There  are  a  number  of  inherent  uncertainties  associated  with  estimating  crude  oil  and  natural  gas  reserves. 
Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of 
the  development  of  the  required  infrastructure  to  recover  the  hydrocarbons,  production  costs,  estimated  selling 
price  of  the  hydrocarbons  produced,  royalty  payments  and  taxes.  Changes  in  these  variables  could  significantly 
impact  the  reserves  estimates  which  would  affect  the  impairment  test  fair  value  less  costs  to  sell  and  DD&A 
expense  of  the  Company’s  crude  oil  and  natural  gas  assets  in  the  Oil  Sands  and  Conventional  segments.  The 
Company’s reserves are evaluated annually and reported to the Company by its IQREs. 

Recoverable Amounts 

Determining  the  recoverable  amount  of  a  CGU  or  an  individual  asset  requires  the  use  of  estimates  and 
assumptions,  which  are  subject  to  change  as  new  information  becomes  available.  For  the  Company’s  upstream 
assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and 
resources,  discount  rates,  future  development  and  operating  expenses.  Recoverable  amounts  for  the  Company’s 
refining  assets,  crude-by-rail  terminal  and  related  ROU  assets  use  assumptions  such  as  throughput,  forward 
commodity prices, market crack spreads, operating expenses, transportation capacity, future capital expenditures, 
supply and demand conditions and the terminal values used. Recoverable amounts for the Company’s real estate 
ROU  assets  use  assumptions  such  as  real  estate  market  conditions  which  includes  market  vacancy  rates  and 
sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes 
in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.  

2020 Upstream Impairments 

The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the 
determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop 
and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash 
flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. All reserves 
have been evaluated as at December 31, 2020 by the IQREs. 

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Crude Oil, NGLs and Natural Gas Prices 

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural 
gas reserves were: 

WTI (US$/barrel)(cid:3)
WCS (C$/barrel)(cid:3)
Edmonton C5+ (C$/barrel)(cid:3)
AECO (1) (C$/Mcf)(cid:3)

2021   
47.17       
44.63       
59.24       
2.88       

2022     
50.17       
48.18       
63.19       
2.80       

2023     
53.17       
52.10       
67.34       
2.71       

2024     
54.97       
54.10       
69.77       
2.75       

(1)

Assumes gas heating value of one million British thermal units per thousand cubic feet. 

Discount and Inflation Rates 

Average(cid:3)
Annual
Increase 
Thereafter
(percent)(cid:3)(cid:3)  
2.0 %  
2.0 %  
2.0 %  
2.0 %  

2025     
56.07       
55.19       
71.18       
2.80       

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based 
on  the  individual  characteristics  of  the  CGU,  and  other  economic  and  operating  factors.  Inflation  is  estimated  at 
approximately two percent. 

2020 Refining Impairments 

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated 
based  on  discounted  after-tax  cash  flows  using  forward  prices  and  cost  estimates.  Key  assumptions  in  the 
determination  of  future  cash  flows  included  forward  crude  oil  prices,  forward  crack  spreads,  future  capital 
expenditures,  operating  costs,  the  terminal  values  and  the  discount  rate.  Forward  crack  spreads  were  based  on 
quoted near-month contracts for WTI and spot prices for gasoline and diesel. 

Crude Oil and Forward Crack Spreads 

Forward  prices  are  based  on  Management’s  best  estimate  and  corroborated  with  third-party  data.  As  at 
September 30, 2020, the forward prices used to determine future cash flows were: 

(cid:120) WTI  forward  prices  used  for 2021  to 2022  ranged from  US$36.36 per  barrel  to  US$50.84 per  barrel  and 

2023 to 2025 ranged from US$49.66 per barrel to US$58.74 per barrel. 

(cid:120) WTI  to  West  Texas  Sour  differential  used  for  2021  to  2022  ranged  from  US$0.37 per  barrel  to 

(cid:120)

(cid:120)

US$1.73 per barrel and 2023 to 2025 ranged from US$1.21 per barrel to US$1.81 per barrel. 
Group 3  forward  market  crack  spread  used  for  2021  to  2022  ranged  from  US$11.56 per  barrel  to 
US$13.23 per barrel and 2023 to 2025 ranged from US$11.79 per barrel to US$16.58 per barrel. 
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to 
year 2035. 

Discount and Inflation Rates 

Discounted  future  cash  flows  are  determined  by  applying  a  discount  rate  of  10 percent  based  on  the  individual 
characteristics of the CGU, and other economic and operating factors. 

Decommissioning Costs 

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining 
assets  and  crude-by-rail  terminal  at  the  end  of  their  economic  lives.  Management  uses  judgment  to  assess  the 
existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and 
cost estimates may change in response to numerous factors including changes in legal requirements, technological 
advances,  inflation  and  the  timing  of  expected  decommissioning  and  restoration.  In  addition,  Management 
determines  the  appropriate  discount rate  at  the  end of  each  reporting period.  This  discount  rate,  which  is  credit-
adjusted,  is  used  to  determine  the  present  value  of  the  estimated  future  cash  outflows  required  to  settle  the 
obligation and may change in response to numerous market factors.  

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination 

The  fair  value  of  assets  acquired  and  liabilities  assumed  in  a  business  combination,  including  contingent 
consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation 
techniques are applied for measuring fair value including market comparables and discounted cash flows which rely 
on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility, 
Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the 
carrying value of the net assets.  

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Income Tax Provisions  

Tax  regulations  and  legislation  and  the  interpretations  thereof  in  the  various  jurisdictions  in  which  Cenovus 
operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes 
are subject to measurement uncertainty.  

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences 
will  be  recoverable  in  future  periods.  The  recoverability  assessment  involves  a  significant  amount  of  estimation 
including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable 
earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax 
laws.  There  are  some  transactions  for  which  the  ultimate  tax  determination  is  uncertain.  To  the  extent  that 
assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated 
Financial Statements of future periods. 

Changes in Accounting Policies 

There  were  no  new  or  amended  accounting  standards  or  interpretations  adopted  during  the  year  ended 
December 31, 2020. 

New Accounting Standards and Interpretations not yet Adopted 

There  are  new  standards,  amendments  to  accounting  standards  and  interpretations  that  are  effective  for  annual 
periods  beginning  or  after  January 1, 2021  and  have  not  been  applied  in  preparing  the  Consolidated  Financial 
Statements for the year ended December 31, 2020. These standards and interpretations are not expected to have 
a material impact on our Consolidated Financial Statements. The standard applicable to us is as follows and will be 
adopted on its respective effective date: 

Interest Rate Benchmark Reform 

On  August 27, 2020,  the  IASB  published  Interest  Rate  Benchmark  Reform  –  Phase  2  (Amendments  to  IFRS  9, 
“Financial  Instruments”,  IAS 39,  “Financial  Instruments:  Recognition  and  Measurement”,  IFRS  7,  “Financial 
Instruments:  Disclosures”,  IFRS  4,  “Insurance  Contracts”  and  IFRS  16)  (“IBOR  Phase  2  Amendments”),  which 
provides clarity on the changes after the reform of an interest rate benchmark. The amendments are effective for 
annual  periods  beginning  on  or  after  January 1, 2021,  with  early  application  permitted.  The  IBOR  Phase  2 
Amendments  primarily  relate  to  the  modification  of  financial  instruments,  allowing  for  a  practical  expedient  for 
modifications  required  by  the  reform.  The  practical  expedient  for  modifications  is  accounted  for  by  updating  the 
effective  interest  rate  without  modification  of  the  financial  instrument  and  is  subject  to  satisfying  all  qualifying 
criteria. We expect the IBOR Phase 2 Amendments will not have a significant impact on our Consolidated Financial 
Statements. 

CONTROL ENVIRONMENT 

Management,  including  our  President  &  Chief  Executive  Officer  and  Executive  Vice-President  &  Chief  Financial 
Officer,  assessed  the  design  and  effectiveness  of  ICFR  and  disclosure  controls  and  procedures  (“DC&P”)  as  at 
December 31, 2020.  In making  its  assessment,  Management  used  the Committee of  Sponsoring Organizations  of 
the  Treadway  Commission  Framework  in  Internal  Control  –  Integrated  Framework  (2013)  to  evaluate  the  design 
and  effectiveness  of  ICFR.  Based  on  our  evaluation,  Management  has  concluded  that  both  ICFR  and  DC&P  were 
effective as at December 31, 2020. 

The  effectiveness  of  our  ICFR  was  audited  as  at  December 31, 2020  by  PricewaterhouseCoopers  LLP,  an 
independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public 
Accounting  Firm,  which  is  included  in  our  audited  Consolidated  Financial  Statements  for  the  year  ended 
December 31, 2020. 

Internal  control  systems,  no matter  how well  designed,  have  inherent  limitations.  Therefore,  even  those  systems 
determined to be effective can provide only reasonable assurance with respect to financial statement preparation 
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that 
controls  may  become  inadequate  because  of  changes  in  conditions,  or  that  the  degree  of  compliance  with  the 
policies or procedures may deteriorate. 

SUSTAINABILITY 

At Cenovus, sustainability is essential to the way we do business. It means creating a safe and inclusive workplace, 
partnering with local and Indigenous communities, and innovating to minimize our impact on the environment. We 
believe  striking  the  right  balance  among  environmental,  economic  and  social  considerations  creates  long-term 
value. 

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To support our sustainability performance, our Sustainability Policy guides our activities in the areas of: Leadership 
and  Governance,  People,  Environment,  Stakeholder  Engagement,  Indigenous  Engagement,  and  Community 
Involvement and Investment. 

Cenovus is committed to world-class safety performance and ESG leadership. This includes ambitious ESG targets, 
robust management systems and transparent performance reporting. The Company will continue working to earn 
its position as a global energy supplier of choice by advancing clean technology and reducing emissions intensity. 
This  includes  the  ambition  of  achieving  net  zero  emissions  by  2050.  Cenovus  will  also  continue  building  upon  its 
strong local community relationships, with a focus on Indigenous economic reconciliation. 

The  targets  Cenovus  released  in  2020 for  its  key  ESG  focus  areas  are  the product of  robust  processes  to  ensure 
alignment  with  the  Company’s  business  plan  and  strategy.  Cenovus  remains  committed  to  pursuing  ESG  targets 
now  that  it  has  completed  the  Arrangement  with  Husky  and  will  undertake  a  similarly  thorough  analysis  before 
setting meaningful targets for the new portfolio. Once that work is complete in 2021 and approved by the Board, 
the new targets and plans to achieve them will be disclosed.  

We published our 2019 ESG report in July 2020 to report on our management efforts and performance across the 
areas  within  our  Sustainability  Policy  that  are  important  to  our  stakeholders.  Our  ESG  report  is  available  on  our 
website at cenovus.com. 

OUTLOOK 

We expect 2021 to be a challenging time for our industry and the global economy in general due to the impacts of 
COVID-19.  With  the  continued  uncertainty  around  COVID-19  and  the scale  of resurgence of COVID-19  cases, we 
anticipate crude oil and refined products demand to be volatile in 2021 with recovery dependent on the success of 
economic  relaunches.  We  anticipate  that  an  increase  in  demand  for  refined  products  will  be  an  early  indicator  of 
recovery. Our top priority will be to maintain the strength of our balance sheet. We have ample liquidity, top-tier 
assets which we are able to effectively manage to respond to price signals, one of the lowest cost structures in the 
industry and have demonstrated our ability to reduce discretionary capital, all of which should allow us to continue 
to adapt to these challenges. 

We  continue  to  monitor  the  overall  market  dynamics  to  assess  how  we  manage  our  Upstream  production  levels. 
Our  assets  can  respond  to  market  signals  and  ramp  up  production  accordingly.  Our  decisions  around  production 
levels and refinery crude run rates will be focused on maximizing the value we receive for our products. We expect 
our  2021  annual  Upstream  production  to  average  between  730,000 BOE  per  day  and  780,000 BOE  per  day  and 
total Downstream throughput of 500,000 barrels per day to 550,000 barrels per day. 

With  the  close  of  the  Arrangement,  we  estimated  approximately  $600 million  in  annual  corporate  and  operating 
synergies  and  approximately  $600 million  in  capital  allocation  synergies  to  be  achievable.  The  2021  budget 
positions us to achieve about $400 million of the estimated annual corporate and operating synergies and all of the 
estimated  capital  allocation  synergies  this  year.  Over  the  longer-term,  we  anticipate  additional  cost  savings  and 
margin enhancements based on further physical  integration of upstream assets with downstream assets, which is 
expected  to  shorten  the  value  chain  and  reduce  condensate  costs  associated  with  heavy  oil  transportation.  We 
continue  to  look  for  additional  opportunities  to  reduce  operating,  capital,  and  G&A  spending  and  increase  our 
margins through strong operating performance and cost leadership while focusing on safe and reliable operations. 

Given the challenges faced by our industry and the global economy and the closing of the Arrangement with Husky, 
achieving  cumulative  free funds flow of  approximately $11 billion  through 2024,  as  disclosed  in  our  news release 
dated October 2, 2019, is under evaluation. We expect to develop a new five-year business plan for the Company 
later this year. 

The following outlook commentary is focused on the next twelve months. 

Commodity Prices Underlying our Financial Results 

Our crude oil pricing outlook is influenced by the following: 

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(cid:120) We  expect  the  general  outlook  for  light  crude  oil  prices  will  be  tied  primarily  to  the  supply  and  demand 
response  to  the  current  uncertain  price  environment,  the  impact  of  oversupply,  and  global  demand  impacts 
amid COVID-19 concerns; 
Crude  oil  and  refined  product  price  volatility  is  expected  to  continue  due  to  crude  demand  destruction  as  a 
result of COVID-19; 
The effectiveness and successful distribution of vaccines will be key to the pace of oil demand recovery; 
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts; 

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(cid:120) We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply cuts 
are  sustained,  the  potential  start-up  of  Enbridge  Inc.’s  Line  3  Replacement  Program,  the  completion  of  the 
Trans Mountain Expansion project, and the level of crude-by-rail activity; and 

(cid:120) We expect refining market crack spreads in 2021 to remain weak relative to normal as a result of significantly 
reduced refined  products  demand due  to  COVID-19,  particularly  in  the  first  half of  the  year. Refining  market 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:25)(cid:22)

 
 
crack  spreads  are  expected  to  continue  to  fluctuate,  adjusting  for  seasonal  trends  and  refining  run  cuts  in 
North America. 

Natural  gas  and  NGLs production  associated with  our  Conventional  assets provide  improved  upstream  integration 
for the fuel, solvent and blending requirements at our Oil Sands operations. 

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Historic Prices and Forward Spot Prices as at December 31, 2020

Brent

WTI

C5 @ Edmonton

WCS at Hardisty (C$/bbl)

WCS at Hardisty

Q1 2020

Q2 2020

Q3 2020

Q4 2020

Q1 2021F

Q2 2021F

Q3 2021F

Q4 2021F

Historic Prices and Forward Spot Prices as at December 31, 2020

Chicago

Natural gas prices have been challenged due to weaker demand as a result of COVID-19, but the forward curve is 
showing that the market expects AECO prices to rebound into 2021. Production declines from both associated gas 
and dry gas, along with rebounding U.S. demand and liquified natural gas exports, should tighten North American 
gas fundamentals in 2021 and result in stronger prices than 2020 on an annual basis. 

We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve 
Board  and  the  Bank  of  Canada  raise  or  lower  benchmark  lending  rates  relative  to  each  other,  and  emerging 
macro-economic  factors.  The  Bank  of  Canada  lowered  its  benchmark  lending  rate  twice  in  2020  to  address  the 
impacts of COVID-19 and is expected to continue to hold the interest rate until 2023. 

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Q4 2020

Q1 2021F

Q2 2021F

Q3 2021F

Q4 2021F

Historic Prices and Forward Spot Prices at December 31, 2020

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Historic Prices and Forward Spot Prices as at December 31, 2020

US$/C$1

Our upstream crude oil production and most of our downstream refined products are exposed to movements in the 
WTI  crude  oil  price.  With  the  closing  of  the  Arrangement,  our  exposure  has  grown  on  both  the  upstream  and 
downstream sides of our business. 

Our refining  capacity  is  now  focused  in  the  U.S. Midwest  along  with  smaller  exposures  to  the  USGC  and  Alberta. 
Cenovus is exposed to the crack spread in all of these markets. 

Our  exposure  to  crude  differentials  includes  light-heavy  and  light-medium  price  differentials.  Light-medium  price 
differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have refining 
capacity, and to a lesser degree in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is 
composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as 
the Alberta differential, which is subject to transportation constraints. While we expect to see volatility in crude oil 
prices, we have the ability to partially mitigate the impact of crude oil and refined product prices and differentials 
through the following: 

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Transportation  commitments  and  arrangements  –  using  our  existing  firm  service  commitments  for  takeaway 
capacity  and supporting  transportation  projects  that  move crude  oil  from  our  production  areas  to  consuming 
markets, including tidewater markets; 
Integration  –  having  heavy  oil  refining  capacity  capable  of  processing  Canadian  heavy  oil.  From  a  value 
perspective,  our  refining  business  positions  us  to  capture  value  from  both  the  WTI-WCS  differential  for 
Canadian crude oil as well as from spreads on refined products; 
Marketing  agreements  –  limiting  the  impact  of  fluctuations  in  upstream  crude  oil  prices  by  entering  into 
physical supply transactions with fixed price components directly with refiners;  
Dynamic  storage  –  our  ability  to  use  the  significant  storage  capacity  in  our  oil  sands  reservoirs  provides  us 
flexibility on timing of production and sales of our inventory. We will continue to manage our production rates 

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in  response  to  pipeline  capacity  constraints,  voluntary  and  mandated  production  curtailments  and  crude  oil 
price differentials;  
Traditional crude oil storage tanks in various geographic locations; and 
Financial  hedge  transactions  –  limiting  the  impact  of  fluctuations  in  crude  oil  and  refined  product  prices  by 
entering into financial transactions related to our exposures. 

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Key Priorities For 2021 

We  recently  developed  and  shared  updated  guidance  on  January 28, 2021.  In  the  current  commodity  price 
environment,  we  continue  to  focus  on  maintaining  balance  sheet  strength  and  liquidity.  Enhancing  our  financial 
resilience  and  flexibility  while  continuing  to  deliver  safe  and  reliable  operations  will  continue  to  be  a  top  priority 
during these uncertain times. 

Our  corporate  strategy  focuses  on  maximizing  shareholder  value  through  cost  leadership  and  realizing  the  best 
margins for our products. We expect to remain focused on disciplined capital investment allocation among the full 
suite of assets for the Company, and continued cost leadership to achieve margin improvement and environmental 
benefits. 

Safe and Reliable Operations 

Safe and reliable operations are our number one priority. Safety continues to be a core value that informs all of the 
decisions  we  make.  We  will  continue  to  promote  a  safety  culture  in  all  aspects  of  our  work  and  use  a  variety  of 
programs to keep safety top of mind at all times. 

Capture Synergies and Maintain Cost Leadership 

The  combination  with  Husky  will  further  improve  cost  structure.  The  2021  budget  positions  us  to  achieve  about 
$400 million  of  annual  corporate  and  operating  synergies  and  an  estimated  $600 million  in  capital  allocation 
synergies in 2021. 

The annual corporate and operating cost synergies  is well underway and is expected through the consolidation of 
information technology systems, eliminating other service overlaps, and through reductions to combined workforce 
and corporate overhead costs. Immediate efficiencies are also expected by implementing best practices from each 
company,  including  applying  Cenovus’s  operating  expertise  to  Husky’s  oil  sands  assets,  leveraging  the  increased 
portfolio’s scale, and pursuing commercial and contract-related efficiencies on transportation, storage, and logistics 
marketing and blending opportunities. 

Over  the  longer  term,  we  anticipate  additional  cost  savings  and  margin  enhancements  based  on  further  physical 
integration.  The  integration  of  Cenovus’s  upstream  assets  with  Husky’s  downstream  and  transportation,  storage, 
and logistics portfolio is expected to shorten the value chain and reduce condensate costs associated with heavy oil 
transportation over the longer term. 

We continue to achieve improvements in our operating and G&A costs. In 2021, we will continue to look for ways 
to improve efficiencies across Cenovus to drive incremental capital, operating and G&A cost reductions. 

Disciplined Capital Investment 

We released our 2021 guidance on January 28, 2021 for the Company and anticipate our total capital expenditures 
to  be  between  $2.3 billion  and  $2.7 billion,  including  sustaining  capital  of  approximately  $2.1  billion  and  costs  of 
$520 million  to  $570 million  (excluding  insurance  proceeds)  for  the Superior  Refinery rebuild.  We will  continue  to 
be disciplined with our capital. The 2021 guidance is available on our website at cenovus.com. 

Oil  Sands  capital  investment  for  2021,  including  Christina  Lake,  Foster  Creek,  Sunrise  and  Tucker  oil  sands 
projects,  as  well  as  the  Lloydminster  thermal  projects  and  Cold  and  Enhanced  Oil  Recovery,  is  forecast  to  be 
between $850 million and $950 million. Oil Sands capital is primarily for sustaining production focused at Christina 
Lake,  Foster Creek  and  the  Lloydminster  thermal  assets.  Our  Oil  Sands production  is  expected  to  range  between 
524,000 and 586,000 barrels per day for 2021. 

Our  Conventional  segment  capital  investment  is  forecasted  to  be  between  $170 million  and  $210  million.  This 
includes  economic  development  in  various  plays  to  generate  strong  returns,  improve  underlying  cost  structures 
through volume enhancement and offset declines. Production is expected to range between 132,000 and 151,000 
BOE per day for 2021. 

Our Offshore segment, including operations and exploration prospects in the Asia Pacific region and Atlantic Canada 
region,  capital  investment  is  expected  to  be  between  $200  million  and  $250  million.  This  capital  spend  includes 
planned  wells  in  China  and  continued  development  of  the  fields  in  the  MDA-MBH  and  MDK  fields  in  the  Madura 
Strait, as well as baseline preservation capital for the West White Rose Project, which has been deferred for 2021 
while  we  continue  to  evaluate  options.  Working  Interest  production  from  our  Offshore  segment  is  expected  to 
range between 61,000 and 72,000 barrels per day. 

In 2021, the Downstream segment, composed of Canadian and U.S. Manufacturing and Retail, we expect to invest 
between  $1.0 billion  and  $1.2 billion  and  will  continue  to  focus  on  refining  reliability  and  maintenance,  safety 
projects  and  high-return  optimization  opportunities  as  well  as  between  $520 million  and  $570 million  for  the 
Superior  rebuild  project.  The  rebuild  project  will  further  improve  our  integration  while  reducing  the  Company’s 

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exposure  to  WTI-WCS  location  differentials.  Downstream  throughput  is  expected  to  be  in  the  range  of  500,000 
barrels per day to 550,000 barrels per day.  

We expect to invest between $75 million and $100 million of corporate capital in 2021 across the Company. 

In 2021, we plan to achieve capital allocation synergies across the Company by optimizing sustaining capital to the 
highest quality assets while maintaining safe and reliable operations across our portfolio. 

As at December 31, 2020, our Net Debt position was $7.2 billion. The estimated incremental annual free funds flow 
from  identified  near-term  synergies  with  the  closing  of  the  Arrangement  is  expected  to  accelerate  balance  sheet 
deleveraging. Through a combination of cash on hand and available capacity on our committed credit facilities and 
demand facilities, we have approximately $10.4 billion of liquidity under the combined company. In addition, WRB 
has available capacity of approximately $70 million, for Cenovus’s proportionate share, on its demand facilities. We 
will continue to focus on allocating free funds flow to reduce Net Debt to less than $10 billion and target a longer-
term Net Debt level at or below $8 billion. 

Maintaining Financial Resilience 

We have top-tier assets, one of the lowest cost structures in our industry and a strong balance sheet, all of which 
position us to withstand the challenges of the current market environment. Our capital planning process is flexible, 
and spending can be reduced in response to commodity prices and other economic factors so we can maintain our 
financial resilience. The Arrangement removes a significant amount of exposure to WTI-WCS location differentials 
and reduces commodity price volatility. Our financial framework and flexible business plan allow multiple options to 
manage  our  balance  sheet.  We  will  continue  to  assess  our  spending  plans  on  a  regular  basis  while  closely 
monitoring crude oil prices in 2021. 

The  Company’s  priority  will  be  to  maximize  free  funds  flow  by  focusing  investments  on  sustaining  capital 
expenditures which will position us to direct available free funds flow to the balance sheet and allow us to achieve a 
Net  Debt  target  of  $10  billion  which  approximates  a  Net  Debt  to  Adjusted  EBITDA  target  of  less  than  2.0 times, 
without the need for asset dispositions. 

The low funds flow volatility, breakeven prices and corporate sustaining costs supports an investment grade profile 
and lower cost of capital through the commodity price cycle. We remain committed to maintaining our investment 
grade credit ratings. 

Shareholder Returns 

After  achieving  our  balance  sheet  objectives,  the  Company’s  free  funds  profile  is  expected  to  enable  sustainable 
growth  in  shareholder  distributions.  The  Board  declared  a  first  quarter  dividend  of  $0.0175 per common share, 
payable  on  March 31, 2021,  to  common  shareholder  of  record  as  of  March 15, 2021.  The  Board  declared  a  first 
quarter  dividend  on  the  Series  1,  2,  3,  5,  and  7  preferred  shares,  payable  on  March 31, 2021,  in  the  amount  of 
$8 million. 

ESG 

We  are  committed  to  ESG  leadership.  This  includes  ambitious  ESG  targets,  robust  management  systems  and 
transparent  performance  reporting.  The  Company  will  continue  working  to  earn  its  position  as  a  global  energy 
supplier  of  choice  by  advancing  clean  technology  and  reducing  emissions  intensity.  This  includes  the  ambition  of 
achieving  net  zero  emissions  by  2050.  We  will  also  continue  building  upon  our  strong  local  community 
relationships, with a focus on Indigenous economic reconciliation. 

The  targets  Cenovus  released  in  2020 for  its  key  ESG  focus  areas  are  the product of  robust  processes  to  ensure 
alignment with the company’s business plan and strategy. We remain committed to pursuing ESG targets now that 
we  have  completed  the  Arrangement  with  Husky  and  will  undertake  a  similarly  thorough  analysis  before  setting 
meaningful targets for the new portfolio. Once that work is complete in 2021 and approved by the Board, the new 
targets and plans to achieve them will be disclosed. 

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(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:50)(cid:41)(cid:3)(cid:44)(cid:49)(cid:39)(cid:40)(cid:51)(cid:40)(cid:49)(cid:39)(cid:40)(cid:49)(cid:55)(cid:3)(cid:53)(cid:40)(cid:42)(cid:44)(cid:54)(cid:55)(cid:40)(cid:53)(cid:40)(cid:39)(cid:3)(cid:51)(cid:56)(cid:37)(cid:47)(cid:44)(cid:38)(cid:3)(cid:36)(cid:38)(cid:38)(cid:50)(cid:56)(cid:49)(cid:55)(cid:44)(cid:49)(cid:42)(cid:3)(cid:41)(cid:44)(cid:53)(cid:48)

(cid:38)(cid:50)(cid:49)(cid:54)(cid:50)(cid:47)(cid:44)(cid:39)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:40)(cid:36)(cid:53)(cid:49)(cid:44)(cid:49)(cid:42)(cid:54)(cid:3)(cid:11)(cid:47)(cid:50)(cid:54)(cid:54)(cid:12)

(cid:38)(cid:50)(cid:49)(cid:54)(cid:50)(cid:47)(cid:44)(cid:39)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:38)(cid:50)(cid:48)(cid:51)(cid:53)(cid:40)(cid:43)(cid:40)(cid:49)(cid:54)(cid:44)(cid:57)(cid:40)(cid:3)(cid:44)(cid:49)(cid:38)(cid:50)(cid:48)(cid:40)(cid:3)(cid:11)(cid:47)(cid:50)(cid:54)(cid:54)(cid:12)

(cid:38)(cid:50)(cid:49)(cid:54)(cid:50)(cid:47)(cid:44)(cid:39)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:37)(cid:36)(cid:47)(cid:36)(cid:49)(cid:38)(cid:40)(cid:3)(cid:54)(cid:43)(cid:40)(cid:40)(cid:55)(cid:54)

(cid:38)(cid:50)(cid:49)(cid:54)(cid:50)(cid:47)(cid:44)(cid:39)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:54)(cid:43)(cid:36)(cid:53)(cid:40)(cid:43)(cid:50)(cid:47)(cid:39)(cid:40)(cid:53)(cid:54)(cid:112)(cid:3)(cid:40)(cid:52)(cid:56)(cid:44)(cid:55)(cid:60)

(cid:38)(cid:50)(cid:49)(cid:54)(cid:50)(cid:47)(cid:44)(cid:39)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:38)(cid:36)(cid:54)(cid:43)(cid:3)(cid:41)(cid:47)(cid:50)(cid:58)(cid:54)

(cid:49)(cid:50)(cid:55)(cid:40)(cid:54)(cid:3)(cid:55)(cid:50)(cid:3)(cid:38)(cid:50)(cid:49)(cid:54)(cid:50)(cid:47)(cid:44)(cid:39)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:41)(cid:44)(cid:49)(cid:36)(cid:49)(cid:38)(cid:44)(cid:36)(cid:47)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)

(cid:26)(cid:27)(cid:3)

(cid:27)(cid:20)(cid:3)
(cid:3)

(cid:27)(cid:20)(cid:3)

(cid:20)(cid:17)(cid:3)(cid:39)(cid:40)(cid:54)(cid:38)(cid:53)(cid:44)(cid:51)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:50)(cid:41)(cid:3)(cid:37)(cid:56)(cid:54)(cid:44)(cid:49)(cid:40)(cid:54)(cid:54)(cid:3) 
  AND SEGMENTED DISCLOSURES

(cid:21)(cid:17)(cid:3)(cid:37)(cid:36)(cid:54)(cid:44)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:51)(cid:53)(cid:40)(cid:51)(cid:36)(cid:53)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3) 
(cid:3) (cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:3)(cid:50)(cid:41)(cid:3)(cid:38)(cid:50)(cid:48)(cid:51)(cid:47)(cid:44)(cid:36)(cid:49)(cid:38)(cid:40)

(cid:22)(cid:17)(cid:3)(cid:54)(cid:56)(cid:48)(cid:48)(cid:36)(cid:53)(cid:60)(cid:3)(cid:50)(cid:41)(cid:3)(cid:54)(cid:44)(cid:42)(cid:49)(cid:44)(cid:41)(cid:44)(cid:38)(cid:36)(cid:49)(cid:55)(cid:3) 
  ACCOUNTING POLICIES

(cid:20)(cid:19)(cid:21)(cid:3) (cid:21)(cid:19)(cid:17)(cid:3)(cid:50)(cid:55)(cid:43)(cid:40)(cid:53)(cid:3)(cid:36)(cid:54)(cid:54)(cid:40)(cid:55)(cid:54)

(cid:20)(cid:19)(cid:21)(cid:3) (cid:21)(cid:20)(cid:17)(cid:3)(cid:42)(cid:50)(cid:50)(cid:39)(cid:58)(cid:44)(cid:47)(cid:47)

(cid:20)(cid:19)(cid:21)(cid:3) (cid:21)(cid:21)(cid:17)(cid:3)(cid:36)(cid:38)(cid:38)(cid:50)(cid:56)(cid:49)(cid:55)(cid:54)(cid:3)(cid:51)(cid:36)(cid:60)(cid:36)(cid:37)(cid:47)(cid:40)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:36)(cid:38)(cid:38)(cid:53)(cid:56)(cid:40)(cid:39)(cid:3)(cid:47)(cid:44)(cid:36)(cid:37)(cid:44)(cid:47)(cid:44)(cid:55)(cid:44)(cid:40)(cid:54)

(cid:20)(cid:19)(cid:21)(cid:3) (cid:21)(cid:22)(cid:17)(cid:3)(cid:54)(cid:43)(cid:50)(cid:53)(cid:55)(cid:16)(cid:55)(cid:40)(cid:53)(cid:48)(cid:3)(cid:37)(cid:50)(cid:53)(cid:53)(cid:50)(cid:58)(cid:44)(cid:49)(cid:42)(cid:54)

(cid:20)(cid:19)(cid:22)(cid:3) (cid:21)(cid:23)(cid:17)(cid:3)(cid:47)(cid:50)(cid:49)(cid:42)(cid:16)(cid:55)(cid:40)(cid:53)(cid:48)(cid:3)(cid:39)(cid:40)(cid:37)(cid:55)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:38)(cid:36)(cid:51)(cid:44)(cid:55)(cid:36)(cid:47)(cid:3)(cid:54)(cid:55)(cid:53)(cid:56)(cid:38)(cid:55)(cid:56)(cid:53)(cid:40)

(cid:28)(cid:19)(cid:3)
(cid:3)

(cid:23)(cid:17)(cid:3)(cid:38)(cid:53)(cid:44)(cid:55)(cid:44)(cid:38)(cid:36)(cid:47)(cid:3)(cid:36)(cid:38)(cid:38)(cid:50)(cid:56)(cid:49)(cid:55)(cid:44)(cid:49)(cid:42)(cid:3)(cid:45)(cid:56)(cid:39)(cid:42)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3) 
(cid:3) (cid:46)(cid:40)(cid:60)(cid:3)(cid:54)(cid:50)(cid:56)(cid:53)(cid:38)(cid:40)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:40)(cid:54)(cid:55)(cid:44)(cid:48)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:56)(cid:49)(cid:38)(cid:40)(cid:53)(cid:55)(cid:36)(cid:44)(cid:49)(cid:55)(cid:60)

(cid:28)(cid:21)(cid:3)

(cid:24)(cid:17)(cid:3)(cid:42)(cid:40)(cid:49)(cid:40)(cid:53)(cid:36)(cid:47)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:36)(cid:39)(cid:48)(cid:44)(cid:49)(cid:44)(cid:54)(cid:55)(cid:53)(cid:36)(cid:55)(cid:44)(cid:57)(cid:40)

(cid:28)(cid:21)(cid:3)

(cid:25)(cid:17)(cid:3)(cid:41)(cid:44)(cid:49)(cid:36)(cid:49)(cid:38)(cid:40)(cid:3)(cid:38)(cid:50)(cid:54)(cid:55)(cid:54)(cid:3)

(cid:28)(cid:21)(cid:3)

(cid:26)(cid:17)(cid:3)(cid:41)(cid:50)(cid:53)(cid:40)(cid:44)(cid:42)(cid:49)(cid:3)(cid:40)(cid:59)(cid:38)(cid:43)(cid:36)(cid:49)(cid:42)(cid:40)(cid:3)(cid:11)(cid:42)(cid:36)(cid:44)(cid:49)(cid:12)(cid:3)(cid:47)(cid:50)(cid:54)(cid:54)(cid:15)(cid:3)(cid:49)(cid:40)(cid:55)

(cid:28)(cid:21)(cid:3)

(cid:27)(cid:17)(cid:3)(cid:39)(cid:44)(cid:57)(cid:40)(cid:54)(cid:55)(cid:44)(cid:55)(cid:56)(cid:53)(cid:40)(cid:54)

(cid:20)(cid:19)(cid:24)(cid:3) (cid:21)(cid:24)(cid:17)(cid:3)(cid:47)(cid:40)(cid:36)(cid:54)(cid:40)(cid:3)(cid:47)(cid:44)(cid:36)(cid:37)(cid:44)(cid:47)(cid:44)(cid:55)(cid:44)(cid:40)(cid:54)(cid:3)

(cid:20)(cid:19)(cid:24)(cid:3) (cid:21)(cid:25)(cid:17)(cid:3)(cid:38)(cid:50)(cid:49)(cid:55)(cid:44)(cid:49)(cid:42)(cid:40)(cid:49)(cid:55)(cid:3)(cid:51)(cid:36)(cid:60)(cid:48)(cid:40)(cid:49)(cid:55)

(cid:20)(cid:19)(cid:25)(cid:3) (cid:21)(cid:26)(cid:17)(cid:3)(cid:39)(cid:40)(cid:38)(cid:50)(cid:48)(cid:48)(cid:44)(cid:54)(cid:54)(cid:44)(cid:50)(cid:49)(cid:44)(cid:49)(cid:42)(cid:3)(cid:47)(cid:44)(cid:36)(cid:37)(cid:44)(cid:47)(cid:44)(cid:55)(cid:44)(cid:40)(cid:54)

(cid:20)(cid:19)(cid:25)(cid:3) (cid:21)(cid:27)(cid:17)(cid:3)(cid:50)(cid:55)(cid:43)(cid:40)(cid:53)(cid:3)(cid:47)(cid:44)(cid:36)(cid:37)(cid:44)(cid:47)(cid:44)(cid:55)(cid:44)(cid:40)(cid:54)

(cid:20)(cid:19)(cid:26)(cid:3) (cid:21)(cid:28)(cid:17)(cid:3)(cid:51)(cid:40)(cid:49)(cid:54)(cid:44)(cid:50)(cid:49)(cid:54)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:50)(cid:55)(cid:43)(cid:40)(cid:53)(cid:3) 
(cid:3)

(cid:3) (cid:51)(cid:50)(cid:54)(cid:55)(cid:16)(cid:40)(cid:48)(cid:51)(cid:47)(cid:50)(cid:60)(cid:48)(cid:40)(cid:49)(cid:55)(cid:3)(cid:37)(cid:40)(cid:49)(cid:40)(cid:41)(cid:44)(cid:55)(cid:54)

(cid:28)(cid:22)(cid:3)

(cid:28)(cid:17)(cid:3)(cid:50)(cid:55)(cid:43)(cid:40)(cid:53)(cid:3)(cid:11)(cid:44)(cid:49)(cid:38)(cid:50)(cid:48)(cid:40)(cid:12)(cid:3)(cid:47)(cid:50)(cid:54)(cid:54)(cid:15)(cid:3)(cid:49)(cid:40)(cid:55)

(cid:20)(cid:19)(cid:28)(cid:3) (cid:22)(cid:19)(cid:17)(cid:3)(cid:54)(cid:43)(cid:36)(cid:53)(cid:40)(cid:3)(cid:38)(cid:36)(cid:51)(cid:44)(cid:55)(cid:36)(cid:47)

(cid:28)(cid:22)(cid:3)

(cid:20)(cid:19)(cid:17)(cid:3)(cid:44)(cid:48)(cid:51)(cid:36)(cid:44)(cid:53)(cid:48)(cid:40)(cid:49)(cid:55)(cid:3)(cid:38)(cid:43)(cid:36)(cid:53)(cid:42)(cid:40)(cid:54)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:53)(cid:40)(cid:57)(cid:40)(cid:53)(cid:54)(cid:36)(cid:47)(cid:54)

(cid:28)(cid:25)(cid:3)

(cid:20)(cid:20)(cid:17)(cid:3)(cid:39)(cid:44)(cid:54)(cid:38)(cid:50)(cid:49)(cid:55)(cid:44)(cid:49)(cid:56)(cid:40)(cid:39)(cid:3)(cid:50)(cid:51)(cid:40)(cid:53)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:54)

(cid:20)(cid:20)(cid:19)(cid:3) (cid:22)(cid:20)(cid:17)(cid:3)(cid:36)(cid:38)(cid:38)(cid:56)(cid:48)(cid:56)(cid:47)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:50)(cid:55)(cid:43)(cid:40)(cid:53)(cid:3) 
(cid:3)

(cid:3) (cid:38)(cid:50)(cid:48)(cid:51)(cid:53)(cid:40)(cid:43)(cid:40)(cid:49)(cid:54)(cid:44)(cid:57)(cid:40)(cid:3)(cid:44)(cid:49)(cid:38)(cid:50)(cid:48)(cid:40)(cid:3)(cid:11)(cid:47)(cid:50)(cid:54)(cid:54)(cid:12)

(cid:28)(cid:25)(cid:3)

(cid:20)(cid:21)(cid:17)(cid:3)(cid:44)(cid:49)(cid:38)(cid:50)(cid:48)(cid:40)(cid:3)(cid:55)(cid:36)(cid:59)(cid:40)(cid:54)

(cid:28)(cid:27)(cid:3)

(cid:20)(cid:22)(cid:17)(cid:3)(cid:51)(cid:40)(cid:53)(cid:3)(cid:54)(cid:43)(cid:36)(cid:53)(cid:40)(cid:3)(cid:36)(cid:48)(cid:50)(cid:56)(cid:49)(cid:55)(cid:54)

(cid:28)(cid:27)(cid:3)

(cid:20)(cid:23)(cid:17)(cid:3)(cid:38)(cid:36)(cid:54)(cid:43)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:38)(cid:36)(cid:54)(cid:43)(cid:3)(cid:40)(cid:52)(cid:56)(cid:44)(cid:57)(cid:36)(cid:47)(cid:40)(cid:49)(cid:55)(cid:54)

(cid:28)(cid:28)(cid:3)
(cid:3)

(cid:20)(cid:24)(cid:17)(cid:3)(cid:36)(cid:38)(cid:38)(cid:50)(cid:56)(cid:49)(cid:55)(cid:54)(cid:3)(cid:53)(cid:40)(cid:38)(cid:40)(cid:44)(cid:57)(cid:36)(cid:37)(cid:47)(cid:40)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3) 

(cid:3) (cid:36)(cid:38)(cid:38)(cid:53)(cid:56)(cid:40)(cid:39)(cid:3)(cid:53)(cid:40)(cid:57)(cid:40)(cid:49)(cid:56)(cid:40)(cid:54)

(cid:20)(cid:20)(cid:19)(cid:3) (cid:22)(cid:21)(cid:17)(cid:3)(cid:54)(cid:55)(cid:50)(cid:38)(cid:46)(cid:16)(cid:37)(cid:36)(cid:54)(cid:40)(cid:39)(cid:3)(cid:38)(cid:50)(cid:48)(cid:51)(cid:40)(cid:49)(cid:54)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:51)(cid:47)(cid:36)(cid:49)(cid:54)

(cid:20)(cid:20)(cid:22)(cid:3) (cid:22)(cid:22)(cid:17)(cid:3)(cid:40)(cid:48)(cid:51)(cid:47)(cid:50)(cid:60)(cid:40)(cid:40)(cid:3)(cid:54)(cid:36)(cid:47)(cid:36)(cid:53)(cid:44)(cid:40)(cid:54)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:37)(cid:40)(cid:49)(cid:40)(cid:41)(cid:44)(cid:55)(cid:3)(cid:40)(cid:59)(cid:51)(cid:40)(cid:49)(cid:54)(cid:40)(cid:54)

(cid:20)(cid:20)(cid:22)(cid:3) (cid:22)(cid:23)(cid:17)(cid:3)(cid:53)(cid:40)(cid:47)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:51)(cid:36)(cid:53)(cid:55)(cid:60)(cid:3)(cid:55)(cid:53)(cid:36)(cid:49)(cid:54)(cid:36)(cid:38)(cid:55)(cid:44)(cid:50)(cid:49)(cid:54)

(cid:20)(cid:20)(cid:22)(cid:3) (cid:22)(cid:24)(cid:17)(cid:3)(cid:41)(cid:44)(cid:49)(cid:36)(cid:49)(cid:38)(cid:44)(cid:36)(cid:47)(cid:3)(cid:44)(cid:49)(cid:54)(cid:55)(cid:53)(cid:56)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)

(cid:20)(cid:20)(cid:25)(cid:3) (cid:22)(cid:25)(cid:17)(cid:3)(cid:53)(cid:44)(cid:54)(cid:46)(cid:3)(cid:48)(cid:36)(cid:49)(cid:36)(cid:42)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)

(cid:28)(cid:28)(cid:3)

(cid:20)(cid:25)(cid:17)(cid:3)(cid:44)(cid:49)(cid:57)(cid:40)(cid:49)(cid:55)(cid:50)(cid:53)(cid:44)(cid:40)(cid:54)

(cid:20)(cid:20)(cid:28)(cid:3) (cid:22)(cid:26)(cid:17)(cid:3)(cid:54)(cid:56)(cid:51)(cid:51)(cid:47)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:36)(cid:53)(cid:60)(cid:3)(cid:38)(cid:36)(cid:54)(cid:43)(cid:3)(cid:41)(cid:47)(cid:50)(cid:58)(cid:3)(cid:44)(cid:49)(cid:41)(cid:50)(cid:53)(cid:48)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)

(cid:28)(cid:28)(cid:3)

(cid:20)(cid:26)(cid:17)(cid:3)(cid:40)(cid:59)(cid:51)(cid:47)(cid:50)(cid:53)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:40)(cid:57)(cid:36)(cid:47)(cid:56)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:36)(cid:54)(cid:54)(cid:40)(cid:55)(cid:54)

(cid:20)(cid:21)(cid:19)(cid:3) (cid:22)(cid:27)(cid:17)(cid:3)(cid:38)(cid:50)(cid:48)(cid:48)(cid:44)(cid:55)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:38)(cid:50)(cid:49)(cid:55)(cid:44)(cid:49)(cid:42)(cid:40)(cid:49)(cid:38)(cid:44)(cid:40)(cid:54)

(cid:20)(cid:19)(cid:19)(cid:3)

(cid:20)(cid:27)(cid:17)(cid:3)(cid:51)(cid:53)(cid:50)(cid:51)(cid:40)(cid:53)(cid:55)(cid:60)(cid:15)(cid:3)(cid:51)(cid:47)(cid:36)(cid:49)(cid:55)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:40)(cid:52)(cid:56)(cid:44)(cid:51)(cid:48)(cid:40)(cid:49)(cid:55)(cid:15)(cid:3)(cid:49)(cid:40)(cid:55)(cid:3)

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REPORT OF MANAGEMENT 

Management’s Responsibility for the Consolidated Financial Statements 

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. 
The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with 
International Financial Reporting Standards as issued by the International Accounting Standards Board and include 
certain estimates that reflect Management’s best judgments.  

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board 
of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is 
made up of five independent directors. The Audit Committee has a written mandate that complies with the current 
requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily 
complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee 
met with Management and the independent auditors on at least a quarterly basis to review the interim Consolidated 
Financial  Statements  and  Management’s  Discussion  and  Analysis  and  recommend  their  approval  to  the  Board  of 
Directors prior to their public release as well as annually to review the annual Consolidated Financial Statements and 
Management’s Discussion and Analysis and recommend their approval to the Board of Directors. 

Management’s Assessment of Internal Control Over Financial Reporting 

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. 
The internal control system was designed to provide reasonable assurance to Management regarding the preparation 
and presentation of the Consolidated Financial Statements. 

Internal  control  systems,  no matter  how well  designed,  have  inherent  limitations.  Therefore,  even  those  systems 
determined to be effective can provide only reasonable assurance with respect to financial statement preparation 
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that 
controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies 
or procedures may deteriorate. 

Management  has  assessed  the  design  and  effectiveness  of  internal  control  over  financial  reporting  as  at 
December 31, 2020. In making its assessment, Management has used the Committee of Sponsoring Organizations 
of the Treadway Commission framework in Internal Control – Integrated Framework (2013) to evaluate the design 
and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded 
that internal control over financial reporting was effective as at December 31, 2020. 

PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed to audit and provide 
independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as 
at  December 31, 2020,  as  stated  in  their  Report  of  Independent  Registered  Public  Accounting  Firm  dated 
February 8, 2021. PricewaterhouseCoopers LLP has provided such opinions. 

/s/ Alexander J. Pourbaix 

Alexander J. Pourbaix 
President & 
Chief Executive Officer 
Cenovus Energy Inc. 

February 8, 2021 

/s/ Jeffrey R. Hart 

Jeffrey R. Hart 
Executive Vice-President & 
Chief Financial Officer 
Cenovus Energy Inc. 

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REPORT OF INDEPENDENT REGISTERED PUBLIC  
ACCOUNTING FIRM 

To the Shareholders and Board of Directors of Cenovus Energy Inc. 

Opinions on the Financial Statements and Internal Control Over Financial Reporting 

We  have  audited  the  accompanying  consolidated  balance  sheets  of  Cenovus  Energy  Inc.  and  its  subsidiaries 
(together, the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of earnings 
(loss), comprehensive income (loss), shareholders’ equity and cash flows for each of the three years in the period 
ended  December  31,  2020,  including  the  related  notes  (collectively  referred  to  as  the  “Consolidated  Financial 
Statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020, 
based  on  criteria  established  in  Internal  Control  -  Integrated  Framework  (2013)  issued  by  the  Committee  of 
Sponsoring Organizations of the Treadway Commission (“COSO”). 

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the 
financial  position of  the Company  as of December 31, 2020  and 2019,  and  its  financial  performance  and  its  cash 
flows for each of the three years in the period ended December 31, 2020 in conformity with International Financial 
Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company 
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based 
on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO. 

Change in Accounting Principle  

As  discussed  in  Note  3  to  the  Consolidated  Financial  Statements,  the  Company  changed  the  manner  in  which  it 
accounts for leases as of January 1, 2019 due to the adoption of IFRS 16, Leases.  

Basis for Opinions 

The  Company's Management is  responsible for  these  Consolidated Financial  Statements,  for maintaining  effective 
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial 
reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our 
responsibility  is  to  express  opinions  on  the  Company’s  Consolidated  Financial  Statements  and  on  the  Company's 
internal  control  over  financial  reporting  based  on  our  audits.  We  are  a  public  accounting  firm  registered  with  the 
Public  Company  Accounting  Oversight  Board  (United  States)  (“PCAOB”)  and  are  required  to  be  independent  with 
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations 
of the Securities and Exchange Commission and the PCAOB. 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and 
perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of 
material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting 
was maintained in all material respects. 

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material 
misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures 
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts 
and  disclosures  in  the  Consolidated  Financial  Statements.  Our  audits  also  included  evaluating  the  accounting 
principles used and significant estimates made by Management, as well as evaluating the overall presentation of the 
Consolidated  Financial  Statements.  Our  audit  of  internal  control  over  financial  reporting  included  obtaining  an 
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and 
testing  and evaluating  the  design  and operating effectiveness of  internal  control  based on  the  assessed  risk. Our 
audits also included performing such other procedures as we considered necessary in the circumstances. We believe 
that our audits provide a reasonable basis for our opinions. 

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Definition and Limitations of Internal Control over Financial Reporting 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding 
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance 
with generally accepted accounting principles. A company’s internal control over financial reporting includes those 
policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly 
reflect  the  transactions  and  dispositions  of  the  assets  of  the  company;  (ii)  provide  reasonable  assurance  that 
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally 
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance 
with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding 
prevention or  timely  detection  of  unauthorized  acquisition,  use, or  disposition  of  the  company’s  assets  that  could 
have a material effect on the financial statements. 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become 
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may 
deteriorate. 

Critical Audit Matters 

The critical audit matters communicated below are matters arising from the current period audit of the Consolidated 
Financial Statements that were communicated or required to be communicated to the audit committee and that (i) 
relate  to  accounts  or  disclosures  that  are  material  to  the  Consolidated  Financial  Statements  and  (ii)  involved  our 
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter 
in  any  way  our  opinion  on  the  Consolidated  Financial  Statements,  taken  as  a  whole,  and  we  are  not,  by 
communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the 
accounts or disclosures to which they relate.  

Impact  of  Reserves  and  Resource  Estimates  on  the  Recoverable  Amounts  of  Property,  Plant  and 
Equipment  (“PP&E”)  and  any  Allocated  Goodwill  (the  “recoverable  amounts”)  of  the  Oil  Sands  and 
Conventional  Cash  Generating  Units  (“CGUs”)  and  on  Depreciation,  Depletion  and  Amortization 
(“DD&A”) Expense for the Oil Sands and Conventional Segments 

As described in Notes 1, 3, 4, 10, 18 and 21 to the Consolidated Financial Statements, Management assesses its 
CGUs for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying 
amount of a CGU, which is net of accumulated DD&A and net impairment losses, may exceed its recoverable amount. 
Goodwill is tested for impairment at least annually. Management calculates depletion on the costs accumulated within 
each  area  using  the  unit-of-production  method  based  on  estimated  proved  reserves.  Costs  subject  to  depletion 
include estimated future costs to be incurred in developing proved reserves. As at December 31, 2020, the Company 
had $19,748 million and $1,758 million in Oil Sands and Conventional PP&E assets net of accumulated DD&A and net 
impairment  losses,  respectively.  Goodwill  related  to  the  Oil  Sands  segment  amounted  to  $2,272  million  as  at 
December 31, 2020. In aggregate, the Company recognized $2,564 million of DD&A expense for the Oil Sands and 
Conventional segments, which included impairment of $555 million for the Conventional CGUs, for the year ended 
December  31,  2020.  Management  determined  the  recoverable  amounts  of  the  Oil  Sands  and  Conventional  CGUs 
based on their fair value less costs of disposal using discounted after-tax cash flows from reserves and resources. 
These fair value  assessments  required  the  use  of significant  estimates  and  judgments by Management related  to 
forward commodity prices, expected production volumes, quantity of reserves and resources, royalty payments, and 
future development and operating expenses as well as estimates over discount rates. Management’s estimates of 
reserves and resources, as applicable, used for both the determination of the recoverable amounts of the Oil Sands 
and  Conventional  CGUs  and  the  calculation  of DD&A  expense  for  the Oil  Sands  and Conventional  segments  have 
been developed by Management’s specialists, specifically independent qualified reserve evaluators. 

The principal considerations for our determination that performing procedures relating to the impact of reserves and 
resource estimates on the recoverable amounts of the Oil Sands and Conventional CGUs and on DD&A expense for 
the Oil Sands and Conventional segments is a critical audit matter are (i) the significant amount of judgment required 
by  Management,  including  the  use  of  Management’s  specialists,  when  developing  the  estimates  of  reserves  and 
resources and the recoverable amounts; (ii) there was a high degree of auditor judgment, subjectivity, and effort in 
performing procedures relating to the significant assumptions used in developing these estimates including forward 
commodity  prices,  expected  production  volumes,  quantity  of  reserves  and  resources,  future  development  and 
operating  expenses,  as  well  as  discount  rates;  and  (iii)  the  audit  effort  involved  the  use  of  professionals  with 
specialized skill and knowledge. 

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Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our 
overall  opinion  on  the  Consolidated  Financial  Statements.  These  procedures  included  testing  the  effectiveness  of 
controls relating to Management’s estimates of reserves and resources, the determination of the recoverable amounts 
of the Oil Sands and Conventional CGUs and the calculation of DD&A expense for the Oil Sands and Conventional 
segments.  These  procedures  also  included,  among  others,  testing  Management’s  process  for  determining  the 
recoverable amounts of the Oil Sands and Conventional CGUs and DD&A expense for the Oil Sands and Conventional 
segments, which included (i) evaluating the appropriateness of the methods used by Management in making these 
estimates; (ii) testing the completeness and accuracy of underlying data used in Management’s model; (iii) assessing 
the reasonability of the assumptions used by Management, including forward commodity prices, expected production 
volumes, quantity of reserves and resources, as well as future development and operating expenses; and (iv) testing 
the  unit-of-production  rates  used  to  calculate  DD&A  expense.  The  work  of  Management’s  specialists  was  used  in 
performing  the  procedures  to  evaluate  the  reasonableness  of  the  quantity  of  reserves  and  resources  used  to 
determine the recoverable amounts of the Oil Sands and Conventional CGUs and DD&A expense for the Oil Sands 
and  Conventional  segments,  as  applicable.  As  a  basis  for  using  this  work,  the  specialists’  qualifications  were 
understood,  and  the  Company’s  relationship  with  the  specialists  was  assessed.  The  procedures  performed  also 
included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists 
and  an  evaluation  of  the  specialists’  findings.  Evaluating  the  assumptions  used  by  Management’s  specialists  also 
involved assessing whether the assumptions used were reasonable considering the current and past performance of 
the Company, consistency with industry pricing forecasts and consistency with evidence obtained in other areas of 
the audit. Professionals with specialized skill and knowledge were also used to assist in evaluating the reasonableness 
of the recoverability calculations, including the discount rate used within the models. 

Impairment Assessment of PP&E for the Wood River and Borger CGUs within the Refining and Marketing 
Segment 

As described in Notes 1, 3, 4, 10 and 18 to the Consolidated Financial Statements, Management assesses its CGUs 
for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount 
of a CGU, which is net of accumulated DD&A and net impairment losses, may exceed its recoverable amount. As at 
December 31, 2020, the Company had $3,476 million of PP&E assets net of accumulated DD&A and net impairment 
losses relating to refining equipment. For the year ended December 31, 2020, the carrying amount of the Borger 
CGU  was  determined  to  be  greater  than  the  recoverable  amount  and  an  impairment  charge  of  $450 million  was 
recorded  as  additional DD&A in  the Refining  and Marketing  segment.  No  impairment of the  Wood River  CGU was 
identified by Management. Management determined the recoverable amounts of PP&E for the Wood River and Borger 
CGUs  based  on  their  fair  value  less  costs  of  disposal  using  discounted  after-tax  cash  flows  requiring  the  use  of 
significant estimates and judgments by Management related to forward crude oil prices, forward crack spreads, future 
capital expenditures, operating expenses, terminal values and the discount rates.  

The principal considerations for our determination that performing procedures relating to the impairment assessment 
of PP&E for the Wood River and Borger CGUs within the Refining and Marketing segment is a critical audit matter are 
(i) the significant amount of judgment required by Management when developing the recoverable amounts of the 
Wood River and Borger CGUs; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing 
procedures  relating  to  the  significant  assumptions  used  in developing  these  estimates  including  forward  crude oil 
prices, forward crack spreads, future capital expenditures, operating expenses and terminal values, as well as the 
discount rate applied; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. 

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Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our 
overall  opinion  on  the  Consolidated  Financial  Statements.  These  procedures  included  testing  the  effectiveness  of 
controls relating to Management’s determination of the recoverable amounts of the Wood River and Borger CGU’s. 
These  procedures  also  included,  among  others,  testing  Management’s  process  for  determining  the  recoverable 
amounts of the Wood River and Borger CGU’s, which included (i) evaluating the appropriateness of the methods used 
by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in 
these models; and (iii) assessing the reasonability of the assumptions used by Management, including forward crude 
oil prices, forward crack spreads, future capital expenditures and operating expenses. Evaluating the assumptions 
used by Management involved assessing whether the assumptions used were reasonable considering the current and 
past performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained 
in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating the 
overall reasonableness of the recoverability calculations, including terminal values and the discount rates used within 
the models. 

/s/ PricewaterhouseCoopers LLP 

Chartered Professional Accountants 
Calgary, Alberta, Canada 

February 8, 2021 

We have served as the Company’s auditor since 2008. 

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CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) 

For the years ended December 31, 
($ millions, except per share amounts) 

Revenues 

Gross Sales 

Less: Royalties 

Expenses 

Purchased Product 

Transportation and Blending 
Operating 

Inventory Write-Down (Reversal) 
(Gain) Loss on Risk Management 

Depreciation, Depletion and Amortization 
Exploration Expense 

General and Administrative 
Finance Costs 
Interest Income 

Transaction Costs 

Foreign Exchange (Gain) Loss, Net 

Re-measurement of Contingent Payment 

(Gain) Loss on Divestiture of Assets 

Other (Income) Loss, Net 

Earnings (Loss) From Continuing Operations Before Income Tax 

Income Tax Expense (Recovery) 

Net Earnings (Loss) From Continuing Operations 

Net Earnings (Loss) From Discontinued Operations 

Net Earnings (Loss) 

Basic and Diluted Earnings (Loss) Per Share ($) 

Continuing Operations 

Discontinued Operations 

Net Earnings (Loss) Per Share 

See accompanying Notes to Consolidated Financial Statements. 

Notes     

2020       

2019       

2018   

1     

1     

16     
35     
10,17,18,19     
10,17     
5     
6     

39     
7     
26     
8     
9     

12     

11     

13     

13,591       
364       
13,227       

21,353       
1,173       
20,180       

21,389   

546   

20,843   

5,119       
4,444       
1,930       
555       
308       
3,464       
91       
292       
536       
(9 )     
29       
(181 )     
(80 )     
(81 )     
40       
(3,230 )     
(851 )     
(2,379 )     
-       
(2,379 )     

8,378       
5,184       
2,088       
49       
156       
2,249       
82       
331       
511       
(12 )     
-       
(404 )     
164       
(2 )     
9       
1,397       
(797 )     
2,194       
-       
2,194       

8,684   

5,942   
2,184   

60   
305   

2,131   
2,123   

1,020   
627   
(19 ) 

-   

854   

50   

795   

13   

(3,926 ) 

(1,010 ) 

(2,916 ) 

247   

(2,669 ) 

(1.94 )     
-       
(1.94 )     

1.78       
-       
1.78       

(2.37 ) 

0.20   

(2.17 ) 

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE 
INCOME (LOSS) 

For the years ended December 31, 
($ millions) 

Net Earnings (Loss) 

Other Comprehensive Income (Loss), Net of Tax 

Items That Will Not be Reclassified to Profit or Loss: 

Actuarial Gain (Loss) Relating to Pension and Other 
   Post-Retirement Benefits 
Change in the Fair Value of Equity Instruments at FVOCI (1) 

Items That May be Reclassified to Profit or Loss: 

Foreign Currency Translation Adjustment 

Total Other Comprehensive Income (Loss), Net of Tax 

Comprehensive Income (Loss) 

(1) 

Fair value through other comprehensive income (loss) (“FVOCI”). 

See accompanying Notes to Consolidated Financial Statements. 

Notes     

2020       

2019       

2018   

(2,379 )     

2,194       

(2,669 ) 

31     

(8 )     
-       

(44 )     
(52 )     
(2,431 )     

5       
12       

(228 )     
(211 )     
1,983       

(3 ) 

1   

397   

395   

(2,274 ) 

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CONSOLIDATED BALANCE SHEETS 

As at December 31, 
($ millions) 

Assets 

Current Assets 

Cash and Cash Equivalents 
Accounts Receivable and Accrued Revenues 

Income Tax Receivable 

Inventories 

Total Current Assets 
Exploration and Evaluation Assets 

Property, Plant and Equipment, Net 
Right-of-Use Assets, Net 

Other Assets 
Deferred Income Taxes 

Goodwill 

Total Assets 

Liabilities and Shareholders’ Equity 

Current Liabilities 

Accounts Payable and Accrued Liabilities 

Short-Term Borrowings 

Lease Liabilities 

Contingent Payment 

Income Tax Payable 

Total Current Liabilities 

Long-Term Debt 

Lease Liabilities 

Contingent Payment 

Decommissioning Liabilities 

Other Liabilities 

Deferred Income Taxes 

Total Liabilities 

Shareholders’ Equity 

Total Liabilities and Shareholders’ Equity 

Commitments and Contingencies 

See accompanying Notes to Consolidated Financial Statements. 

Approved by the Board of Directors 

Notes     

2020     

2019   

378       
1,488       
21       
1,089       
2,976       
623       
25,411       
1,139       
313       
36       
2,272       
32,770       

2,018       
121       
184       
36       
-       
2,359       
7,441       
1,573       
27       
1,248       
181       
3,234       
16,063       
16,707       
32,770       

186   
1,556   

10   

1,532   

3,284   
787   

27,834   
1,325   

211   
-   

2,272   

35,713   

2,229   

-   

196   

79   

17   

2,521   

6,699   

1,720   

64   

1,235   

241   

4,032   

16,512   

19,201   

35,713   

14     
15     

16     

1,17     
1,18     
1,19     
20     
12     
1,21     

22     
23     
25     
26     

24     
25     
26     
27     
28     
12     

38     

/s/ Keith A. MacPhail 

Keith A. MacPhail 
Director 
Cenovus Energy Inc. 

/s/ Claude Mongeau 

Claude Mongeau 
Director 
Cenovus Energy Inc. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:26)(cid:24)

 
 
 
  
  
       
          
  
  
  
     
       
   
     
       
   
     
       
   
     
     
     
  
     
       
   
     
       
   
     
       
   
     
     
     
     
     
  
     
       
   
       
   
  
     
       
   
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY 

($ millions) 

As at December 31, 2017 

Net Earnings (Loss) 

Other Comprehensive Income (Loss) 

Total Comprehensive Income (Loss) 

Stock-Based Compensation Expense 
Dividends on Common Shares 

As at December 31, 2018 

Net Earnings (Loss) 

Other Comprehensive Income (Loss) 

Total Comprehensive Income (Loss) 

Stock-Based Compensation Expense 

Dividends on Common Shares 

As at December 31, 2019 

Net Earnings (Loss) 
Other Comprehensive Income (Loss) 

Total Comprehensive Income (Loss) 

Stock-Based Compensation Expense 

Dividends on Common Shares 

As at December 31, 2020 

Share 
Capital     
(Note 30)     

Paid in 
Surplus     
(Note 30)       

Retained 
Earnings     

AOCI (1)     
(Note 31)       

11,040       

-     
-     
-     
-       
-     

11,040       
-       
-       
-       
-       
-       
11,040       
-       
-       
-       
-       
-       
11,040       

4,361       
-       
-     
-       
6     
-       
4,367       
-       
-       
-       
10       
-       
4,377       
-       
-       
-       
14       
-       
4,391       

3,937       
(2,669 )   

-       
(2,669 )     

-     
(245 )   
1,023       
2,194       
-       
2,194       
-       
(260 )     
2,957       
(2,379 )     
-       
(2,379 )     
-       
(77 )     
501       

643       
-       
395       
395       
-       
-       
1,038       
-       
(211 )     
(211 )     
-       
-       
827       
-       
(52 )     
(52 )     
-       
-       
775       

Total   

19,981   

(2,669 ) 

395   

(2,274 ) 

6   
(245 ) 

17,468   

2,194   

(211 ) 

1,983   
10   

(260 ) 
19,201   

(2,379 ) 
(52 ) 

(2,431 ) 

14   

(77 ) 

16,707   

(1) 

Accumulated other comprehensive income (loss) (“AOCI”).  

See accompanying Notes to Consolidated Financial Statements. 

(cid:26)(cid:25)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
  
    
        
        
        
        
  
  
  
     
   
  
  
       
       
       
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
    
        
        
        
        
  
 
 
CONSOLIDATED STATEMENTS OF CASH FLOWS 

For the years ended December 31, 
($ millions) 

Notes     

2020       

2019       

2018   

Operating Activities 
Net Earnings (Loss) 

Depreciation, Depletion and Amortization 
Exploration Expense 

Inventory Write-Down (Reversal) 

Deferred Income Tax Expense (Recovery) 

Unrealized (Gain) Loss on Risk Management 
Unrealized Foreign Exchange (Gain) Loss 

Re-measurement of Contingent Payment 

(Gain) Loss on Discontinuance 

(Gain) Loss on Divestiture of Assets 
Unwinding of Discount on Decommissioning Liabilities 

Realized Inventory Write-Down 

Realized Foreign Exchange (Gain) Loss on Non-Operating Items 

Other 
Net Change in Other Assets and Liabilities 

Net Change in Non-Cash Working Capital 

Cash From (Used in) Operating Activities 

10,17,18,19     
10,17     
16     
12     
35     
7     
26     
11     
8     
27     

Investing Activities 

Capital Expenditures – Exploration and Evaluation Assets 

Capital Expenditures – Property, Plant and Equipment 

Proceeds From Divestitures 

Net Change in Investments and Other 

Net Change in Non-Cash Working Capital 

Cash From (Used in) Investing Activities 

17     
18     
8,11     

(2,379 )     
3,464       
91       
555       
(838 )     
56       
(131 )     
(80 )     
-       
(81 )     
57       
(572 )     
(33 )     
38       
(72 )     
198       
273       

(48 )     
(811 )     
38       
(4 )     
(38 )     
(863 )     

2,194       
2,249       
82       
49       
(814 )     
149       
(827 )     
164       
-       
(2 )     
58       
(71 )     
401       
70       
(84 )     
(333 )     
3,285       

(73 )     
(1,110 )     
1       
(133 )     
(117 )     
(1,432 )     

(2,669 ) 

2,131   
2,123   

60   

(794 ) 

(1,249 ) 
649   

50   

(301 ) 

795   
63   

(13 ) 
206   

670   
(72 ) 

505   

2,154   

(55 ) 

(1,322 ) 

1,050   

9   

(295 ) 

(613 ) 

Net Cash Provided (Used) Before Financing Activities 

(590 )     

1,853       

1,541   

Financing Activities 

Issuance (Repayment) of Short-Term Borrowings 

Issuance of Long-Term Debt 

Repayment of Long-Term Debt 

Net Issuance (Repayment) of Revolving Long-Term Debt 

Principal Repayment of Leases 

Dividends Paid on Common Shares 

Other 

Cash From (Used in) Financing Activities 

Foreign Exchange Gain (Loss) on Cash and Cash 
  Equivalents Held in Foreign Currency 
Increase (Decrease) in Cash and Cash Equivalents 
Cash and Cash Equivalents, Beginning of Year 

Cash and Cash Equivalents, End of Year 

See accompanying Notes to Consolidated Financial Statements. 

37     

13     

117       
1,326       
(112 )     
(220 )     
(197 )     
(77 )     
-       
837       

(55 )     
192       
186       
378       

-       
-       
(2,279 )     
276       
(150 )     
(260 )     
-       
(2,413 )     

(35 )     
(595 )     
781       
186       

-   

-   

(1,144 ) 

(20 ) 

-   

(245 ) 

(1 ) 

(1,410 ) 

40   

171   

610   

781   

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:26)(cid:26)

 
 
 
  
  
  
  
  
  
  
  
  
     
       
       
   
     
       
       
   
     
     
     
     
     
     
     
  
     
       
       
   
     
       
       
   
     
     
     
  
     
       
       
   
     
  
     
       
       
   
       
       
   
     
     
     
     
     
     
     
  
     
       
       
   
     
     
     
     
  
     
       
       
   
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES 

Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of developing, 
producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with marketing activities 
and refining operations in the United States (“U.S.”). 

Cenovus  is  incorporated  under  the  “Canada  Business  Corporations  Act”  and  its  shares  are  listed  on  the  Toronto 
(“TSX”)  and  New  York  (“NYSE”)  stock  exchanges.  The  executive  and  registered  office  is  located  at  4100,  225 
6 Avenue S.W.,  Calgary,  Alberta,  Canada,  T2P 1N2.  Information  on  the  Company’s  basis  of  preparation  for  these 
Consolidated Financial Statements is found in Note 2.  

On October 25, 2020, Cenovus announced that it had entered into a definitive agreement to combine with Husky 
Energy  Inc.  (“Husky”).  The  transaction  was  accomplished  through  a  plan  of  arrangement  (the  “Arrangement”) 
pursuant to which Cenovus acquired all the issued and outstanding common shares of Husky in exchange for common 
shares  and  common  share  purchase  warrants  of  Cenovus.  In  addition,  all  of  the  issued  and  outstanding  Husky 
preferred shares were exchanged for Cenovus preferred shares with substantially identical terms. The Arrangement 
closed on January 1, 2021 (see Note 39).  

The Arrangement will combine oil sands and heavy oil assets with extensive transportation, storage and logistics and 
downstream infrastructure, creating opportunities to optimize the margin captured across the heavy oil value chain. 
The  combined  company  will  be  largely  integrated  reducing  exposure  to  Alberta  heavy  oil  price  differentials  while 
maintaining exposure to global commodity prices.  

Management has determined the operating segments based on information regularly reviewed for the purposes of 
decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision 
makers. The Company evaluates the financial performance of its operating segments primarily based on operating 
margin. The Company’s reportable segments at December 31, 2020 are: 

(cid:120)  Oil  Sands,  which  includes  the  development  and  production  of  bitumen  in  northeast  Alberta.  Cenovus’s 
bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early 
stages of development.  

(cid:120) 

Conventional,  which  includes  assets  rich  in  NGLs  and  natural  gas  within  the  Elmworth-Wapiti,  Kaybob-
Edson, and Clearwater operating areas in Alberta and British Columbia and the exploration for heavy oil in 
Marten Hills area. The assets include interests in numerous natural gas processing facilities. The Company 
renamed  its  Deep  Basin  segment  to  Conventional  in  2020  and  its  new  resource  play,  Marten  Hills,  was 
reclassified  from  the  Oil  Sands  segment  to  the  Conventional  segment.  Comparative  periods  have  been 
reclassified. On December 2, 2020, the Company completed the sale of its Marten Hills assets (see Note 8).  

(cid:120)  Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum 
and  chemical  products.  Cenovus  jointly  owns  two  refineries  in  the  U.S.  with  the  operator  Phillips  66,  an 
unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. 
This  segment  coordinates  Cenovus’s  marketing  and  transportation  initiatives  to  optimize  product  mix, 
delivery points, transportation commitments and customer diversification. The marketing of crude oil and 
natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to 
be  undertaken  by  a  Canadian  business.  U.S.  sourced  crude  oil  and  natural  gas  purchases  and  sales  are 
attributed to the U.S. 

(cid:120) 

Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative 
financial  instruments,  gains  and  losses  on  divestiture  of  assets,  as  well  as  other  Cenovus-wide  costs  for 
general and administrative, financing activities and research costs. As financial instruments are settled, the 
realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. 
Eliminations  include  adjustments  for  internal  usage  of  natural  gas  production  between  segments, 
transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production 
used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. 
Eliminations are recorded at transfer prices based on current market prices. The Corporate and Eliminations 
segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which 
have been attributed to the country in which the transacting entity resides. 

The following tabular financial information presents the segmented information first by segment, then by product 
and geographic location.  

(cid:26)(cid:27)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
 
A) Results of Operations – Segment and Operational Information  

For the years ended December 31, 

2020     

2019     

2018      2020      2019      2018      2020     

2019     

2018   

Oil Sands 

Conventional 

     Refining and Marketing 

Revenues 

Gross Sales 
Less: Royalties 

Expenses 

Purchased Product 

Transportation and Blending 

Operating 
Inventory Write-Down (Reversal) 

(Gain) Loss on Risk Management 

Operating Margin 

Depreciation, Depletion and 

Amortization 

Exploration Expense 

Segment Income (Loss) 

   7,514       10,838       10,026        635       
   324        1,143       
40       
   7,190        9,695        9,553        595       

473       

691       
30       
661       

904        6,051       10,513       11,183   
-   
831        6,051       10,513       11,183   

73       

-       

-       

-       

-       

-       
-       
   4,399        5,152        5,879       
81       
   1,094        1,039        1,037        318       
-       
   316       
   268       
-       
   1,113        3,481        1,086        196       

-       
23        1,551       

-       

-       
82       
337       
-       
-       
242       

-        5,397        8,795        9,201   
-   

90       
403       
-       
26       
312       

-       
824       
239       
(21 )     
(388 )     

-       
948       
49       
(16 )     
737       

   1,684        1,543        1,439        880       
82       
(359 )      (766 )    

18       
   (580 )     1,920       

9       

6       

319       

412       
64        2,117       

739       
-       
(141 )     (2,217 )      (1,127 )     

280       
-       
457       

Corporate and 
Eliminations 

     2020      2019      2018      2020     

Consolidated 
2019     

927   
60   

(1 ) 

996   

222   

-   

774   

2018   

For the years ended December 31, 

Revenues 

Gross Sales 

Less: Royalties 

Expenses 

Purchased Product 

Transportation and Blending 

Operating 

Inventory Write-Down (Reversal) 

(Gain) Loss on Risk Management 

Depreciation, Depletion and Amortization 

Exploration Expense 

Segment Income (Loss) 

General and Administrative 

Finance Costs 

Interest Income 

Transaction Costs 
Foreign Exchange (Gain) Loss, Net      

Re-measurement of Contingent Payment 

(Gain) Loss on Divestiture of Assets 
Other (Income) Loss, Net 

Earnings (Loss) From Continuing Operations Before Income Tax 

Income Tax Expense (Recovery) 

Net Earnings (Loss) From Continuing Operations 

       (609 )    
-       
       (609 )    

       (278 )    
(36 )    
       (306 )    
-       
61       
       161       
-       
       (211 )    
       292       
       536       
(9 )    
29       
       (181 )    
(80 )    
(81 )    
40       
       546       

(689 )      (724 )     13,591       21,353       21,389   
546   
(689 )      (724 )     13,227       20,180       20,843   

364        1,173       

-       

-       

-       

-       

91       

(50 )     

49       
156       

555       
308       

(417 )      (517 )      5,119        8,378        8,684   
(27 )      4,444        5,184        5,942   
(236 )      (183 )      1,930        2,088        2,184   
60   

-       
149       (1,271 )     
107       
-       

305   
58        3,464        2,249        2,131   
82        2,123   
(586 ) 
331        1,020   
511       
627   
(12 )     
-       
(404 )     
164       
(2 )     
9       

(242 )      1,216        (2,684 )      1,994       
331        1,020       
627       
511       
(19 )     
(12 )     
-       
-       
854       
(404 )     
50       
164       
795       
(2 )     
13       
9       
597        3,340       

292       
536       
(9 )     
29       
(181 )     
(80 )     
(81 )     
40       
546       

795   
13   
597        3,340   
       (3,230 )      1,397       (3,926 ) 
(797 )     (1,010 ) 
       (2,379 )      2,194       (2,916 ) 

-   
854   

(851 )     

(19 ) 

50   

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:26)(cid:28)

 
 
 
  
    
  
    
      
       
       
       
       
       
       
       
   
  
  
       
       
       
       
       
       
       
       
   
  
  
  
  
       
       
       
       
       
       
       
       
   
  
    
        
        
    
    
  
    
        
        
    
        
        
        
      
       
       
       
       
   
    
        
        
    
        
        
      
  
    
        
        
    
        
        
      
       
       
       
       
       
   
    
        
        
    
        
        
      
    
        
        
    
        
        
      
    
        
        
      
        
        
    
        
        
      
    
        
        
    
        
        
    
        
        
    
        
        
      
    
        
        
      
        
        
        
        
      
        
        
      
    
        
        
      
  
    
        
        
        
        
  
       
       
         
        
        
      
        
        
        
 
 
 
B) Revenues by Product 

For the years ended December 31, 

2020       

2019       

2018   

Upstream 

Crude Oil 

NGLs 

Natural Gas 

Other 

Refined Products 

Market Optimization 
Corporate and Eliminations 

Revenues From Continuing Operations 

C) Geographical Information  

For the years ended December 31, 

Canada 

United States 

Consolidated 

As at December 31, 
Canada 
United States 

Consolidated 

7,270       
142       
315       
58       
4,734       
1,317       
(609 )     
13,227       

9,790       
202       
299       
65       
8,291       
2,222       
(689 )     
20,180       

Revenues 

2020       
8,399       
4,828       
13,227       

2019       
11,798       
8,382       
20,180       

9,662   

333   

320   

69   
9,032   

2,151   
(724 ) 

20,843   

2018   

11,694   

9,149   

20,843   

Non-Current Assets (1) 

2020     
26,168       
3,590       
29,758       

2019   

28,336   

4,093   

32,429   

(1) 

Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, other assets and goodwill. 

Export Sales 

Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers 
outside of Canada were $2,639 million (2019 – $4,002 million; 2018 – $2,500 million). 

Major Customers 

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined 
products  for  the  year  ended December 31, 2020,  Cenovus  had  three  customers  (2019 –  two; 2018  –  three)  that 
individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized 
as major international energy companies with investment grade credit ratings, were approximately $4,323 million, 
$1,834 million and $1,472 million, respectively (2019 – $6,922 million and $2,316 million; 2018 – $7,840 million, 
$2,285 million and $2,263 million), which are included in all of the Company’s operating segments. 

D) Assets by Segment  

As at December 31, 
Oil Sands 

Conventional 

Refining and Marketing 

Corporate and Eliminations 

Consolidated 

As at December 31, 
Oil Sands 

Conventional 
Refining and Marketing 
Corporate and Eliminations 

Consolidated 

E&E Assets (1) 
2020     

617       
6       
-     
-     
623       

PP&E 

ROU Assets 

2019     

2020     

2019     
594        19,748        20,924       
1,758       
2,433       
193       
3,652       
4,131       
-       
346       
253       
-       
787        25,411        27,834       

2020     

623       
3       
79       
434       
1,139       

2019   

768   
3   

77   

477   

1,325   

Goodwill 

2020     
2,272       

-     
-     
-     

2,272       

Total Assets 
2020     

2019     
2,272        24,656       
1,953       
4,951       
1,210       
2,272        32,770       

-       
-       
-       

2019   

26,203   
2,754   
5,688   
1,068   

35,713   

(1) 

Prior to its sale, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment and the comparative period was reclassified.  

(cid:27)(cid:19)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
  
  
       
       
   
  
  
  
  
  
  
  
  
 
  
  
  
  
  
  
 
 
  
  
  
  
  
  
    
    
  
  
  
  
 
  
  
    
  
    
  
  
    
  
  
    
    
  
    
  
  
    
  
  
    
  
  
    
    
 
 
E) Capital Expenditures (1) 

For the years ended December 31, 
Capital Investment (2) 

Oil Sands 

Conventional 

Refining and Marketing 

Corporate and Eliminations 

Acquisition Capital 

Oil Sands 
Conventional 

Refining and Marketing 

Total Capital Expenditures 

2020       

2019       

2018   

427       
78       
276       
60       
841       

6       
12       
-       
859       

656       
103       
280       
137       
1,176       

2       
7       
4       
1,189       

870   

228   

208   

57   

1,363   

319   

22   

-   

1,704   

Includes expenditures on PP&E and E&E assets. 

(1) 
(2)   Prior to its sale, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment and the comparative periods were reclassified. 

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE 

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. 
All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars. 

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting 
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the 
International Financial Reporting Interpretations Committee (“IFRIC”). 

These Consolidated Financial  Statements  have been  prepared on  a  historical  cost  basis, except  as detailed  in  the 
Company’s accounting policies disclosed in Note 3.  

These Consolidated Financial Statements were approved by the Board of Directors on February 8, 2021. 

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 

A) Principles of Consolidation  

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities 
over  which  the  Company  has  control.  Subsidiaries  are  consolidated  from  the  date  of  acquisition  of  control  and 
continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and 
unrealized gains and losses from intercompany transactions are eliminated on consolidation. 

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights 
and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets 
and obligations for the liabilities of the arrangement. The Company’s refining activities are conducted through the 
joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets, 
liabilities, revenues and expenses.  

An associate is an entity for which the Company has significant influence over but does not control or jointly control 
the investee. Investments in associates are accounted for using the equity method of accounting and are recognized 
at  cost  and  adjusted  thereafter  to  recognize  the  Company’s  share  of  the  investee’s  profit  or  loss  and  other 
comprehensive income (“OCI”).  

B) Foreign Currency Translation 

Functional and Presentation Currency 

The  Company’s  functional  and  presentation  currency  is  Canadian  dollars.  The  accounts  of  the  Company’s  foreign 
operations that have a functional currency different from the Company’s presentation currency are translated into 
the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates 
over  the  period  for  revenues  and  expenses.  Translation  gains  and  losses  relating  to  the  foreign  operations  are 
recognized in OCI as cumulative translation adjustments. 

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant 
influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign 
operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation 
that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between 
controlling and non-controlling interests. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:27)(cid:20)

 
 
  
  
       
       
   
  
  
  
  
  
 
 
 
  
  
       
       
   
  
  
  
  
 
 
Transactions and Balances 

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect 
at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies 
are  translated  into  its functional  currency  at  the  rates of exchange  in effect  at  the period-end  date.  Any gains or 
losses are recorded in the Consolidated Statements of Earnings (Loss). 

C) Revenue Recognition  

Revenue  is  measured  based  on  the  consideration  specified  in  a  contract  with  a  customer  and  excludes  amounts 
collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service 
to a customer, which is generally when title passes from the Company to its customer.  

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are 
recorded  on  a  net  basis.  Revenues  associated  with  services  provided  as  agent  are  recorded  as  the  services  are 
provided. 

Cenovus recognizes revenue from the following major products and services: 

Sale of crude oil, NGLs and natural gas. 
(cid:120) 
Sale of petroleum and refined products. 
(cid:120) 
Natural gas processing revenue. 
(cid:120) 
(cid:120)  Marketing and transportation services. 
(cid:120) 

Fee-for-service hydrocarbon trans-loading services. 

The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, 
natural gas and petroleum and refined products, which is generally at a point in time. Performance obligations for 
natural gas processing revenue, marketing, transportation services and trans-loading services are satisfied over time 
as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas and petroleum and refined 
products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on 
the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on 
the  agreed  transaction  price  with  any  variability  in  transaction  price  recognized  in  the  same  period.  Revenue 
associated  with  natural  gas  processing,  marketing,  transportation  services  and  trans-loading  services  are  based, 
generally on fixed price contracts. 

Cenovus’s  revenue  transactions  do  not  contain  significant  financing  components  and  payments  are  typically  due 
within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant 
financing component when the period between the transfer of the promised goods or services to the customer and 
payment  by  the  customer  is  less  than  one  year.  The  Company  does  not  disclose  or  quantify  information  about 
remaining performance obligations that have an original expected duration of one year or less and it does not have 
any long-term contracts with unfulfilled performance obligations.  

D) Transportation and Blending 

The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in 
blending, are recognized when the product is sold. 

E) Exploration Expense 

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which 
they are incurred as exploration expense.  

Costs  incurred  after  the  legal  right  to  explore  is  obtained  are  initially  capitalized.  If  it  is  determined  that  the 
field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the 
exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense. 

F) Employee Benefit Plans 

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit 
component and an other post-employment benefit plan (“OPEB”).  

Pension expense for the defined contribution pension is recorded as the benefits are earned. 

The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit 
method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension 
and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus 
resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds 
from the plans or reductions in future contributions to the plans.  

(cid:27)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
 
Changes  in  the  defined  benefit  obligation from  service  costs,  net  interest  and remeasurements  are  recognized  as 
follows: 
(cid:120) 

Service  costs,  including  current  service  costs,  past  service  costs,  gains  and  losses  on  curtailments,  and 
settlements, are recorded with pension benefit costs.  
Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation 
at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense 
and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit 
costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. 
Remeasurements,  composed  of  actuarial  gains  and  losses,  the  effect  of  changes  to  the  asset  ceiling 
(excluding interest) and the return on plan assets (excluding interest income), are charged or credited to 
equity  in  OCI  in  the  period  in  which  they  arise.  Remeasurements  are  not  reclassified  to  net  earnings  in 
subsequent periods.  

(cid:120) 

(cid:120) 

Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E 
assets, corresponding to where the associated salaries of the employees rendering the service are recorded.  

From time-to-time, the Company may provide certain other long-term incentive benefits to employees. In 2019, a 
one-time  incentive  program was  introduced whereby a cash  award  equivalent  to  the  employee’s  base  salary  is 
payable  if  Cenovus  achieves  prior  to  February  12,  2024 a target share  price  of  $20  per  share  for a  period 
of 20 consecutive trading days on the TSX (the “Plan”). All employees, except for the President & Chief Executive 
Officer,  are  eligible  and  new  employees  are  eligible  for  a  pro-rated  award  based  on  start  date provided  they  are 
employed on the payout date. The obligation related to this Plan is estimated as the probability of the payout being 
achieved multiplied by the expected payout amount. The obligation is recognized over the greater of (i) the time to 
earliest payout of February 13, 2022; and (ii) the estimated time until payout is achieved, prior to February 12, 2024 
as general and administrative expense.  

G) Government Grants 

Government  grants  are  recognized  when  there  is  reasonable  assurance  that  the  grant  will  be  received  and  all 
conditions  associated with  the  grant  are  met. Grants related  to  assets  are recorded  as a  reduction  to  the  asset’s 
carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related 
to income are recorded as other income in the period in which eligible expenses were incurred or when the services 
have been performed.  

H) Income Taxes 

Income  taxes  comprise  current  and  deferred  taxes.  Income  taxes  are  provided  for  on  a  non-discounted  basis  at 
amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the 
Consolidated Balance Sheet date. 

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for 
the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the 
substantively  enacted  income  tax  rates  expected  to  apply  when  the  assets  are  realized  or  liabilities  are  settled. 
Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with 
the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items 
charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, 
respectively. 

Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the 
case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable 
that the temporary difference will not reverse in the foreseeable future or when distributions can be made without 
incurring income taxes. 

Deferred  income  tax  assets  are recognized only  to  the  extent  that  it  is  probable  that  future  taxable profit will  be 
available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only 
offset where  they  arise  within  the  same  entity  and  tax  jurisdiction.  Deferred  income  tax  assets  and  liabilities  are 
presented as non-current. 

I) Net Earnings per Share Amounts 

Basic  net  earnings  per  share  is  computed  by  dividing  net  earnings  by  the  weighted  average  number  of  common 
shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution 
that would occur if stock options or other contracts to issue common shares were exercised or converted to common 
shares.  The  treasury  stock  method  is  used  to  determine  the  dilutive  effect  of  stock  options  and  other  dilutive 
instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock 
options are used to repurchase common shares at the average market price. For those contracts that may be settled 
in  cash  or  in  shares  at  the  holder’s  option,  the  more  dilutive  of  cash  settlement  and  share  settlement  is  used  in 
calculating diluted earnings per share. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:27)(cid:22)

 
 
 
 
J) Cash and Cash Equivalents  

Cash  and  cash  equivalents  include  short-term  investments,  such  as  money  market  deposits  or  similar  type 
instruments, with a maturity of three months or less. 

K) Inventories  

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average 
cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to 
its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business 
less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The 
write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory 
is still on hand. 

L) Exploration and Evaluation Assets  

Costs  incurred  after  the  legal  right  to  explore  an  area  has  been  obtained,  and  before  technical  feasibility  and 
commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include 
license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable 
internal  costs.  E&E  assets  are  carried  forward  until  technical  feasibility  and  commercial  viability  of  the 
field/project/area  is  established  or  the  assets  are  determined  to  be  impaired  or  the  future  economic  value  has 
decreased. E&E costs are subject to regular technical, commercial and Management review to confirm the continued 
intent to develop the resources.  

Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These 
operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as 
depreciation,  depletion  and  amortization  (“DD&A”),  is  recognized  on  this  production  using  a  unit-of-production 
method  based  on  estimated  proved  reserves  determined  using  forward  prices  and  costs  and  considering  any 
estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an 
energy equivalent basis.  

Non-producing assets classified as E&E are not depleted.  

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested 
for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.  

Any gains or losses from the divestiture of E&E assets are recognized in net earnings. 

M) Property, Plant and Equipment  

General 

PP&E is stated at cost less accumulated DD&A, and net of any impairment losses. Expenditures related to renewals 
or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and 
repairs are expensed as incurred. Land is not depreciated.  

Any gains or losses from the divestiture of PP&E are recognized in net earnings.  

Development and Production Assets  

Development and production assets are capitalized on an area-by-area basis and include all costs associated with 
the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in 
finding  reserves  of  crude  oil,  NGLs  or  natural  gas  transferred  from  E&E  assets.  Capitalized  costs  include  directly 
attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated 
with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.  

Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved 
reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to 
crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in 
developing proved reserves. 

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial 
substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair 
value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.  

Other Upstream Assets 

Other upstream assets include information technology assets used to support the upstream business. These assets 
are  depreciated  on  a  straight-line  basis over  their  useful  lives  of  three years. Other  upstream  assets  also  include 
gross  overriding  royalty  interests  (“GORRs”)  in  certain  oil  and  gas  properties  and  are  depleted  using  a  unit-of-
production method.  

(cid:27)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
 
Refining Assets 

The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or 
otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended 
use, the associated decommissioning costs and, for qualifying assets, borrowing costs.  

Refining  assets  are  depreciated  on  a  straight-line  basis  over  the  estimated  service  life  of  each  component  of  the 
refinery. The major components are depreciated as follows:  

Land improvements and buildings 

(cid:120) 
(cid:120)  Office equipment and vehicles 
(cid:120) 

Refining equipment 

25 to 40 years 
3 to 15 years 
10 to 60 years 

The  residual  value,  the  method of  amortization  and  the  useful  life  of  each  component are reviewed  annually  and 
adjusted on a prospective basis, if appropriate.  

Other Assets 

Costs associated with the crude-by-rail terminal, infrastructure, office furniture, fixtures, leasehold improvements, 
information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated 
service lives of the assets, which range from three years to 60 years.  

The residual value, the method of amortization and the useful lives of the assets are reviewed annually and adjusted 
on a prospective basis, if appropriate.  

N) Impairment of Non-Financial Assets 

PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment quarterly or when facts and 
circumstances  suggest  that  the  carrying  amount  may  exceed  its  recoverable  amount.  Goodwill  is  tested  for 
impairment at least annually. 

If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated 
as  the  greater  of  value-in-use  (“VIU”)  and  fair  value  less  costs  of  disposal  (“FVLCOD”).  VIU  is  estimated  as  the 
present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the 
amount  that  would  be  realized  from  the  disposition  of  an  asset  or  CGU  in  an  arm’s  length  transaction  between 
knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is based on the discounted after-tax cash 
flows  of  reserves  and  resources  using  forward  prices  and  costs,  consistent  with  Cenovus’s  independent  qualified 
reserves evaluators (“IQREs”) and may consider an evaluation of comparable asset transactions.  

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing 
for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill 
is allocated to the CGUs to which it contributes to the future cash flows. 

If  the  recoverable  amount  of  the  CGU  is  less  than  the  carrying  amount,  an  impairment  loss  is  recognized.  An 
impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to 
reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed. 

Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as 
additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.  

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date 
for  any  indicators  that  the  impairment  losses  may  no  longer  exist  or  may  have  decreased.  In  the  event  that  an 
impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable 
amount,  but  only  to  the  extent  that  the  carrying  amount  does  not  exceed  the  amount  that  would  have  been 
determined  had  no  impairment  loss been  recognized  on  the  asset  in  prior periods.  The  amount of  the reversal  is 
recognized in net earnings. 

O) Leases  

The Company adopted IFRS 16, “Leases” (“IFRS 16”) on January 1, 2019 using the modified retrospective approach; 
therefore comparative periods were not restated. 

Policy Applicable From January 1, 2019 

Leases  

The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the 
use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration 
in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of 
storage tanks, the Company has elected not to separate non-lease components.  

As Lessee  

Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is 
available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value  

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:27)(cid:24)

 
 
basis. Lease liabilities include the net present value of fixed payments, costs to be incurred by the lessee in 
dismantling, removing and restoring the underlying asset, variable lease payments that are based on an index or a 
rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of purchase 
options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating the 
lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental 
borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate 
for a portfolio of leases with reasonably similar characteristics.  

Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings 
over the lease term.  

The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is 
a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount 
expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the 
Company will exercise a purchase, extension or termination option that is within the control of the Company.  

When the lease liability is remeasured, a corresponding adjustment is made to the carrying amount of the ROU asset 
or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been 
reduced to zero.  

The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct 
costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying 
asset or site on which it is located less any lease payments made at or before the commencement date.  

The ROU asset is depreciated, on a straight-line basis, over the shorter of the estimated useful life of the asset or 
the lease term. The ROU asset may be adjusted for certain remeasurements of the lease liability and impairment 
losses.  

Leases  that  have  terms  of  less  than  twelve  months  or  leases  on  which  the  underlying  asset  is  of  low  value  are 
recognized as an expense in the Consolidated Statements of Earnings (Loss) on a straight-line basis over the lease 
term. 

A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and 
if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase 
in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, 
at the effective date of the lease modification, the Company will remeasure the lease liability using the Company’s 
incremental  borrowing  rate,  when  the  rate  implicit  to  the  lease  is  not  readily  available,  with  a  corresponding 
adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing 
the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate 
decrease in scope.  

As Lessor  

As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the 
Company  transfers  substantially  all  of  the  risk  and  rewards  incidental  to  ownership  of  the  underlying  asset  are 
classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the 
net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. 
If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an 
operating lease. The Company recognizes lease payments received under operating leases as income on a straight-
line basis over the lease term as other income.  

When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. 
It  assesses  the  lease  classification  of  a  sublease  with  reference  to  the  ROU  asset  from  the  head  lease  not  with 
reference  to  the  underlying  assets.  If  the  head  lease  is  a  short-term  lease  to  which  the  Company  applies  the 
exemption for lease accounting, the sublease is classified as an operating lease. 

Policy Applicable Before January 1, 2019 

Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as 
operating  leases. Operating  lease payments  are recognized as  an  expense  on  a  straight-line  basis  over  the  lease 
term. 

Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance 
leases.  At  inception,  a  leased  asset  within  PP&E  and  a  corresponding  lease  obligation  are  recognized.  The  leased 
asset is depreciated over the shorter of the estimated useful life of the asset or the lease term. 

P) Intangible Assets 

Intangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets 
are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with 
finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the  

(cid:27)(cid:25)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated 
Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset.  

Q) Business Combinations and Goodwill 

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets 
acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at 
the  date  of  acquisition,  with  the  exception  of  income  taxes,  stock-based  compensation,  lease  liabilities  and  ROU 
assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired 
is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited 
to net earnings. 

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is 
at cost less any accumulated impairment losses. 

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition 
and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair 
value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash 
used  in  investing  activities  until  the  cumulative  payments  exceed  the  acquisition  date  fair  value  of  the  liability. 
Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. 
Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.  

When  a  business  combination  is  achieved  in  stages,  the  Company  re-measures  its  pre-existing  interest  at  the 
acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings. 

R) Provisions  

General 

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, 
that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to 
settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at 
a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks 
specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the 
Consolidated Statements of Earnings (Loss). 

Decommissioning Liabilities  

Decommissioning  liabilities  include  those  legal  or  constructive  obligations  where  the  Company  will  be  required  to 
retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the 
crude-by-rail  terminal.  The  amount  recognized  is  the  present  value  of  estimated  future  expenditures  required  to 
settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the 
liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting 
from  revisions  to  expected  timing  or  future  decommissioning  costs  are  recognized  as  a  change  in  the 
decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the 
useful life of the related asset.  

Actual expenditures incurred are charged against the accumulated liability. 

Onerous Contract Provisions 

Onerous  contract  provisions  are  recognized  when  the  unavoidable  costs  of  meeting  the  obligation  exceed  the 
economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of 
estimated  future  cash  flows  underlying  the  obligations  less  any  estimated  recoveries,  discounted  at  the  credit-
adjusted  risk-free rate. Changes  in  the  underlying  assumptions  are  recognized  in  the  Consolidated Statements of 
Earnings (Loss). 

S) Share Capital 

Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are 
recognized as a deduction from equity, net of any income taxes. 

T) Stock-Based Compensation  

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement 
rights  (“NSRs”),  performance  share  units  (“PSUs”),  restricted  share  units  (“RSUs”),  and  deferred  share  units 
(“DSUs”). Stock-based compensation costs are recorded in general and administrative expense, or E&E assets and 
PP&E when directly related to exploration or development activities. 

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Net Settlement Rights 

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-
Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-
based  compensation  costs  over  the  vesting  period,  with  a  corresponding  increase  recorded  as  paid  in  surplus  in 
Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus 
are recorded as share capital.  

Performance, Restricted and Deferred Share Units 

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market 
value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation 
costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in 
the period they occur.  

U) Financial Instruments  

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk 
management assets, net investment in finance leases, investments in the equity of private companies and long-term 
receivables.  The  Company’s  financial  liabilities  include  accounts  payable  and  accrued  liabilities,  short-term 
borrowings, lease liabilities, contingent payment, risk management liabilities and long-term debt. 

Financial  instruments  are  recognized  when  the  Company  becomes  a  party  to  the  contractual  provisions  of  the 
instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and 
intends to settle on a net basis or settle the asset and liability simultaneously.  

The  Company  characterizes  its  fair  value  measurements  into  a  three-level  hierarchy  depending  on  the  degree  to 
which the inputs are observable, as follows: 

(cid:120) 
(cid:120) 

(cid:120) 

Level 1 inputs are quoted prices in active markets for identical assets and liabilities. 
Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset 
or liability either directly or indirectly. 
Level 3 inputs are unobservable inputs for the asset or liability. 

Classification and Measurement of Financial Assets 

The initial classification of a financial asset depends upon the Company’s business model for managing its financial 
assets and the contractual terms of the cash flows. There are three measurement categories into which the Company 
classified its financial assets: 

(cid:120) 

(cid:120) 

(cid:120) 

Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to 
collect  contractual  cash  flows  and  its  contractual  terms  give  rise  on  specified  dates  to  cash  flows  that 
represent solely payments of principal and interest. 
FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting 
contractual  cash flows  and  selling  the  financial  assets,  where  its  contractual  terms give rise on  specified 
dates to cash flows that represent solely payments of principal and interest. 
Fair Value through Profit or Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost 
or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets. 

On  initial  recognition,  the Company  may  irrevocably  designate  a financial  asset  that  meets  the  amortized  cost or 
FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial 
recognition  of  an  equity  investment  that  is  not  held-for-trading,  the  Company  may  irrevocably  elect  to  present 
subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes 
to earnings following the derecognition of the investment. However, dividends that reflect a return on investment 
continue to be recognized in net earnings. This election is made on an investment-by-investment basis.  

At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset 
not  at  FVTPL,  including  transaction  costs  that  are  directly  attributable  to  the  acquisition  of  the  financial  asset. 
Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.  

Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those 
financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period 
following the change in the business model.  

A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been 
transferred and the Company has transferred substantially all the risks and rewards of ownership.  

Impairment of Financial Assets 

The  Company  recognizes  loss  allowances  for  expected  credit  losses  (“ECLs”)  on  its  financial  assets  measured  at 
amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to 
expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the 
expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured  

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as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in 
accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the 
effective interest rate of the related financial asset. The Company does not have any financial assets that contain a 
financing component.  

Classification and Measurement of Financial Liabilities  

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as 
measured  at  FVTPL  if  it  is  held-for-trading,  a  derivative,  or  designated  as  FVTPL  on  initial  recognition.  The 
classification of a financial liability is irrevocable.  

Financial  liabilities  at  FVTPL  (other  than  financial  liabilities  designated  at  FVTPL)  are  measured  at  fair  value  with 
changes  in  fair  value,  along  with  any  interest  expense,  recognized  in  net  earnings.  Other  financial  liabilities  are 
initially  measured  at  fair  value  less  directly  attributable  transaction  costs  and  are  subsequently  measured  at 
amortized  cost  using  the  effective  interest  method.  Interest  expense  and  foreign  exchange  gains  and  losses  are 
recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.  

A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial 
liability  is  replaced  by  another  from  the  same  counterparty  with  substantially  different  terms,  or  the  terms  of  an 
existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition 
of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-
substantial,  it  is  accounted  for  as  a  modification  to  the  existing financial  liability.  Where  a  liability  is  substantially 
modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference 
between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability 
is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows 
and a gain or loss is recorded in net earnings.  

Derivatives 

Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, 
foreign  currency  exchange  rates  and  interest  rates.  Policies  and  procedures  are  in  place  with  respect  to  required 
documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are 
executed,  the  Company  assesses,  both  at  the  time  of  purchase  and  on  an  ongoing  basis,  whether  the  financial 
instrument  used  in  the  particular  transaction  is  effective  in  offsetting  changes  in  fair  values  or  cash  flows  of  the 
transaction. 

Derivative  financial  instruments  are  measured  at  FVTPL  unless  designated  for  hedge  accounting.  Derivative 
instruments  that  do  not  qualify  as  hedges,  or  are  not  designated  as  hedges,  are  recorded  using  mark-to-market 
accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with 
changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of 
all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and 
forecasts. 

V) Reclassification 

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2020. 

W) Recent Accounting Pronouncements 

New Accounting Standards and Interpretations not yet Adopted 

There are new accounting standards, amendments to accounting standards and interpretations that are effective for 
annual  periods  beginning  on  or  after  January  1,  2021  and  have  not  been  applied  in  preparing  the  Consolidated 
Financial Statements for the year ended December 31, 2020. These standards and interpretations are not expected 
to have a material impact on the Company’s Consolidated Financial Statements. The standard applicable to Cenovus 
is as follows and will be adopted on its effective date: 

Interest Rate Benchmark Reform 

On  August  27,  2020,  the  IASB  published  Interest  Rate  Benchmark  Reform  –  Phase  2  (Amendments  to  IFRS  9, 
“Financial  Instruments”,  IAS 39,  “Financial  Instruments:  Recognition  and  Measurement”,  IFRS  7,  “Financial 
Instruments:  Disclosures”,  IFRS  4,  “Insurance  Contracts”  and  IFRS  16)  (“IBOR  Phase  2  Amendments”),  which 
provides clarity on the changes after the reform of an interest rate benchmark. The amendments are effective for 
annual  periods  beginning  on  or  after  January  1,  2021,  with  early  application  permitted.  The  IBOR  Phase  2 
Amendments  primarily  relate  to  the  modification  of  financial  instruments,  allowing  for  a  practical  expedient  for 
modifications  required  by  the  reform.  The  practical  expedient  for  modifications  is  accounted  for  by  updating  the 
effective interest rate without modification of the financial instrument and is subject to satisfying all qualifying criteria. 
The Company expects the IBOR Phase 2 Amendments will not have a significant impact on the Consolidated Financial 
Statements.  

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4.  CRITICAL  ACCOUNTING  JUDGMENTS  AND  KEY  SOURCES  OF  ESTIMATION 
UNCERTAINTY  

The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management 
make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and 
disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported 
amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and 
events  as  of  the  date  of  the  Consolidated  Financial  Statements.  The  estimated  fair  value  of  financial  assets  and 
liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from 
estimated amounts as future confirming events occur.  

A) Critical Judgments in Applying Accounting Policies  

Critical  judgments  are  those  judgments  made by Management  in  the  process of  applying  accounting policies  that 
have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements. 

Joint Arrangements 

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus 
holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the 
assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation 
and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial 
Statements. 

In  determining  the  classification  of  its  joint  arrangements  under  IFRS  11,  “Joint  Arrangements”,  the  Company 
considered the following: 

(cid:120) 

(cid:120) 

(cid:120) 

(cid:120) 

(cid:120) 

The intention of the joint arrangement was to form an integrated North American heavy oil business. The 
integrated  business  was  structured,  initially  on  a  tax  neutral  basis,  through  two  partnerships  due  to  the 
assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited 
life. 
The  partnership  agreements  require  the  partners  (Cenovus  and  Phillips  66  or  respective  subsidiaries)  to 
make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past 
and future development of  WRB  is dependent  on  funding from  the partners  by  way of partnership  notes 
payable and loans. 
The WRB working interest relationship is operated whereby the operating partner takes product on behalf 
of the participants and is modified to account for the operating environment of the refining business.  
Phillips 66, as the operator, either directly or through wholly-owned subsidiaries, provide marketing services, 
purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the 
agreements prohibit the partnership from undertaking these roles themselves. In addition, the partnership 
does not have employees and, as such, are not capable of performing these roles. 
In  the  arrangement,  output  is  taken  by  the  partners,  indicating  that  the  partners  have  the  rights  to  the 
economic benefits of the assets and the obligation for funding the liabilities of the arrangement. 

Exploration and Evaluation Assets 

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether 
it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and 
commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future 
operating  expenses,  as  well  as  estimated  reserves  and  resources  are  considered.  In  addition,  Management  uses 
judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are 
considered,  including  the  existence  of  reserves,  and  whether  the  appropriate  approvals  have  been  received  from 
regulatory bodies and the Company’s internal approval process. 

Identification of Cash-Generating Units 

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that 
are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation 
of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification 
include the integration between assets, shared infrastructures, the existence of common sales points, geography, 
geologic structure, and the manner in which Management monitors and makes decisions about its operations. The 
recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are 
assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses 
and reversals. 

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Determining the Lease Term 

In determining the lease term, Management considers all facts and circumstances that create an economic incentive 
to  exercise  an  extension  option,  or  not exercise  a  termination  option.  The  assessment  is  reviewed  if  a  significant 
event or a significant change in circumstances occurs which affects this assessment. 

B) Key Sources of Estimation Uncertainty 

Critical  accounting  estimates  are  those  estimates  that  require  Management  to  make  particularly  subjective  or 
complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed 
on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are 
revised. The following are the key assumptions about the future and other key sources of estimation at the end of 
the  reporting  period  that,  if  changed, could result  in  a  material  adjustment  to  the  carrying  amount of  assets  and 
liabilities within the next financial year. 

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread 
of  a  novel  strain  of  the  coronavirus  (“COVID-19”).  The  outbreak  and  subsequent  measures  intended  to  limit  the 
pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted 
global commercial activity, including significantly reducing worldwide demand for crude oil.  

The full extent of the impact of COVID-19 on the Company’s operations and future financial performance is currently 
unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and 
spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information 
that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined 
how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, 
its performance, and estimates and assumptions used by Management in the preparation of its financial results. 

The outbreak and current market conditions have increased the complexity of estimates and assumptions used to 
prepare the annual Consolidated Financial Statements, particularly related to recoverable amounts.  

In addition, the evolving worldwide demand for energy and global advancement of alternative sources of energy that 
are not sourced from fossil fuels could result in a change in assumptions used in determining the recoverable amount 
and could affect the carrying value of the related assets. The timing in which global energy markets transition from 
carbon-based sources to alternative energy is highly uncertain. 

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within 
the next financial year. 

Crude Oil and Natural Gas Reserves 

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves 
estimates  are  dependent  upon  variables  including  the  recoverable  quantities  of  hydrocarbons,  the  cost  of  the 
development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of 
the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the 
reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s 
crude oil and natural gas assets in the Oil Sands and Conventional segments. The Company’s reserves are evaluated 
annually and reported to the Company by its IQREs. 

Recoverable Amounts 

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, 
which  are  subject  to  change  as  new  information  becomes  available.  For  the  Company’s  upstream  assets,  these 
estimates  include  forward  commodity  prices,  expected  production  volumes,  quantity  of  reserves  and  resources, 
discount rates, future development and operating expenses. Recoverable amounts for the Company’s refining assets, 
crude-by-rail  terminal  and  related  ROU  assets  use  assumptions  such  as  throughput,  forward  commodity  prices, 
market crack spreads, operating expenses, transportation capacity, future capital expenditures, supply and demand 
conditions  and  the  terminal  values  used.  Recoverable  amounts  for  the  Company’s  real  estate  ROU  assets  use 
assumptions  such  as  real  estate  market  conditions  which  includes  market  vacancy  rates  and  sublease  market 
conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used 
in determining the recoverable amount could affect the carrying value of the related assets.  

Decommissioning Costs 

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining 
assets  and  crude-by-rail  terminal  at  the  end  of  their  economic  lives.  Management  uses  judgment  to  assess  the 
existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and 
cost estimates may change in response to numerous factors including changes in legal requirements, technological 
advances,  inflation  and  the  timing  of  expected  decommissioning  and  restoration.  In  addition,  Management 
determines  the  appropriate  discount rate  at  the  end of  each  reporting period.  This  discount  rate,  which  is  credit-
adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation 
and may change in response to numerous market factors. 

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Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination 

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration 
and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are 
applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions 
such  as  forward  commodity  prices,  quantity  of  reserves  and  resources,  production  costs,  Canadian-U.S.  foreign 
exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the 
net assets.  

Income Tax Provisions  

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates 
are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject 
to measurement uncertainty.  

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences 
will  be  recoverable  in  future  periods.  The  recoverability  assessment  involves  a  significant  amount  of  estimation 
including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable 
earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax 
laws.  There  are  some  transactions  for  which  the  ultimate  tax  determination  is  uncertain.  To  the  extent  that 
assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated 
Financial Statements of future periods. 

5. GENERAL AND ADMINISTRATIVE 

For the years ended December 31, 

Salaries and Benefits 

Administrative and Other 

Onerous Contract Provisions (Recovery) 

Stock-Based Compensation Expense (Note 32) 

Other Long-Term Incentive Expense (Recovery) 

6. FINANCE COSTS 

For the years ended December 31, 

Interest Expense – Short-Term Borrowings and Long-Term Debt 

Net (Discount) Premium on Redemption of Long-Term Debt (Note 24) 

Interest Expense – Lease Liabilities (Note 25) 

Unwinding of Discount on Decommissioning Liabilities (Note 27) 

Other 

7. FOREIGN EXCHANGE (GAIN) LOSS, NET 

For the years ended December 31, 

Unrealized Foreign Exchange (Gain) Loss on Translation of: 

U.S. Dollar Debt Issued From Canada 
Other 

Unrealized Foreign Exchange (Gain) Loss 
Realized Foreign Exchange (Gain) Loss 

2020       
145       
84       
18       
49       
(4 )     
292       

2020       
392       
(25 )     
87       
57       
25       
536       

2019       
143       
95       
(5 )     
67       
31       
331       

2019       
407       
(63 )     
82       
58       
27       
511       

2018   

205   

177   

629   

9   

-   

1,020   

2018   

516   

17   

-   

62   

32   

627   

2020       

2019       

2018   

(194 )     
63       
(131 )     
(50 )     
(181 )     

(800 )     
(27 )     
(827 )     
423       
(404 )     

602   
47   

649   
205   

854   

8. DIVESTITURES 

On December 2, 2020, the Company sold its Marten Hills assets in northern Alberta to Headwater Exploration Inc. 
(“Headwater”) for total consideration of $138 million, excluding the retained GORR. A before-tax gain of $79 million 
was recorded on the sale (after-tax gain – $65 million). Total consideration received consists of $33 million in cash, 
50 million common shares valued at $97 million and 15 million share purchase warrants valued at $8 million at the  

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date of close. The share purchase warrants have a three-year term and an exercise price of $2.00 per share. The 
Company retained a GORR in the Marten Hills assets which was reclassified from E&E to PP&E for $41 million on 
the date of close. The investment in Headwater is held in other assets (see Note 20).  

On September 6, 2018, the Company completed the sale of Cenovus Pipestone Partnership (“CPP”), a wholly-owned 
subsidiary, for cash proceeds of $625 million, before closing adjustments. CPP held the Company’s Pipestone and 
Wembley natural gas and liquids business in northwestern Alberta and included the Company’s 39 percent operated 
working interest in the Wembley gas plant. A before-tax loss of $797 million was recorded on the sale (after-tax – 
$557 million).  

9. OTHER (INCOME) LOSS, NET  

For the year ended December 31, 2020, the Company recorded a $100 million loss related to the Keystone XL pipeline 
project. 

The Government of Canada passed the Canada Emergency Wage Subsidy (“CEWS”) as part of its COVID-19 Economic 
Response Plan. The program is effective from March 15, 2020 to June 2021. For the year ended December 31, 2020, 
the Company recorded $40 million in other income from the CEWS program. 

For the year ended December 31, 2020, the Company recognized $24 million of lease income (2019 – $17 million). 
Lease income is earned on tank subleases, operating leases related to the Company’s real estate ROU assets in which 
Cenovus is the lessor, and from the recovery of non-lease components for operating costs and unreserved parking 
related  to  the  Company's  net  investment  in  finance  leases.  Finance  leases  are  included  in  other  assets  as  net 
investment in finance leases. The Company adopted IFRS 16 on January 1, 2019 using the modified retrospective 
approach; therefore, comparative periods were not restated. 

10. IMPAIRMENT CHARGES AND REVERSALS 

A) Cash-Generating Unit Net Impairments 

On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances 
suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.  

2020 Upstream Impairments 

During the three months ended March 31, 2020, the Company tested its upstream CGUs and CGUs with associated 
goodwill for impairment. As a result, the Company recorded an impairment loss of $315 million as additional DD&A 
in the Conventional segment due to the decline in forward crude oil and natural gas prices. As at March 31, 2020, 
there was no impairment of goodwill or Oil Sands CGUs.  

As  at  December 31, 2020,  indicators  of  impairment  were  noted  for  the  Company’s  Conventional  assets  due  to  a 
change in future development plans since the Company last tested for impairment as at March 31, 2020. Therefore, 
the Company tested its Conventional CGUs for impairment and determined that the carrying amount was greater 
than the recoverable amount for certain CGUs and recorded an additional impairment loss of $240 million as DD&A. 

For the purpose of impairment testing, goodwill is allocated to the CGU of which it relates. There was no impairment 
of goodwill as at December 31, 2020. 

The following table summarizes the year ended December 31, 2020 impairment losses and estimated recoverable 
amounts as at December 31, 2020 by CGU: 

CGU 
Clearwater 
Elmworth-Wapiti 
Kaybob-Edson 

Key Assumptions 

Impairment 

Amount     
260       
120       
175       

Recoverable 
Amount   
160   
259   
384   

The  recoverable  amounts  (Level  3)  of  Cenovus’s  upstream  CGUs  were  determined  based  on  FVLCOD.  Key 
assumptions in the determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, 
costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted 
after-tax cash flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. 
All reserves have been evaluated as at December 31, 2020 by the Company’s IQREs. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:28)(cid:22)

 
 
 
 
  
  
  
 
 
 
Crude Oil, NGLs and Natural Gas Prices 

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural 
gas reserves were: 

2021     
47.17       
44.63       
59.24       
2.88       

2022     
50.17       
48.18       
63.19       
2.80       

2023     
53.17       
52.10       
67.34       
2.71       

2024     
54.97       
54.10       
69.77       
2.75       

2025     
56.07       
55.19       
71.18       
2.80       

Average 
Annual 
Increase 
Thereafter   

2.0 % 
2.0 % 

2.0 % 

2.0 % 

WTI (US$/barrel) (1) 
WCS (C$/barrel) (2) 
Edmonton C5+ (C$/barrel) 
AECO (C$/Mcf) (3) 
(1)  West Texas Intermediate (“WTI”). 
(2)  Western Canadian Select (“WCS”).  
(3) 

Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units per thousand cubic feet (“Mcf”). 

Discount and Inflation Rates 

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based 
on the individual characteristics of the CGU, and other economic and operating factors. Inflation was estimated at 
approximately two percent. 

Sensitivities 

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would 
have had on the calculated recoverable amount in the impairment testing completed as at December 31, 2020 for 
the following CGUs:  

Increase (Decrease) to Recoverable Amount 

Clearwater 
Elmworth-Wapiti 
Kaybob-Edson 

2020 Refining Impairments  

Rate     

(5 )     
(7 )     
(13 )     

One Percent 
Increase in 
the Discount 

One Percent 
Decrease in 
the Discount 

Five Percent 
Increase in 
the Forward 
Price 

Five Percent 
Decrease in 
the Forward 
Price 
Estimates   
(97 ) 
(96 ) 
(106 ) 

Rate     

Estimates     

6       
8       
14       

52       
54       
54       

As  at  September  30,  2020,  the  recovery  in  demand  for  refined  products  from  the  impact  of  COVID-19  lagged 
expectations resulting in higher than anticipated inventory levels. These factors, along with low market crack spreads 
and crude oil processing runs for North American refineries, were identified as potential indicators of impairment for 
the Wood River and Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was determined 
to be  greater  than  the recoverable  amount  and  an  impairment  charge of $450 million was  recorded  as  additional 
DD&A  in  the  Refining  and  Marketing  segment.  The  recoverable  amount  of  the  Borger  CGU  was  estimated  at 
$692 million,  using  a  discounted  cash  flow  method  in  accordance  with  IFRS.  As  at  September  30,  2020,  no 
impairment of  the  Wood River CGU was  identified.  As  at December 31, 2020,  there  were  no further  indicators of 
impairment noted since the Company last tested as at September 30, 2020. 

Key Assumptions 

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated 
based  on  discounted  after-tax  cash  flows  using  forward  prices  and  cost  estimates.  Key  assumptions  in  the 
determination  of  future  cash  flows  included  forward  crude  oil  prices,  forward  crack  spreads,  future  capital 
expenditures, operating costs, terminal values and the discount rate. Forward crack spreads were based on quoted 
near-month contracts for WTI and spot prices for gasoline and diesel. 

Crude Oil and Forward Crack Spreads 

Forward  prices  are  based  on  Management’s  best  estimate  and  corroborated  with  third-party  data.  As  at 
September 30, 2020, the forward prices used to determine future cash flows were: 

(cid:120)  WTI forward prices used for 2021 to 2022 ranged from US$36.36 per barrel to US$50.84 per barrel and 

2023 to 2025 ranged from US$49.66 per barrel to US$58.74 per barrel. 

(cid:120)  WTI to West Texas Sour differential used for 2021 to 2022 ranged from US$0.37 per barrel to US$1.73 per 

barrel and 2023 to 2025 ranged from US$1.21 per barrel to US$1.81 per barrel. 

(cid:120)  Group 3 forward market crack spread used for 2021 to 2022 ranged from US$11.56 per barrel to US$13.23 

(cid:120) 

per barrel and 2023 to 2025 ranged from US$11.79 per barrel to US$16.58 per barrel. 
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to 
year 2035. 

(cid:28)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
  
  
  
  
  
  
 
 
Discount Rates 

Discounted  future  cash  flows  were  determined  by  applying  a  discount  rate  of  10  percent  based  on  the  individual 
characteristics of the CGU, and other economic and operating factors. 

Sensitivities  

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would 
have had on the calculated recoverable amount in the impairment testing completed as at September 30, 2020 for 
the following CGU: 

Increase (Decrease) to Recoverable Amount 

Borger 

2020 ROU Asset Impairments 

Rate     

(71 )     

One Percent 
Increase in 
the Discount 

One Percent 
Decrease in 
the Discount 

Five Percent 
Increase in 
the Forward 
Price 

Rate     

Estimates     

81       

263       

Five Percent 
Decrease in 
the Forward 
Price 
Estimates   
(264 ) 

As at March 31, 2020, the temporary suspension of the Company’s crude-by-rail program was considered to be an 
indicator  of  impairment  for  the  railcar  CGU.  As  a  result,  the  CGU  was  tested  for  impairment  and  an  impairment 
expense of $3 million was recorded as additional DD&A in the Refining and Marketing segment.  

2019 Upstream Impairments 

As at December 31, 2019, the Company tested its Conventional CGUs for impairment as there were indicators of 
impairment due to a decline in forward natural gas prices. As at December 31, 2019, there were no impairments of 
goodwill or the Company’s CGUs.  

2018 Net Upstream Impairments  

As at December 31, 2018, the Company tested its upstream CGUs for impairment. As at December 31, 2018, there 
was  no  impairment  of  goodwill  or  the  Company’s  CGUs.  However,  the  impairment  test  provided  evidence  that 
previously recognized impairment losses should be reversed.  

As at December 31, 2018, the recoverable amount of the Clearwater CGU was estimated to be $761 million. Earlier 
in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline 
in  forward prices.  The  impairment  was recorded  as  additional  DD&A  in  the  Conventional  segment  (formerly Deep 
Basin). In the fourth quarter of 2018, the Company reversed $132 million of impairment losses, net of the DD&A 
that  would  have  been  recorded  had  no  impairments  been  recorded.  The  reversal  was  due  to  improved  recovery, 
extensions and well performance and changes to the development plan. 

B) Asset Impairments and Write-downs 

Exploration and Evaluation Assets 

For the year ended December 31, 2020, $9 million and $82 million of previously capitalized E&E costs were written 
off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be 
recoverable and recorded as exploration expense.  

In 2019, $18 million and $64 million of previously capitalized E&E costs were written off in the Oil Sands segment 
and Conventional segment, respectively, as the carrying value was not considered to be recoverable and recorded as 
exploration expense.  

In 2018, Management completed a comprehensive review of the Conventional development plan, formerly known as 
Deep Basin, considering factors such as well inventory, pace of development, infrastructure constraints, economic 
thresholds  and  limited capital  spending  on  the  assets  going  forward.  As  such, previously  capitalized  E&E  costs of 
$2.1 billion were written off as exploration expense in the Elmworth, Wapiti, Kaybob, Edson and Clearwater areas 
within the Conventional segment. 

Property, Plant and Equipment, Net 

For the year ended December 31, 2020, $48 million and $4 million of previously capitalized PP&E costs were written 
off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to 
be recoverable. In addition, $52 million of previously capitalized PP&E costs relating to information technology assets 
were written off due to synergies identified as a result of the Arrangement. The impairment was recorded as additional 
DD&A in the Corporate and Eliminations segment.  

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:28)(cid:24)

 
 
  
  
  
  
 
 
11. DISCONTINUED OPERATIONS 

The results of operations from the former Conventional segment was reported as a discontinued operation.  

For  the  year  ended  December  31,  2018,  the  Company  recorded  net  earnings  from  discontinued  operations  of 
$247 million.  The  cash  flows  from  discontinued  operations  reported  in  the  Consolidated  Statement  of  Cash  Flows 
were $36 million related to cash from operating activities and $404 million related to cash from investing activities.  

On January 5, 2018, the Company completed the sale of its Suffield crude oil and natural gas operations in southern 
Alberta  for  cash  proceeds  of  $512  million,  before  closing  adjustments.  A  before-tax  gain  on  discontinuance  of 
$343 million was recorded on the sale. 

12. INCOME TAXES 

The provision for income taxes is: 

For the years ended December 31, 

Current Tax 
Canada 

United States 

Total Current Tax Expense (Recovery) 
Deferred Tax Expense (Recovery) 

Tax Expense (Recovery) From Continuing Operations 

2020       

2019       

2018   

(14 )     
1       
(13 )     
(838 )     
(851 )     

14       
3       
17       
(814 )     
(797 )     

(128 ) 

2   

(126 ) 
(884 ) 

(1,010 ) 

For the year ended December 31, 2020, a deferred tax recovery was recorded due to an impairment of the Borger 
CGU,  impairment  in  the  Conventional  segment  and  current  period  operating  losses  that  will  be  carried  forward, 
excluding  unrealized  foreign  exchange  gains  and  losses  on  long-term  debt.  In  2020,  the  Government  of  Alberta 
accelerated the reduction in the provincial corporate tax rate from 12 percent to eight percent.  

In  2019,  the  Government  of  Alberta  enacted  a  reduction  in  the  provincial  corporate  tax  rate  from  12 percent  to 
eight percent over four years. As a result, the Company recorded a deferred income tax recovery of $671 million for 
the  year  ended  December  31,  2019.  In  addition,  the  Company  recorded  a  deferred  income  tax  recovery  of 
$387 million due to an internal restructuring of the Company’s U.S. operations resulting in a step-up in the tax basis 
of the Company’s refining assets. 

In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down of 
the Conventional E&E assets and a $78 million recovery arising from an adjustment to the tax basis of the Company’s 
refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its 
interest in WRB, which due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s 
assets. The maximum recovery related to the carry back of losses to recover tax paid was reached in 2018.  

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: 

For the years ended December 31, 

Earnings (Loss) From Continuing Operations Before Income Tax 

Canadian Statutory Rate 

Expected Income Tax Expense (Recovery) From Continuing Operations 

2020     
(3,230 )     
24.0%     

(775 )     

2019     
1,397       
26.5%     

370       

Effect on Taxes Resulting From: 

Statutory and Other Rate Differences 

Non-Taxable Capital (Gains) Losses 

Non-Recognition of Capital (Gains) Losses 

Adjustments Arising From Prior Year Tax Filings 
Recognition of U.S. Tax Basis 

Alberta Corporate Rate Reduction 
Other 

Total Tax Expense (Recovery) From Continuing Operations 

19       
(42 )     
(42 )     
(8 )     
-       
(7 )     
4       
(851 )     

(52 )     
(38 )     
(39 )     
4       
(387 )     
(671 )     
16       
(797 )     

Effective Tax Rate 

26.3%     

(57.1)%     

2018   

(3,926 ) 

27.0%   

(1,060 ) 

(57 ) 

89   

87   

3   
(78 ) 

-   
6   

(1,010 ) 

25.7%   

(cid:28)(cid:25)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
 
  
  
       
       
   
  
  
  
  
  
  
  
  
       
       
   
  
  
  
  
  
  
  
  
 
 
 
The analysis of deferred income tax liabilities and deferred income tax assets is as follows: 

For the years ended December 31, 

Deferred Income Tax Liabilities 

Deferred Income Tax Liabilities to be Settled Within Twelve Months 

Deferred Income Tax Liabilities to be Settled After More Than Twelve Months 

Deferred Income Tax Assets 

Deferred Income Tax Assets to be Recovered Within Twelve Months 

Deferred Income Tax Assets to be Recovered After More Than Twelve Months 

Net Deferred Income Tax Liability 

2020     

2019   

-       
4,146       
4,146       

(88 )     
(860 )     
(948 )     
3,198       

3   

4,540   

4,543   

(113 ) 

(398 ) 

(511 ) 

4,032   

The deferred income tax assets and liabilities to be settled within twelve months represents Management’s estimate 
of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of 
the subsequent year. 

The  movement  in  deferred  income  tax  liabilities  and  assets,  without  taking  into  consideration  the  offsetting  of 
balances within the same tax jurisdiction, is: 

Deferred Income Tax Liabilities 

As at December 31, 2018 

Charged (Credited) to Earnings 

Charged (Credited) to OCI 

As at December 31, 2019 

Charged (Credited) to Earnings 

Charged (Credited) to OCI 

As at December 31, 2020 

Deferred Income Tax Assets 

As at December 31, 2018 

Charged (Credited) to Earnings 

Charged (Credited) to OCI 

As at December 31, 2019 

Charged (Credited) to Earnings 

Charged (Credited) to OCI 

As at December 31, 2020 

Risk 

PP&E     
5,450       
(927 )     
(25 )     
4,498       
(367 )     
(7 )     
4,124       

Management     
44       
(43 )     
-       
1       
(1 )     
-       
-       

Unused Tax 

Losses     

Risk 

Management     
(1 )     
-       
-       
(1 )     
(12 )     
-       
(13 )     

(357 )     
129       
3       
(225 )     
(448 )     
14       
(659 )     

Net Deferred Income Tax Liabilities 
Net Deferred Income Tax Liabilities as at December 31, 2018 

Charged (Credited) to Earnings 
Charged (Credited) to OCI 

Net Deferred Income Tax Liabilities as at December 31, 2019 

Charged (Credited) to Earnings 
Charged (Credited) to OCI 

Net Deferred Income Tax Liabilities as at December 31, 2020 

Other     
51       
(7 )     
-       
44       
(22 )     
-       
22       

Other     
(326 )     
34       
7       
(285 )     
12       
(3 )     
(276 )     

Total   

5,545   
(977 ) 

(25 ) 

4,543   

(390 ) 

(7 ) 

4,146   

Total   

(684 ) 

163   

10   

(511 ) 

(448 ) 

11   

(948 ) 

Total   
4,861   
(814 ) 
(15 ) 
4,032   
(838 ) 
4   
3,198   

The deferred income tax asset of $36 million (2019 – $nil) represents net deductible temporary differences in the 
U.S. jurisdiction which has been fully recognized, as the probability of realization is expected due to a forecasted 
taxable  income.  No  deferred  tax  liability  has  been  recognized  as  at  December  31,  2020  and  2019  on  temporary 
differences associated with investments in subsidiaries and joint arrangements where the Company can control the 
timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:28)(cid:26)

 
 
  
       
   
  
  
  
  
  
       
   
  
  
  
  
  
 
  
  
  
  
  
  
  
  
  
       
       
       
   
  
  
  
  
  
  
  
 
  
  
  
  
  
  
  
 
 
 
The approximate amounts of tax pools available, including tax losses, are: 

As at December 31, 

Canada 

United States 

2020     
6,540       
3,117       
9,657       

2019   

6,113   

2,648   

8,761   

As at December 31, 2020, the above tax pools included $1,682 million (2019 – $696 million) of Canadian federal 
non-capital losses and $1,084 million (2019 – $188 million) of U.S. federal net operating losses. These losses expire 
no earlier than 2037.  

Also  included  in  the  December  31,  2020  tax  pools  are  Canadian  net  capital  losses  totaling  $85  million  (2019 –
$188 million), which are available for carry forward to reduce future capital gains. As at December 31, 2020, net 
capital  gains  totaling  $22 million  (2019  –  $100  million  net  capital  losses)  have  been  realized,  decreasing  the  net 
capital  loss  balance  from  prior  year.  The  Company  has  not  recognized  $254 million  (2019  –  $262  million)  of  net 
capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt. 

13. PER SHARE AMOUNTS  

A) Net Earnings (Loss) Per Share – Basic and Diluted 

For the years ended December 31, 

Earnings (Loss) From: 
Continuing Operations 

Discontinued Operations 

Net Earnings (Loss) 

Basic – Weighted Average Number of Shares  
Dilutive Effect of Cenovus Net Settlement Rights 
Diluted – Weighted Average Number of Shares 

Basic and Diluted Earnings (Loss) Per Share From: ($) 

Continuing Operations 

Discontinued Operations 

2020       

2019       

2018   

(2,379 )     
-       
(2,379 )     

2,194       
-       
2,194       

1,228.9       
-       
1,228.9       

1,228.8       
0.6       
1,229.4       

(2,916 ) 

247   

(2,669 ) 

1,228.8   

0.4   

1,229.2   

(1.94 )     
-       
(1.94 )     

1.78       
-       
1.78       

(2.37 ) 

0.20   

(2.17 ) 

As at December 31, 2020, 31 million NSRs (2019 – 32 million; 2018 – 34 million) were excluded from the diluted 
weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceeded 
the market price of Cenovus’s common shares. These instruments could potentially dilute earnings per share in the 
future. For further information on the Company’s stock-based compensation plans (see Note 32). 

B) Common Share Dividend 

The Company temporarily suspended its common share dividend in response to the low global oil price environment. 
Prior to the suspension, the Company paid common share dividends of $77 million or $0.0625 per common share in 
the first quarter of 2020, all of which were paid in cash (2019 – $260 million or $0.2125 per common share; 2018 – 
$245 million or $0.20 per common share). The declaration of dividends is at the sole discretion of the Company’s 
Board of Directors and is considered quarterly. The Company’s Board of Directors declared a first quarter dividend of 
$0.0175 per common share, payable on March 31, 2021, to common shareholders of record as of March 15, 2021. 

C) Preferred Share Dividend 

Subsequent  to  the  closing of the  Arrangement  on  January 1, 2021,  the outstanding  Husky preferred  shares were 
exchanged  for  Cenovus  preferred  shares  (see  Note  39).  The  Company’s  Board  of  Directors  declared  first  quarter 
dividends for its Cenovus series 1, 2, 3, 5, and 7 first preferred shares, payable on March 31, 2021, in the amount 
of $8 million. 

14. CASH AND CASH EQUIVALENTS 

As at December 31, 

Cash 
Short-Term Investments 

2020     

368       
10       
378       

2019   

108   
78   

186   

(cid:28)(cid:27)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
 
 
  
  
       
       
   
  
  
  
  
  
       
       
   
  
  
  
  
  
       
       
   
  
       
       
   
  
  
  
  
 
  
  
  
  
 
 
 
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES 

As at December 31, 

Accruals 

Prepaids and Deposits 

Partner Advances 
Trade 

Joint Operations Receivables 

Other 

16. INVENTORIES 

As at December 31, 

Product 

Refining and Marketing 
Oil Sands 

Conventional 

Parts and Supplies 

2020     
1,053       
121       
175       
96       
35       
8       
1,488       

2019   

1,221   

54   

16   
212   

36   

17   

1,556   

2020     

2019   

613       
382       
1       
93       
1,089       

874   
570   

1   
87   

1,532   

During the year ended December 31, 2020, approximately $9,996 million of produced and purchased inventory was 
recorded as an expense (2019 – $14,285 million; 2018 – $15,664 million). 

As at March 31, 2020, the Company recorded $588 million in non-cash inventory write-downs of its crude oil blend, 
condensate and refined product inventory. Subsequently, $547 million of inventory that was written down at the end 
of  March  was  sold  and  the  loss  was  realized.  For  the  year  ended  December  31,  2020,  the  Company  reversed 
$39 million of the inventory write-downs related to March product inventory that was still on hand due to improved 
refined product and crude oil prices. As at December 31, 2020, the Company recorded a $6 million write-down in 
refined product inventory.  

As  at  December  31,  2019,  the  Company  recorded  a  $25 million  write-down  in  refined  product  inventory.  The 
inventory write-down was realized in 2020.  

17. EXPLORATION AND EVALUATION ASSETS  

As at December 31, 2018 

Additions 
Exploration Expense (Note 10) 
Change in Decommissioning Liabilities 
Exchange Rate Movements and Other 

As at December 31, 2019 

Additions 
Transfers to PP&E (Note 18) (1) 
Exploration Expense (Note 10) 
Depletion 
Change in Decommissioning Liabilities 
Divestitures (Note 8) 

As at December 31, 2020 

 (1) 

Includes the $41 million reclassification of the GORR retained in the sale of the Marten Hills assets (see Note 8). 

Total   
785   
73   
(82 ) 
9   
2   
787   
48   
(47 ) 
(91 ) 
(18 ) 
5   
(61 ) 
623   

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:28)(cid:28)

 
 
  
  
  
  
  
  
  
  
 
  
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
 
18. PROPERTY, PLANT AND EQUIPMENT, NET  

Upstream Assets 

Development 
& Production     

Other 
Upstream     

Refining 
Equipment     

Other (1)     

Total   

COST 
As at December 31, 2018 

Adjustment for Change in Accounting Policy (2)    
Additions 

Change in Decommissioning Liabilities 
Exchange Rate Movements and Other 

Divestitures (Note 8) 

As at December 31, 2019 

Additions 
Transfers From E&E Assets (Note 17) 

Change in Decommissioning Liabilities 

Exchange Rate Movements and Other 

Divestitures 

As at December 31, 2020 

ACCUMULATED DEPRECIATION, 
DEPLETION AND AMORTIZATION 

As at December 31, 2018 

Adjustment for Change in Accounting Policy (2)    
Depreciation, Depletion and Amortization 

Impairment Charges (Note 10) 

Exchange Rate Movements and Other 

Divestitures (Note 8) 

As at December 31, 2019 

Depreciation, Depletion and Amortization 

Impairment Charges (Note 10) 

Exchange Rate Movements and Other 

As at December 31, 2020 

CARRYING VALUE 

As at December 31, 2018 

As at December 31, 2019 

As at December 31, 2020 

28,046       
-       
695       
340       
(9 )     
(40 )     
29,032       
475       
6       
(11 )     
(6 )     
(3 )     
29,493       

3,918       
-       
1,735       
20       
31       
(29 )     
5,675       
1,768       
607       
(22 )     
8,028       

333       
-       
-       
-       
-       
-       
333       
-       
41       
-       
-       
-       
374       

333       
-       
-       
-       
-       
-       
333       
-       
-       
-       
333       

5,632       
(4 )     
228       
9       
(288 )     
-       
5,577       
243       
-       
3       
(152 )     
-       
5,671       

1,442       
(1 )     
241       
-       
(86 )     
-       
1,596       
242       
450       
(93 )     
2,195       

1,213       
-       
193       
5       
3       
-       
1,414       
93       
-       
2       
(1 )     
-       
1,508       

833       
-       
75       
10       
-       
-       
918       
109       
52       
-       
1,079       

35,224   

(4 ) 
1,116   

354   
(294 ) 

(40 ) 

36,356   

811   
47   

(6 ) 

(159 ) 

(3 ) 

37,046   

6,526   

(1 ) 

2,051   

30   

(55 ) 

(29 ) 

8,522   

2,119   

1,109   

(115 ) 

11,635   

24,128       
23,357       
21,465       

-       
-       
41       

4,190       
3,981       
3,476       

380       
496       
429       

28,698   

27,834   

25,411   

(1) 
(2) 

Primarily consists of crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft. 
Effective January 1, 2019, the Company adopted IFRS 16. 

PP&E includes the following amounts in respect of assets under construction and not subject to DD&A: 

As at December 31, 

Development and Production 

Refining Equipment 

2020     
1,807       
226       
2,033       

2019   

1,836   

172   

2,008   

(cid:20)(cid:19)(cid:19)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
        
        
        
  
  
  
       
       
       
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
  
       
       
       
       
   
  
       
       
       
       
   
  
  
  
  
  
  
  
  
  
  
  
  
       
       
       
       
   
  
       
       
       
       
   
  
  
  
  
  
  
  
 
 
 
 
 
19. RIGHT-OF-USE ASSETS, NET 

COST 
As at January 1, 2019 (2) 

Additions 

Terminations 
Reclassifications 

Re-measurement 
Exchange Rate Movements and Other 

As at December 31, 2019 

Additions 

Terminations 
Modifications 

Reclassifications 

Re-measurement 

Exchange Rate Movements and Other 

As at December 31, 2020 

ACCUMULATED DEPRECIATION 
As at January 1, 2019 (2) 

Depreciation 

Impairment Charges (Note 10) 

Terminations 

Exchange Rate Movements and Other 

As at December 31, 2019 

Depreciation 

Impairment Charges (Note 10) 

Terminations 

Exchange Rate Movements and Other 

As at December 31, 2020 

CARRYING VALUE 
As at January 1, 2019 (2) 
As at December 31, 2019 

As at December 31, 2020 

Real 
Estate     

Railcars 
& Barges     

Storage 
Assets (1)     

Refining 
Equipment     

Other     

Total   

517       
10       
-       
(8 )     
-       
(10 )     
509       
1       
-       
-       
(14 )     
-       
(1 )     
495       

-       
29       
3       
-       
-       
32       
27       
-       
-       
(1 )     
58       

63       
436       
-       
-       
(2 )     
(2 )     
495       
18       
-       
-       
-       
(20 )     
(13 )     
480       

-       
55       
-       
-       
-       
55       
86       
3       
-       
(13 )     
131       

292       
172       
(11 )     
-       
18       
(7 )     
464       
22       
(1 )     
1       
-       
19       
(8 )     
497       

-       
75       
-       
(1 )     
(1 )     
73       
95       
-       
(1 )     
(5 )     
162       

13       
-       
-       
-       
(2 )     
(1 )     
10       
5       
-       
-       
-       
-       
-       
15       

1       
2       
-       
-       
-       
3       
2       
-       
-       
-       
5       

9       
6       
-       
-       
-       
(1 )     
14       
7       
-       
(3 )     
-       
(1 )     
(2 )     
15       

-       
4       
-       
-       
-       
4       
5       
-       
-       
(2 )     
7       

894   

624   

(11 ) 
(8 ) 

14   
(21 ) 

1,492   
53   

(1 ) 
(2 ) 

(14 ) 

(2 ) 

(24 ) 

1,502   

1   

165   

3   

(1 ) 

(1 ) 

167   

215   

3   

(1 ) 

(21 ) 

363   

517       
477       
437       

63       
440       
349       

292       
391       
335       

12       
7       
10       

9       
10       
8       

893   

1,325   

1,139   

(1) 
(2) 

Includes caverns and tanks. 
Effective January 1, 2019, the Company adopted IFRS 16.  

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:19)(cid:20)

 
 
  
  
       
       
       
       
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
       
       
       
       
       
   
  
       
       
       
       
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
       
       
       
       
       
   
  
       
       
       
       
       
   
  
  
  
 
 
 
20. OTHER ASSETS 

As at December 31, 

Intangible Assets 

Equity Investments (Note 35A) 

Investment in Associate (Note 8) 
Net Investment in Finance Leases 

Long-Term Receivables and Prepaids 

Other 

2020     

89       
52       
97       
52       
11       
12       
313       

2019   

101   

52   

-   
30   

28   

-   

211   

In 2019, Cenovus entered into an agreement to assume a firm capacity shipper position in a pipeline transportation 
services agreement from a third party. The fee was recorded as an intangible asset at cost and will be amortized 
over the life of the contract of approximately 10 years. 

21. GOODWILL 

As at December 31, 2020 and 2019, the carrying amount of goodwill associated with the Company’s Primrose (Foster 
Creek) CGU and Christina Lake CGU was $1,171 million and $1,101 million, respectively. 

For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used 
to test Cenovus’s goodwill for impairment as at December 31, 2020 are consistent to those disclosed in Note 10. 
There was no impairment of goodwill as at December 31, 2020.  

22. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 

As at December 31, 

Accruals 

Trade 

Interest 

Partner Advances 

Employee Long-Term Incentives 

Joint Operations Payable 

Risk Management 

Onerous Contract Provisions 

Other 

2020     

912       
608       
77       
175       
130       
6       
58       
26       
26       
2,018       

2019   

1,085   

954   

49   

16   

60   

2   

2   

17   

44   

2,229   

23. SHORT-TERM BORROWINGS 

The Company has uncommitted demand facilities of $1.6 billion in place, of which $600 million may be drawn for 
general purposes, or the full amount can be available to issue letters of credit. As at December 31, 2020, no amount 
was drawn on these facilities (December 31, 2019 – $nil) and there were outstanding letters of credit aggregating to 
$441 million (December 31, 2019 – $364 million). 

WRB has uncommitted demand facilities of US$300 million (the Company’s proportionate share – US$150 million) 
available to cover short-term working capital requirements. As at December 31, 2020, US$190 million was drawn on 
these facilities, of which the Company’s proportionate share was US$95 million (C$121 million) (December 31, 2019 
– $nil). 

(cid:20)(cid:19)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
  
  
  
 
  
  
  
  
  
  
  
  
  
  
  
 
 
 
24. LONG-TERM DEBT AND CAPITAL STRUCTURE 

As at December 31, 
Revolving Term Debt (1) 
U.S. Dollar Denominated Unsecured Notes 

Total Debt Principal 
Debt Discounts and Transaction Costs 

Long-Term Debt 

Notes   

A     
B     

2020     

-       
7,510       
7,510       
(69 )     
7,441       

2019   

265   

6,492   

6,757   
(58 ) 

6,699   

(1)  Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.  

The weighted average interest rate on outstanding debt, including the Company’s proportionate share of the WRB 
uncommitted demand facilities, for the year ended December 31, 2020 was 4.9 percent (2019 – 5.1 percent).  

As at December 31, 2020, the Company is in compliance with all of the terms of its debt agreements. 

A) Committed Credit Facilities 

Cenovus has in place a committed revolving credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche 
with maturity dates of November 30, 2022 and November 30, 2023, respectively. In April 2020, the Company added 
a committed credit facility with capacity of $1.1 billion to further support the Company’s financial resilience in the 
current market environment. On December 31, 2020, the Company cancelled the $1.1 billion credit facility.  

B) U.S. Dollar Denominated Unsecured Notes  

The remaining principal amounts of the Company’s U.S. dollar denominated unsecured notes are: 

As at December 31, 

3.00% due August 15, 2022 

3.80% due September 15, 2023 

5.38% due July 15, 2025 

4.25% due April 15, 2027 

5.25% due June 15, 2037 
6.75% due November 15, 2039 
4.45% due September 15, 2042 
5.20% due September 15, 2043 
5.40% due June 15, 2047 

2020 

US$ Principal 

Amount     
500       
450       
1,000       
962       
583       
1,390       
155       
58       
800       
5,898       

Total C$ 
Equivalent     
637       
573       
1,273       
1,225       
742       
1,770       
198       
74       
1,018       
7,510       

2019 

US$ Principal 

Amount     

Total C$ 
Equivalent   

500       
450       
-       
962       
641       
1,400       
155       
58       
832       
4,998       

650   

585   

-   

1,249   

833   

1,818   

202   

75   

1,080   

6,492   

The  Company  has  in  place  a  base  shelf  prospectus  that  allows  the  Company  to  offer,  from  time  to  time,  up  to 
US$5.0 billion,  or  the  equivalent  in  other  currencies,  of  debt  securities,  common  shares,  preferred  shares, 
subscription  receipts,  warrants,  share  purchase  contracts  and  units  in  Canada,  the  U.S.  and  elsewhere  where 
permitted by law. The base shelf prospectus will expire in October 2021. Offerings under the base shelf prospectus 
are subject to market conditions. 

On July 30, 2020, Cenovus completed a public offering in the U.S., under the Company’s U.S. base shelf prospectus, 
of  senior  unsecured  notes  in  the  aggregate  principal  of  US$1.0  billion  due  in  2025.  As  at  December  31,  2020, 
US$3.7 billion is available under the base shelf prospectus for permitted offerings.  

In addition, during the year ended December 31, 2020, the Company paid US$81 million to repurchase a portion of 
its unsecured notes with a principal amount of US$100 million. A gain on the repurchase of $25 million was recorded 
in finance costs (see Note 6). 

C) Mandatory Debt Payments 

As at December 31, 2020 

2022 
2023 
2025 

Thereafter 

US$ 
Principal 
Amount     
500       
450       
1,000       
3,948       
5,898       

Total C$ 
Equivalent   

637   
573   
1,273   

5,027   

7,510   

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:19)(cid:22)

 
 
  
  
   
   
   
     
   
     
   
     
  
    
  
  
  
  
  
  
  
  
  
  
  
  
 
  
  
  
  
  
  
 
 
 
D) Capital Structure  

Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists 
of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and 
long-term  portions  of  long-term  debt,  net  of  cash  and  cash  equivalents  and  short-term  investments.  Cenovus 
conducts its business and makes decisions consistent with that of an investment grade company. The Company’s 
objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, 
ensure  its  ability  to  finance  internally  generated  growth  and  to  fund  potential  acquisitions  while  maintaining  the 
ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, 
among other actions, adjust capital and operating spending, draw down on its credit facilities or repay existing debt, 
adjust dividends paid to shareholders, repurchase the Company’s common shares for cancellation, issue new debt, 
or issue new shares.  

Cenovus  monitors  its  capital structure  and financing requirements  using,  among other  things,  non-GAAP  financial 
metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net 
Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s 
overall financial strength.  

Cenovus  targets  a  Net  Debt  to  Adjusted  EBITDA  ratio  of  less  than  2.0  times  over  the  long-term.  This  ratio  may 
periodically be above the target due to factors such as persistently low commodity prices.  

Net Debt to Adjusted EBITDA (1) 

As at December 31, 

Short-Term Borrowings 
Current Portion of Long-Term Debt 

Long-Term Debt 

Less: Cash and Cash Equivalents 

Net Debt 

Net Earnings (Loss) 

Add (Deduct): 

Finance Costs 

Interest Income 

Income Tax Expense (Recovery) 

Depreciation, Depletion and Amortization 

Exploration Expense 

Unrealized (Gain) Loss on Risk Management 

Foreign Exchange (Gain) Loss, Net 

Re-measurement of Contingent Payment 

(Gain) Loss on Discontinuance 

(Gain) Loss on Divestitures of Assets 

Other (Income) Loss, Net 

Adjusted EBITDA 

2020     
121       
-       
7,441       
(378 )     
7,184       

2019     
-       
-       
6,699       
(186 )     
6,513       

2018   

-   
682   

8,482   

(781 ) 

8,383   

(2,379 )     

2,194       

(2,669 ) 

536       
(9 )     
(851 )     
3,464       
91       
56       
(181 )     
(80 )     
-       
(81 )     
40       
606       

511       
(12 )     
(797 )     
2,249       
82       
149       
(404 )     
164       
-       
(2 )     
9       
4,143       

628   

(19 ) 

(920 ) 

2,131   

2,123   

(1,249 ) 

854   

50   

(301 ) 

795   

13   

1,436   

Net Debt to Adjusted EBITDA 

11.9x     

1.6x     

5.8x   

(1) 

IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. 

Net Debt to Capitalization 

As at December 31, 
Net Debt 
Shareholders’ Equity 

Net Debt to Capitalization 

2020     
7,184       
16,707       
23,891       
30%     

2019     
6,513       
19,201       
25,714       
25%     

2018   
8,383   
17,468   
25,851   
32%   

Cenovus  also  manages  its  Net  Debt  to  Capitalization  ratio  to  ensure  compliance  with  the  associated  covenant  as 
defined  in  its  committed  credit  facility  agreements.  Under  the  terms  of  Cenovus’s  committed  credit  facility,  the 
Company  is  required  to  maintain  a  debt  to  capitalization  ratio,  as  defined  in  the  agreements,  not  to  exceed 
65 percent. The Company is well below this limit. 

(cid:20)(cid:19)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
  
  
       
       
   
  
  
       
       
   
  
  
  
  
  
  
  
  
  
  
  
  
  
  
       
       
   
  
  
  
  
 
 
25. LEASE LIABILITIES 

Lease Liabilities, Beginning of Year 

Additions 
Interest Expense (Note 6) 
Lease Payments 
Terminations 
Modifications 
Re-measurement 
Exchange Rate Movements and Other 

Lease Liabilities, End of Year 

Less: Current Portion 
Long-Term Portion 

2020     
1,916       
49       
87       
(284 )     
(1 )     
(2 )     
(2 )     
(6 )     
1,757       

184       
1,573       

2019   
1,494   
590   
82   
(232 ) 
(11 ) 
-   
15   
(22 ) 
1,916   

196   
1,720   

The Company has lease liabilities for contracts related to office space, railcars, barges, storage assets, drilling and 
service rigs, and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a 
wide range of different terms and conditions.  

For the years ended December 31, 
Variable Lease Payments 
Short-Term Lease Payments 

2020     

16       
6       

2019   
19   
13   

The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are 
leases with terms of twelve months or less.  

The Company has included extension options in the calculation of lease liabilities where the Company has the right 
to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company does 
not have any significant termination options and the residual amounts are not material.  

26. CONTINGENT PAYMENT 

Contingent Payment, Beginning of Year 

Re-measurement (1) 
Liabilities Settled or Payable 

Contingent Payment, End of Year 

Less: Current Portion 

Long-Term Portion 

2020     

143       
(80 )     
-       
63       

36       
27       

2019   

132   

164   

(153 ) 

143   

79   

64   

(1)  Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings. 

In  connection  with  the  acquisition  (the  “Acquisition  in  2017”)  from  ConocoPhillips  Company  and  certain  of  its 
subsidiaries  (collectively, “ConocoPhillips”),  Cenovus  agreed  to  make quarterly payments  to  ConocoPhillips  during 
the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 
per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds 
$52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant production outages 
at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. There are no maximum 
payment terms. 

The contingent payment is accounted for as a financial option. The fair value is estimated by calculating the present 
value of the future expected cash flows using an option pricing model, which assumes the probability distribution for 
WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI 
and WCS futures pricing, and discounted at a credit-adjusted risk-free rate. The contingent payment is re-measured 
at fair value at each reporting date with changes in fair value recognized in net earnings. As at December 31, 2020, 
no amount was payable under this agreement (2019 – $14 million). 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:19)(cid:24)

 
 
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
 
27. DECOMMISSIONING LIABILITIES 

The  decommissioning  provision  represents  the  present  value  of  the  expected  future  costs  associated  with  the 
retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal.  

The aggregate carrying amount of the obligation is: 

Decommissioning Liabilities, Beginning of Year 

Liabilities Incurred 

Liabilities Settled 

Liabilities Disposed 
Change in Estimated Future Cash Flows 

Change in Discount Rate 

Unwinding of Discount on Decommissioning Liabilities (Note 6) 

Foreign Currency Translation 

Decommissioning Liabilities, End of Year 

2020     
1,235       
14       
(42 )     
(2 )     
13       
(28 )     
57       
1       
1,248       

2019   

875   

3   

(52 ) 

(8 ) 
21   

339   

58   

(1 ) 

1,235   

As at December 31, 2020, the undiscounted amount of estimated future cash flows required to settle the obligation 
is  $4,953 million  (2019  –  $5,173  million),  which  has  been  discounted  using  a  credit-adjusted  risk-free  rate  of 
5.0 percent (2019 – 4.9 percent) and an inflation rate of two percent (2019 – two percent). Most of these obligations 
are not expected to be paid for several years, or decades, and are expected to be funded from general resources at 
that time. The Company expects to settle approximately $40 million to $45 million of decommissioning liabilities over 
the  next year. Revisions  in  estimated future  cash flows resulted from  a  change  in  the  timing  of  decommissioning 
liabilities over the estimated life of the reserves and an increase in cost estimates. 

Sensitivities 

Changes  to  the  credit-adjusted  risk-free  rate  or  the  inflation  rate  would  have  the  following  impact  on  the 
decommissioning liabilities:  

2020 

2019 

Increase      Decrease   
332   

(236 )     
340       

(243 ) 

2019   

103   

73   

46   
19   

241   

2020     

33       
91       
39       
18       
181       

Sensitivity 
Range 

± one percent 

± one percent 

  Increase      Decrease     
313       
(235 )     

(228 )     
321       

As at December 31, 
Credit-Adjusted Risk-Free Rate 

Inflation Rate 

28. OTHER LIABILITIES 

As at December 31, 

Employee Long-Term Incentives 

Pension and Other Post-Employment Benefit Plan (Note 29) 

Onerous Contract Provisions 
Other 

(cid:20)(cid:19)(cid:25)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
  
  
  
  
  
 
  
  
  
    
  
    
    
 
  
  
  
  
  
  
 
 
 
29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS 

The  Company  provides  employees  with  a  pension  that  includes  either  a  defined  contribution  or  defined  benefit 
component and other post-employment benefit plan. Most of the employees participate in the defined contribution 
pension. Employees who meet certain criteria may elect to move from the current defined contribution component 
to a defined benefit component for their future service. 

The  defined  benefit  pension  provides  pension  benefits  at  retirement  based  on  years  of  service  and  final  average 
earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides 
certain retired employees with health care and dental benefits until age 65 and life insurance benefits. 

The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial 
regulator at least every three years. The most recently filed valuation was dated December 31, 2019 and the next 
required actuarial valuation will be as at December 31, 2022. 

A) Defined Benefit and OPEB Plan Obligation and Funded Status  

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is: 

As at December 31, 

Defined Benefit Obligation 

Defined Benefit Obligation, Beginning of Year 

Current Service Costs 
Interest Costs (1) 
Benefits Paid 

Plan Participant Contributions 

Re-measurements: 

(Gains) Losses From Experience Adjustments 

(Gains) Losses From Changes in Financial Assumptions 

Defined Benefit Obligation, End of Year 

Plan Assets 

Fair Value of Plan Assets, Beginning of Year 

Employer Contributions 

Plan Participant Contributions 

Benefits Paid 
Interest Income (1) 
Re-measurements: 

Return on Plan Assets (Excluding Interest Income) 

Fair Value of Plan Assets, End of Year 

Pension Benefits 

OPEB 

2020     

2019     

2020     

2019   

158       
13       
5       
(6 )     
2       

1       
15       
188       

107       
6       
2       
(5 )     
2       

5       
117       

167       
11       
6       
(36 )     
2       

(4 )     
12       
158       

113       
9       
2       
(35 )     
3       

15       
107       

22       
1       
-       
(2 )     
-       

(2 )     
1       
20       

-       
-       
-       
-       
-       

-       
-       

21   

1   

1   
(2 ) 

-   

-   

1   

22   

-   

-   

-   

-   

-   

-   

-   

Pension and OPEB (Liability) (2) 
(1)  Based on the discount rate of the defined benefit obligation at the beginning of the year. 
(2) 

Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets. 

(71 )     

(51 )     

(20 )     

(22 ) 

The weighted average duration of the defined benefit pension and OPEB obligations are 17.4 years and 13.3 years, 
respectively.  

B) Pension and OPEB Costs 

For the years ended December 31, 

Defined Benefit Plan Cost 

Current Service Costs 
Past Service Costs – Curtailments 
Net Interest Costs 
Re-measurements: 

Return on Plan Assets (Excluding Interest 
   Income) 
(Gains) Losses From Experience Adjustments   
(Gains) Losses From Changes in Financial 
   Assumptions 

Defined Benefit Plan Cost (Recovery) 
Defined Contribution Plan Cost 

Total Plan Cost 

Pension Benefits 

OPEB 

2020     

2019     

2018     

2020     

2019     

2018   

13       
-       
3       

(5 )     
1       

15       
27       
22       
49       

11       
-       
3       

(15 )     
(4 )     

12       
7       
21       
28       

13       
(2 )     
3       

7       
-       

-       
21       
22       
43       

1       
-       
-       

-       
(2 )     

1       
-       
-       
-       

1       
-       
1       

-       
-       

1       
3       
-       
3       

1   
-   
1   

-   

-   

(1 ) 

1   
-   

1   

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:19)(cid:26)

 
 
  
    
  
  
       
       
       
   
  
  
  
  
  
  
       
       
       
   
  
  
  
  
  
       
       
       
   
  
       
       
       
   
  
  
  
  
  
  
       
       
       
   
  
  
  
  
       
       
       
   
  
  
    
  
  
       
       
       
       
       
   
  
  
  
  
       
       
       
       
       
   
  
  
  
  
  
C) Investment Objectives and Fair Value of Plan Assets 

The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving 
consideration to the security of the assets and the potential volatility of market returns and the resulting effect on 
both  contribution  requirements  and  pension  expense.  The  long-term  return  is  expected  to  achieve  or  exceed  the 
return  from  a  composite  benchmark  comprised  of  passive  investments  in  appropriate  market  indices.  The  asset 
allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure 
to individual equity investment and credit rating categories. 

The  allocation  of  assets  between  the various  types  of  investment funds  is  monitored  regularly  and  is  re-balanced 
monthly,  if  necessary.  The  asset  allocation  structure  targets  an  investment of 25 percent  to  70  percent  in  equity 
securities,  25 percent  to  35 percent  in  fixed  income  assets,  zero percent  to  15  percent  in  real  estate  assets, 
zero percent to 10 percent in listed infrastructure assets, zero percent to 10 percent in emerging market debts and 
zero percent to 10 percent in cash and cash equivalents. 

The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change 
in the process used by the Company to manage these risks from prior periods. 

The fair value of the plan assets is: 

As at December 31, 

Equity Funds 
Fixed Income Funds 

Real Estate Funds 
Listed Infrastructure Funds 

Emerging Market Debt Funds 

Non-Invested Assets 

Cash and Cash Equivalents 

2020     

58       
35       
6       
8       
7       
1       
2       
117       

2019   

59   
35   

-   
9   

-   

2   

2   

107   

Fair value of the equity, fixed income and listed infrastructure assets are based on the trading price of the underlying 
funds (Level 1). The fair value of the real estate fund reflects the appraisal valuation for each property investment 
(Level 2). The fair value of the non-invested assets is the discounted value of the expected future payments (Level 3). 

The defined benefit plan does not hold any direct investment in Cenovus shares.  

D) Funding  

The  defined  benefit  pension  is  funded  in  accordance  with  federal  and  provincial  government  pension  legislation, 
where  applicable.  Contributions  are  made  to  trust funds  administered by  an  independent  trustee.  The  Company’s 
contributions  to  the  defined  benefit  pension  plan  are  based  on  the  most  recent  actuarial  valuation  as  at 
December 31, 2019, and direction of the Management Pension Committee and Human Resources and Compensation 
Committee of the Board of Directors. 

Employees participating in the defined benefit pension are required to contribute four percent of their pensionable 
earnings,  up  to  an  annual  maximum,  and  the  Company provides  the balance  of  the funding  necessary  to  ensure 
benefits  will  be  fully  provided  for  at  retirement.  The  expected  employer  contributions  for  the  year  ended 
December 31, 2021 are $10 million for the defined benefit pension plan. The OPEB is funded on an as required basis.  

E) Actuarial Assumptions and Sensitivities  

Actuarial Assumptions  

The  principal  weighted  average  actuarial  assumptions  used  to  determine  benefit  obligations  and  expenses  are  as 
follows: 

For the years ended December 31, 

Discount Rate 
Future Salary Growth Rate 
Average Longevity (years) 
Health Care Cost Trend Rate 

Pension Benefits 
2019      
3.00 %     
3.94 %     
88.2        
N/A      

2020      
2.50 %     
3.97 %     
88.3        
N/A      

OPEB 

2018      
3.50 %     
3.88 %     
88.2        
N/A        

2020      
2.50 %     
4.94 %     
88.2        
6.00 %     

2019      
3.00 %     
5.08 %     
88.2        
6.00 %     

2018   

3.50 % 
5.08 % 
88.1   

6.00 % 

The  discount  rates  are  determined  with  reference  to  market  yields  on  high  quality  corporate  debt  instruments  of 
similar duration to the benefit obligations at the end of the reporting period.  

(cid:20)(cid:19)(cid:27)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
  
  
  
  
 
  
     
  
  
  
  
 
 
 
Sensitivities 

The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is: 

As at December 31, 

One Percent Change: 

Discount Rate 
Future Salary Growth Rate 

Health Care Cost Trend Rate 

One Year Change in Assumed Life Expectancy 

2020 

2019 

Increase     

Decrease     

Increase     

Decrease   

(31 )     
4       
1       
4       

40       
(4 )     
(1 )     
(4 )     

(25 )     
3       
1       
3       

32   
(3 ) 

(1 ) 
(3 ) 

The sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, 
the  changes  in  some  assumptions  may  be  correlated.  The  same  methodologies  have  been  used  to  calculate  the 
sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied when calculating 
the defined benefit pension liability recorded on the Consolidated Balance Sheets. 

F) Risks  

Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity 
risk, interest rate risk, investment risk and salary risk. 

Longevity Risk 

The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality 
of plan participants both during and after their employment. An increase in the life expectancy of participants will 
increase the defined benefit plan obligation.  

Interest Rate Risk 

A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially 
offset by an increase in the return on debt holdings. 

Investment Risk 

The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference 
to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to 
the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than 
in debt instruments and real estate. 

Salary Risk  

The  present  value  of  the  defined  benefit  plan  obligation  is  calculated  by  reference  to  the  future  salaries  of  plan 
participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation. 

30. SHARE CAPITAL 

A) Authorized 

Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not 
exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second 
preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s 
Board of Directors prior to issuance and subject to the Company’s articles. Prior to the close of the Arrangement, 
Cenovus’s articles were amended effective December 30, 2020 to create the Cenovus series 1, 2, 3, 4, 5, 6, 7 and 8 
first preferred shares.  

B) Issued and Outstanding  

As at December 31, 

Outstanding, Beginning of Year 

Common Shares Issued Under Stock Option Plan (Note 32) 

Outstanding, End of Year 

2020 

Number of 
Common 
Shares 
(thousands)     
   1,228,828       
42       
   1,228,870       

2019 

Number of 
Common 
Shares 
(thousands)     
1,228,790       

38     

1,228,828       

Amount     
11,040       
-       
11,040       

Amount   

11,040   
-   

11,040   

There were no preferred shares outstanding as at December 31, 2020 (2019 – nil). 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:19)(cid:28)

 
 
  
    
  
  
       
       
       
   
  
  
  
  
 
  
    
  
  
 
 
 
As at December 31, 2020, there were 27 million (2019 – 26 million) common shares available for future issuance 
under the stock option plan.  

Subsequent to December 31, 2020, the Company issued common shares and first preferred shares in connection to 
the Arrangement that closed on January 1, 2021 (see Note 39). 

C) Paid in Surplus 

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) 
under the plan of arrangement into two independent energy companies, Encana (now known as Ovintiv Inc.) and 
Cenovus  (pre-arrangement  earnings).  In  addition,  paid  in  surplus  includes  stock-based  compensation  expense 
related to the Company’s NSRs discussed in Note 32A. 

As at December 31, 2018 

Stock-Based Compensation Expense 

As at December 31, 2019 

Stock-Based Compensation Expense 

As at December 31, 2020 

Pre-
Arrangement 

Earnings     
4,086       
-       
4,086       
-       
4,086       

Stock-Based 
Compensation     
281       
10       
291       
14       
305       

31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) 

As at December 31, 2018 

Other Comprehensive Income (Loss), Before Tax 

Income Tax 

As at December 31, 2019 

Other Comprehensive Income (Loss), Before Tax 

Income Tax 

As at December 31, 2020 

Defined 
Benefit 

Private 
Equity 

Pension Plan     

Instruments     

Foreign 
Currency 
Translation 
Adjustment     

(7 )     
6       
(1 )     
(2 )     
(10 )     
2       
(10 )     

15       
14       
(2 )     
27       
-       
-       
27       

1,030       
(228 )     
-       
802       
(44 )     
-       
758       

Total   

4,367   

10   

4,377   
14   

4,391   

Total   

1,038   

(208 ) 

(3 ) 

827   

(54 ) 

2   

775   

32. STOCK-BASED COMPENSATION PLANS  

A) Employee Stock Option Plan 

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to 
purchase a common share of the Company. Option exercise prices approximate the market value for the common 
shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted 
after  one  year,  an  additional  30  percent  of  the  number  granted  after  two  years  and  are  fully  exercisable  after 
three years. Options expire after seven years.  

Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising 
the option, gives the option holder the right to receive the number of common shares that could be acquired with 
the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of 
the option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the 
excess of the market price received from the sale of the common shares over the exercise price of the option. 

The NSRs vest and expire under the same terms and conditions as the underlying options. 

(cid:20)(cid:20)(cid:19)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
  
  
  
  
  
  
 
 
  
  
  
  
  
  
  
  
 
 
 
Net Settlement Rights 

The weighted average unit fair value of NSRs granted during the year ended December 31, 2020 was $2.27 before 
considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was 
estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as 
follows:  

Risk-Free Interest Rate 
Expected Dividend Yield 
Expected Volatility (1) 
Expected Life (years) 
(1) 

Expected volatility has been based on historical share volatility of the Company and comparable industry peers. 

The following tables summarize information related to the NSRs: 

1.19 % 
1.77 % 
29.74 % 
5.00   

For the year ended December 31, 2020 

Outstanding, Beginning of Year 

Granted 
Exercised 

Forfeited 
Expired 

Outstanding, End of Year 

As at December 31, 2020 
Range of Exercise Price ($) 
5.00 to 9.99 

10.00 to 14.99 

15.00 to 19.99 

20.00 to 24.99 

25.00 to 29.99 

30.00 to 34.99 

Number of 
NSRs 

(thousands)     
31,528       
5,783       
(42 )     
(416 )     
(6,256 )     
30,597       

Weighted 
Average 
Exercise 
Price ($)   
22.61   

11.73   
9.48   

23.52   
32.60   

18.52   

Outstanding NSRs 

Exercisable NSRs 

Number of 
NSRs 

(thousands)     
2,796       
12,921       
2,691       
3,078       
8,540       
571       
30,597       

Weighted 
Average 
Remaining 
Contractual 
Life (years)     
4.2       
5.2       
2.3       
1.1       
0.1       
0.5       
2.9       

Weighted 
Average 
Exercise 
Price ($)     
9.48       
12.27       
19.47       
22.26       
28.37       
32.27       
18.52       

Number of 
NSRs 

(thousands)     
1,596       
4,189       
2,691       
3,078       
8,540       
571       
20,665       

Weighted 
Average 
Exercise 
Price ($)   
9.48   

13.53   

19.47   

22.26   

28.37   

32.27   

21.94   

The Arrangement on January 1, 2021 resulted in the accelerated vesting of outstanding NSRs held by non-executive 
employees  and  certain  non-executive  officers  of  the  Company.  In  accordance  with  their  terms,  2,738  thousand 
additional NSRs vested and were exercisable as a result of the accelerated vesting on January 1, 2021. 

B) Performance Share Units 

Cenovus  has granted  PSUs  to  certain  employees  under  its Performance  Share Unit  Plan  for  Employees.  PSUs  are 
time-vested whole-share units that entitle employees to receive, upon vesting, either a common share of Cenovus 
or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible to vest is determined 
by  a  multiplier  that  ranges  from  zero  percent  to  200  percent  and  is  based  on  the  Company  achieving  key  pre-
determined performance measures. PSUs vest after three years.  

The Company has recorded a liability of $65 million as at December 31, 2020 (2019 – $53 million) in the Consolidated 
Balance  Sheets  for  PSUs  based  on  the  market  value  of  Cenovus’s  common  shares  at  the  end  of  the  year.  The 
Arrangement  on  January  1,  2021  resulted  in  the  accelerated  vesting  of  outstanding  PSUs  held  by  non-executive 
employees and certain non-executive officers of the Company. As a result, the intrinsic value was $51 million as at 
December 31, 2020. In accordance with their terms, 7,055 thousand PSUs will be settled, in cash, subsequent to 
December 31, 2020 based on the 30-day volume weighted average trading price prior to the date of closing. The 
intrinsic value of vested PSUs was $nil as at December 31, 2019.  

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:20)(cid:20)

 
 
 
  
  
  
  
  
  
  
  
  
  
 
  
    
  
  
  
  
  
  
  
  
  
 
 
 
The following table summarizes the information related to the PSUs held by Cenovus employees: 

For the year ended December 31, 2020 
Outstanding, Beginning of Year 

Granted 
Vested and Paid Out 
Cancelled 
Units in Lieu of Dividends 
Outstanding, End of Year 

C) Restricted Share Units 

Number of 
PSUs 
(thousands)   
6,912   
3,846   
(1,223 ) 
(449 ) 
198   
9,284   

Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-
share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment 
equal to the value of a Cenovus common share. RSUs generally vest after three years. 

RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s 
common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting 
period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period they occur. 

The Company has recorded a liability of $61 million as at December 31, 2020 (2019 – $63 million) in the Consolidated 
Balance  Sheets  for  RSUs  based  on  the  market  value  of  Cenovus’s  common  shares  at  the  end  of  the  year.  The 
Arrangement on January 1, 2021 resulted in the accelerated vesting of outstanding RSUs held by employees and 
certain  non-executive  officers  of  the  Company.  As  a  result,  the  intrinsic  value  was  $60  million  as  at 
December 31, 2020. In accordance with their terms, 8,237 thousand RSUs will be settled, in cash, subsequent to 
December 31, 2020 based on the 30-day volume weighted average trading price prior to the date of closing. The 
intrinsic value of vested RSUs was $nil as at December 31, 2019. 

The following table summarizes the information related to the RSUs held by Cenovus employees: 

For the year ended December 31, 2020 
Outstanding, Beginning of Year 

Granted 
Vested and Paid Out 
Cancelled 
Units in Lieu of Dividends 
Outstanding, End of Year 

D) Deferred Share Units 

Number of 
RSUs 
(thousands)   
8,372   
2,686   
(2,606 ) 
(234 ) 
212   
8,430   

Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which 
are equivalent in value to a common share of the Company. Eligible employees have the option to convert either 
zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance 
with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of 
directorship or employment. 

The Company has recorded a liability of $10 million as at December 31, 2020 (2019 – $16 million) in the Consolidated 
Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic 
value  of  vested  DSUs  equals  the  carrying  value  as  DSUs  vest  at  the  time  of  grant.  In  connection  with  the 
Arrangement, the termination of a DSU holder that is a Cenovus director or employee will result in the settlement 
and redemption of DSUs, in cash based on the five day volume weighted average trading price prior to the date of 
redemption, in accordance with the terms of the related DSU Plan. 

The  following  table  summarizes  the  information  related  to  the  DSUs  held  by  Cenovus  directors,  officers  and 
employees: 

For the year ended December 31, 2020 
Outstanding, Beginning of Year 

Granted to Directors 
Granted 
Units in Lieu of Dividends 
Redeemed 

Outstanding, End of Year 

(cid:20)(cid:20)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

Number of 
DSUs 
(thousands)   
1,237   
288   
30   
33   
(255 ) 
1,333   

 
 
  
  
  
  
  
  
 
  
  
  
  
  
  
 
  
  
  
  
  
  
 
 
 
E) Total Stock-Based Compensation 

For the years ended December 31, 

Net Settlement Rights 

Performance Share Units 

Restricted Share Units 

Deferred Share Units 

Stock-Based Compensation Expense 
Stock-Based Compensation Costs Capitalized 

33. EMPLOYEE SALARIES AND BENEFIT EXPENSES 

For the years ended December 31, 

Salaries, Bonuses and Other Short-Term Employee Benefits 
Post-Employment Benefits 

Stock-Based Compensation Expense (Note 32) 
Other Long-Term Incentive Benefits 

Termination Benefits 

2020       
11       
19       
23       
(4 )     
49       
16       
65       

2020     
605       
33       
49       
(4 )     
9       
692       

2019       
9       
15       
34       
9       
67       
20       
87       

2019     
567       
29       
67       
31       
6       
700       

2018   

6   

(6 ) 

9   

-   

9   
4   

13   

2018   

580   
30   

9   
-   

63   

682   

Stock-based compensation includes the costs recorded during the year associated with NSRs, PSUs, RSUs and DSUs. 

34. RELATED PARTY TRANSACTIONS 

Key Management Compensation 

Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and 
Vice-Presidents. The compensation paid or payable to key management is: 

For the years ended December 31, 

Salaries, Director Fees and Short-Term Benefits 

Post-Employment Benefits 

Stock-Based Compensation 

Other Long-Term Incentive Benefits 

Termination Benefits 

2020     
21       
3       
15       
1       
6       
46       

2019     
24       
2       
22       
1       
-       
49       

2018   

20   

3   

5   

-   

9   

37   

Post-employment benefits represent the present value of future pension benefits earned during the year.  

35. FINANCIAL INSTRUMENTS 

Cenovus’s  financial  assets  and  financial  liabilities  consist  of  cash  and  cash  equivalents,  accounts  receivable  and 
accrued revenues, net investment in finance leases, accounts payable and accrued liabilities, risk management assets 
and  liabilities,  investments  in  the  equity  of  private  companies,  long-term  receivables,  lease  liabilities,  contingent 
payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of 
derivative financial instruments. 

A) Fair Value of Non-Derivative Financial Instruments  

The  fair  values  of  cash  and  cash  equivalents,  accounts  receivable  and  accrued  revenues,  accounts  payable  and 
accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of 
these instruments. 

The fair values of long-term receivables and net investment in finance leases approximate their carrying amounts 
due to the specific non-tradeable nature of these instruments. 

Long-term debt is carried at amortized cost. The estimated fair value of long-term debt has been determined based 
on the period-end trading prices on the secondary market (Level 2). As at December 31, 2020, the carrying value of 
Cenovus’s  long-term  debt  was  $7,441 million  and  the  fair  value  was  $8,608 million  (2019  carrying  value  – 
$6,699 million; fair value – $7,610 million). 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:20)(cid:22)

 
 
  
  
  
  
  
  
  
  
  
 
  
  
  
  
  
  
  
 
  
  
  
  
  
  
  
 
 
Equity investments classified at FVOCI comprise equity investments in private companies. The Company classifies 
certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective 
of  the  Company’s  operations.  These  assets  are  carried  at  fair  value  on  the  Consolidated  Balance  Sheets  in  other 
assets. Fair value is determined based on recent private placement transactions (Level 3) when available. 

The following table provides a reconciliation of changes in the fair value of private equity investments classified at 
FVOCI: 

Fair Value, Beginning of Year 
Change in Fair Value (1) 

Fair Value, End of Year 

(1)  Changes in fair value are recorded in OCI. 

2020     

2019   

52       
-       
52       

38   

14   

52   

B) Fair Value of Risk Management Assets and Liabilities  

The Company’s risk management assets and liabilities consist of crude oil swaps, futures, natural gas futures, and if 
entered into, crude oil options, condensate futures and swaps, foreign exchange swaps, interest rate swaps and cross 
currency interest rate swaps. Crude oil, condensate and, if entered into, natural gas contracts are recorded at their 
estimated fair value based on the difference between the contracted price and the period-end forward price for the 
same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated 
to the end of the term of the contract (Level 2). The fair value of foreign exchange swaps are calculated using external 
valuation  models  which  incorporate  observable  market  data,  including  foreign  exchange  forward  curves  (Level 2) 
and the fair value of interest rate swaps are calculated using external valuation models which incorporate observable 
market data, including interest rate yield curves (Level 2). The fair value of cross currency interest rate swaps are 
calculated  using  external valuation  models which  incorporate  observable market data,  including  foreign exchange 
forward curves (Level 2) and interest rate yield curves (Level 2).  

Summary of Unrealized Risk Management Positions 

As at December 31, 

Crude Oil, Natural Gas and Condensate 

2020 

2019 

Risk Management 

Asset      Liability     

5       

58       

Net     
(53 )     

Risk Management 
Liability     

Asset     

5       

2       

Net   

3   

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at 
fair value: 

As at December 31, 

Level 2 – Prices Sourced From Observable Data or Market Corroboration 

2020     

(53 )     

2019   

3   

Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using 
active quotes and in part using observable, market-corroborated data. 
The following table summarizes the changes in the fair value of Cenovus’s risk management assets and liabilities: 

Fair Value of Contracts, Beginning of Year 

Fair Value of Contracts Realized During the Year 
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered 
   Into During the Year 
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts 

Fair Value of Contracts, End of Year 

2020     

3       
252       

(308 )     
-       
(53 )     

2019   

160   

7   

(156 ) 

(8 ) 

3   

Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on 
a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities 
when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk 
management positions are subject to an enforceable master netting arrangement or similar agreement that are not 
otherwise offset. 

(cid:20)(cid:20)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
    
  
  
    
  
  
 
  
 
  
  
  
  
  
  
 
 
 
The following table provides a summary of the Company’s offsetting risk management positions: 

As at December 31, 

Asset      Liability     

Net     

2020 

Risk Management 

2019 

Risk Management 
Liability     

Asset     

Recognized Risk Management Positions 

Gross Amount 

Amount Offset 

Net Amount per Consolidated Financial 

Statements 

70       
(65 )     

123       
(65 )     

(53 )     
-       

13       
(8 )     

10       
(8 )     

5       

58       

(53 )     

5       

2       

Net   

3   

-   

3   

The  derivative  liabilities  do  not  have  credit  risk-related  contingent  features.  Due  to  credit  practices  that  limit 
transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to 
changes in the credit risk of financial liabilities is immaterial. 

Cenovus  pledges  cash  collateral  with  respect  to  certain  of  these  risk  management  contracts,  which  is  not  offset 
against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk 
management  contracts  as  commodity  prices  change.  Additional  cash  collateral  is  required  if,  on  a  net  basis,  risk 
management  payables  exceed  risk  management  receivables  on  a  particular  day.  As  at  December  31,  2020, 
$59 million was pledged as cash collateral (2019 – $nil). 

C) Fair Value of Contingent Payment 

The  contingent  payment  is  carried  at  fair  value  on  the  Consolidated  Balance  Sheets.  Fair  value  is  estimated  by 
calculating the present value of the expected future cash flows using an option pricing model (Level 3), which assumes 
the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian to U.S. foreign 
exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 
2.0 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which 
consists  of  individuals  who  are  knowledgeable  and  have  experience  in  fair  value  techniques.  As  at 
December 31, 2020, the fair value of the contingent payment was estimated to be $63 million (2019 – $143 million). 

As  at  December  31,  2020,  average  WCS  forward  pricing  for  the  remaining  term  of  the  contingent  payment  is 
$42.93 per  barrel.  The  average  implied  volatility  of  WTI  options  and  the  Canadian  to  U.S.  foreign  exchange  rate 
options  used  to  value  the  contingent  payment  were  35.6 percent  and  6.8  percent,  respectively.  Changes  in  the 
following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted 
in an unrealized gain (loss) impacting earnings before income tax as follows: 

As at December 31, 2020 

WCS Forward Prices 

WTI Option Volatility 

Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility 

As at December 31, 2019 

WCS Forward Prices 

WTI Option Volatility 

Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility 

Sensitivity Range    

± $5.00 per barrel 

± five percent 

± five percent 

Sensitivity Range    

± $5.00 per barrel 

± five percent 

± five percent 

Increase     
(41 )     
(18 )     
7       

Increase     
(129 )     
(45 )     
10       

Decrease   

32   

17   

(10 ) 

Decrease   

80   

42   

(19 ) 

D) Earnings Impact of (Gains) Losses From Risk Management Positions 

For the years ended December 31, 
Realized (Gain) Loss (1) 
Unrealized (Gain) Loss (2) 
(Gain) Loss on Risk Management From Continuing Operations 

2020       
252       
56       
308       

2019       
7       
149       
156       

2018   

1,554   

(1,249 ) 

305   

(1)  Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.  
(2)  Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:20)(cid:24)

 
 
  
    
  
  
    
  
  
       
       
       
       
       
   
  
  
  
 
 
    
    
    
  
  
      
        
  
    
    
    
 
  
  
  
  
 
 
36. RISK MANAGEMENT 

Cenovus  is  exposed  to  financial  risks,  including  market risk  related  to  commodity  prices,  foreign exchange rates, 
interest rates as well as credit risk and liquidity risk.  

To manage exposure to interest rate volatility, the Company may periodically enter into interest rate swap contracts. 
To  mitigate  the  Company’s  exposure  to  foreign  exchange  rate  fluctuations,  the  Company  periodically  enters  into 
foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters 
into cross currency interest rate swaps. As at December 31, 2020, there were no interest rate, foreign exchange or 
cross currency interest rate swap contracts outstanding. 

To manage exposure to commodity price movements between when products are produced or purchased and when 
sold to the customer or used by Cenovus, the Company may periodically enter into financial positions as a part of 
ongoing operations to market the Company’s production and physical inventory positions of crude oil and condensate 
volumes. The Company has entered into risk management positions to help capture the incremental margin expected 
to be received in future periods at the time products will be sold. To mitigate overall exposure to the fluctuations in 
commodity  prices,  the  Company  may  also  enter  into  financial  positions  to  protect  the  near-term  and  future  cash 
flows. As at December 31, 2020, the fair value of financial positions was a net liability of $53 million and primarily 
consisted of crude oil and condensate instruments. 

Net Fair Value of Risk Management Positions 

As at December 31, 2020 

Crude Oil and Condensate Contracts 

WTI Fixed - Sell 
WTI Fixed - Buy 
Other Financial Positions (4) 

Total Fair Value 

Notional  
Volumes (1) (2) 

Terms (3) 

Weighted 
Average Price (1) (2)   

19.6 MMbbls     
January 2021 - June 2022     
11.7 MMbbls      February 2021 - June 2022     

US$43.99/bbl       
US$44.55/bbl       

Fair Value 
Asset 
(Liability)   

(113 ) 
59   
1   
(53 ) 

(1)   Million barrels (“MMbbls”). Barrel (“bbl”). 
(2)   Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average 

price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.  

(3)   Contract terms represents averages for various individual contracts with different terms and range from one to twenty-three months. 
(4)   Other financial positions consist of risk management positions related to WCS and condensate differential contracts, Belvieu and natural gas fixed 

contracts and the Company’s Refining and Marketing segment. 

A) Commodity Price Risk 

Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value 
or  future  cash  flows  of  financial  assets  and  liabilities.  To  partially  mitigate  exposure  to  commodity  price  risk,  the 
Company has entered into various financial derivative instruments.  

The use of these derivative instruments is governed under formal policies and is subject to limits established by the 
Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes. 

Crude  Oil  –  The  Company  has  used  commodity  futures  and  swaps,  basis  price  risk  management  contracts,  and 
costless collars to partially mitigate its exposure to the commodity price risk on its crude oil sales and to protect both 
near-term and future cash flows. Cenovus has entered into a number of transactions to help protect against widening 
light/heavy  crude  oil  price  differentials  and  to  manage  exposure  to  commodity  price  movements  between  when 
products are produced or purchased and when sold to the customer or used by Cenovus. In addition, the Company 
has entered into risk management positions to help mitigate the risk to incremental margin expected to be received 
in future periods at the time products will be sold. 

Condensate  –  The  Company  has  used  commodity  futures  and  swaps,  as  well  as  basis  price  risk  management 
contracts to partially mitigate its exposure to the commodity price risk on its condensate purchases. 

Natural  Gas  –  The  Company  has  used  fixed  price  and  basis  instruments  to  partially  mitigate  its  natural  gas 
commodity price risk. 

(cid:20)(cid:20)(cid:25)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
     
     
       
   
     
     
       
     
     
       
 
 
Sensitivities 

The  following  table  summarizes  the  sensitivity  of  the  fair  value  of  Cenovus’s  risk  management  positions  to 
independent  fluctuations  in  commodity  prices,  with  all  other  variables  held  constant.  Management  believes  the 
fluctuations identified in the table below are a reasonable measure of volatility.  

The impact of fluctuating commodity prices on the Company’s open risk management positions could have resulted 
in unrealized gains (losses) impacting earnings before income tax as follows: 

As at December 31, 2020 

Sensitivity Range 

Crude Oil Commodity Price  ± US$5.00 per bbl Applied to WTI and Condensate Hedges 

Crude Oil Differential Price  ± US$2.50 per bbl Applied to Differential Hedges Tied to Production    

As at December 31, 2019 

Sensitivity Range 

Crude Oil Commodity Price  ± US$5.00 per bbl Applied to WTI and Condensate Hedges 
Crude Oil Differential Price  ± US$2.50 per bbl Applied to Differential Hedges Tied to Production    

Increase     
(44 )     
(2 )     

Decrease   

44   

2   

Increase     

Decrease   

3       
5       

(3 ) 
(5 ) 

B) Foreign Exchange Risk 

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash 
flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange 
rate between the U.S./Canadian dollar can have a significant effect on reported results.  

As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains 
and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2020, Cenovus had 
US$5,898 million in U.S. dollar debt issued from Canada (2019 – US$4,998 million). In respect of these financial 
instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change 
to the foreign exchange (gain) loss as follows: 

For the years ended December 31, 

$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate 

$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate 

2020     

300       
(300 )     

2019   

250   

(250 ) 

C) Interest Rate Risk 

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. 
Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both 
fixed  and floating  rate  debt. To  manage  exposure  to  interest  rate volatility,  the  Company  periodically  enters  into 
interest rate swap contracts. As at December 31, 2020, Cenovus had no interest rate swap contracts outstanding 
(2019  –  $nil).  To  manage  interest  costs  on  short-term  borrowings,  the  Company  periodically  enters  into  cross 
currency interest rate swaps. As at December 31, 2020, Cenovus had no cross currency interest rate swap contracts 
outstanding (2019 – $nil). 

As at December 31, 2020, the increase or decrease in net earnings for a one percent change in interest rates on 
floating rate debt amounts to $1 million (2019 – $3 million; 2018 – $nil). This assumes the amount of fixed and 
floating debt remains unchanged from respective balance sheet dates. 

D) Credit Risk 

Credit  risk  arises  from  the  potential  that  the  Company  may  incur  a  financial  loss  if  a  counterparty  to  a  financial 
instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in 
place a Credit Policy approved by the Audit Committee and the Board of Directors designed to ensure that its credit 
exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy. 
The  Credit  Policy  outlines  the  roles  and  responsibilities  related  to  credit  risk,  sets  a  framework  for  how  credit 
exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.  

Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on 
an  ongoing  basis.  A  substantial  portion  of  Cenovus’s  accounts  receivable  are  with  customers  in  the  oil  and  gas 
industry  and  are  subject  to  normal  industry  credit  risks.  Cenovus’s  exposure to  its  counterparties  is  within  credit 
policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, net 
investment in finance leases, risk management assets, and long-term receivables is the total carrying value. 

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:20)(cid:26)

 
 
  
  
  
    
        
  
  
 
  
  
 
 
 
 
As at December 31, 2020, approximately 98 percent of the Company’s accruals, joint operations, trade receivables 
and  net  investment  in  finance  leases  were  with  investment  grade  counterparties  (2019  –  97  percent),  and  as  at 
December 31, 2020  and  2019,  substantially  all  of  the  Company’s  accounts  receivable  were  outstanding  less  than 
60 days. The average expected credit loss on the Company’s accruals, joint operations, trade receivables and net 
investment  in  finance  leases  was  0.5 percent  as  at  December 31, 2020  (2019  –  0.3  percent).  As  at 
December 31, 2020,  Cenovus  had  one  counterparty  (2019  –  one  counterparty)  whose  net  settlement  position 
individually accounted for more than 10 percent of the fair value of the Company’s accruals, joint operations, trade 
receivables and net investment in finance leases.  

E) Liquidity Risk 

Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. 
Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. 
Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate 
access  to credit,  which  may be  impacted by  the  Company’s credit ratings. As  disclosed  in  Note 24, over  the  long 
term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt 
position.  

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and 
cash equivalents, cash from operating activities, undrawn capacity on its committed credit facility and uncommitted 
demand  facilities  as  well  as  availability  under  its  base  shelf  prospectus.  As  at  December  31,  2020,  Cenovus  had 
$378 million in cash and cash equivalents, $4.5 billion available on its committed credit facility, $1.1 billion available 
on its uncommitted demand facilities, of which $600 million may be drawn for general purposes, or the full amount 
can be available to issue letters of credit. A further US$55 million representing the Company’s available proportionate 
share  of  the  WRB  uncommitted  demand  facilities  is  available.  In  addition,  Cenovus  has  unused  capacity  of 
US$3.7 billion under its base shelf prospectus, the availability of which is dependent on market conditions.  

On January 1, 2021, with the close of the Arrangement, Cenovus obtained access to additional sources of capital 
(see Note 39).  
Undiscounted cash outflows relating to financial liabilities are: 

Less than 1 

Year      Years 2 and 3      Years 4 and 5     
-       
-       
1,966       
-       
365       

-       
-       
1,965       
28       
445       

2,018       
121       
385       
36       
254       

Less than 1 

Year      Years 2 and 3      Years 4 and 5     
-       
1,465       
-       
410       

-       
1,338       
69       
466       

2,229       
344       
79       
277       

Thereafter     
-       
-       
8,627       
-       
1,412       

Thereafter     
-       
9,326       
-       
1,544       

Total   

2,018   

121   

12,943   

64   

2,476   

Total   

2,229   

12,473   

148   

2,697   

As at December 31, 2020 

Accounts Payable and Accrued Liabilities 
Short-Term Borrowings (1) 
Long-Term Debt (1) 
Contingent Payment (2) 
Lease Liabilities (1) 

As at December 31, 2019 

Accounts Payable and Accrued Liabilities 
Long-Term Debt (1) 
Contingent Payment (2) 
Lease Liabilities (1) 
(1) 
(2)  Refer to Note 35C for fair value assumptions.  

Principal and interest, including current portion. 

(cid:20)(cid:20)(cid:27)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
  
  
  
  
     
          
          
          
          
  
  
  
  
  
 
 
37. SUPPLEMENTARY CASH FLOW INFORMATION 

The following table provides a reconciliation of liabilities to cash flows arising from financing activities: 

For the years ended December 31, 
Interest Paid 
Interest Received 

Income Taxes Paid 

2020     
381       
5       
18       

2019     
457       
12       
17       

2018   

564   
19   

116   

The following table provides a reconciliation of cash flows arising from financing activities: 

As at December 31, 2017 

Changes From Financing Cash Flows: 

Repayment of Long-Term Debt 
Net Issuance (Repayment) of Revolving Long-Term Debt 

Dividends Paid 
Non-Cash Changes: 

Dividends Declared 
Foreign Exchange (Gain) Loss 

Finance Costs 

As at December 31, 2018 

Adjustment for Change in Accounting Policy (1) 
Changes From Financing Cash Flows: 

Dividends Paid 

Repayment of Long-Term Debt 

Net Issuance (Repayment) of Revolving Long-Term Debt 

Principal Repayment of Leases 

Non-Cash Changes: 

Dividends Declared 

Foreign Exchange (Gain) Loss 

Gain on Repurchase of Debt and Amortization of Debt Issuance Costs   

Lease Additions 

Re-measurement of Lease Liabilities 

Lease Terminations 

Other 

As at December 31, 2019 

Changes From Financing Cash Flows: 

Dividends Paid 

Issuance (Repayment) of Short-Term Borrowings 

Issuance of Long-Term Debt 

Repayment of Long-Term Debt 

Net Issuance (Repayment) of Revolving Long-Term Debt 

Principal Repayment of Leases 

Non-Cash Changes: 

Dividends Declared 

Foreign Exchange (Gain) Loss 

Gain on Repurchase of Debt and Amortization of Debt Issuance Costs   
Lease Additions 
Lease Terminations 

Lease Modifications 
Re-measurement of Lease Liabilities 
Other 

As at December 31, 2020 

(1) 

Effective January 1, 2019, the Company adopted IFRS 16. 

Dividends 

Payable     
-       

Short-Term 
Borrowings     
-       

Long-Term 

Debt     
9,513       

(1,144 )     
(20 )     
-       

-       
817       
(2 )     
9,164       
-       

-       
(2,279 )     
276       
-       

-       
(399 )     
(63 )     
-       
-       
-       
-       
6,699       

-       
-       
1,326       
(112 )     
(220 )     
-       

-       
(231 )     
(20 )     
-       
-       
-       
-       
(1 )     
7,441       

Lease 
Liabilities   

-   

-   
-   

-   

-   
-   

-   

-   
1,494   

-   

-   

-   

(150 ) 

-   

(23 ) 

-   

590   

15   

(11 ) 

1   

1,916   

-   

-   

-   

-   

-   

(197 ) 

-   

(6 ) 

-   
49   
(1 ) 

(2 ) 
(2 ) 
-   

1,757   

-       
-       
(245 )     

245       
-       
-       
-       
-       

(260 )     
-       
-       
-       

260       
-       
-       
-       
-       
-       
-       
-       

(77 )     
-       
-       
-       
-       
-       

77       
-       
-       
-       
-       
-       
-       
-       
-       

-       
-       
-       

-       
-       
-       
-       
-       

-       
-       
-       
-       

-       
-       
-       
-       
-       
-       
-       
-       

-       
117       
-       
-       
-       
-       

-       
4       
-       
-       
-       
-       
-       
-       
121       

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:20)(cid:28)

 
 
 
  
  
  
 
  
  
  
       
       
       
   
  
  
  
  
       
       
       
   
  
  
  
  
  
       
       
       
   
  
  
  
  
  
       
       
       
   
  
  
  
  
  
  
  
  
       
       
       
   
  
  
  
  
  
  
  
       
       
       
   
  
  
  
  
  
  
  
  
 
 
 
38. COMMITMENTS AND CONTINGENCIES 

A) Commitments 

Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding 
agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts 
recorded in the Consolidated Balance Sheets. 

As at December 31, 2020 
Transportation and Storage (1) 
Real Estate (2) 
Capital Commitments 
Other Long-Term Commitments 
Total Payments (3) 

1 Year      2 Years      3 Years      4 Years      5 Years     Thereafter     

Total   
954        1,341        1,444        1,107        15,537        21,397   
797   

3   
322   
   1,153        1,037        1,411        1,517        1,175        16,226        22,519   

36       
2       
45       

38       
-       
32       

41       
-       
32       

44       
-       
24       

604       
-       
85       

   1,014       
34       
1       
104       

As at December 31, 2019 
Transportation and Storage (1) 
Real Estate (2) 
Other Long-Term Commitments 
Total Payments (3) 
(1) 

1 Year      2 Years      3 Years      4 Years      5 Years     Thereafter     
1,005       
35       
104       
1,144       

1,026       
38       
36       
1,100       

1,456       
39       
34       
1,529       

959       
36       
44       
1,039       

Total   
1,381        15,672        21,499   
852   

354   
1,451        16,442        22,705   

662       
108       

42       
28       

Includes transportation commitments of $14 billion (2019 – $13 billion) that are subject to regulatory approval or have been approved, but are not 
yet in service. Terms are up to 20 years subsequent to the date of commencement.  

(2)  Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed 

payments for which a provision has been provided. 

(3)  Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest.  

Transportation and storage commitments include future commitments relating to storage tank leases of $31 million, 
that have not yet commenced. 

As at December 31, 2020, there were outstanding letters of credit aggregating to $441 million issued as security for 
performance under certain contracts (2019 – $364 million). 

In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 36 
and commitments related to the Arrangement are disclosed in Note 39. 

B) Contingencies 

Legal Proceedings 

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus 
believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have 
a material effect on its Consolidated Financial Statements.  

Decommissioning Liabilities 

Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded 
a  liability  of  $1,248 million,  based  on  current  legislation  and  estimated  costs,  related  to  its  upstream  properties, 
refining  facilities  and  the  crude-by-rail  terminal.  Actual  costs  may  differ  from  those  estimated  due  to  changes  in 
legislation and changes in costs. 

Income Tax Matters 

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates 
are continually changing. As a result, there are usually a number of tax matters under review. Management believes 
that the provision for taxes is adequate. 

Contingent Payment 

In connection with the Acquisition in 2017, Cenovus agreed to make quarterly payments to ConocoPhillips during the 
five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per 
barrel  during  the  quarter.  As  at  December  31,  2020,  the  estimated  fair  value  of  the  contingent  payment  was 
$63 million (2019 – $143 million) (see Note 26). 

(cid:20)(cid:21)(cid:19)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
 
  
  
  
  
     
          
          
          
          
          
          
  
  
  
  
  
 
 
39. SUBSEQUENT EVENT 

Cenovus and Husky Combine to Create a New Integrated Energy Company 

A) Summary of the Acquisition 

On October 25, 2020, Cenovus announced that it had entered into a definitive agreement to combine with Husky. 
The transaction was accomplished through a plan of arrangement pursuant to which Cenovus acquired all the issued 
and outstanding common shares of Husky in exchange for common shares and common share purchase warrants of 
Cenovus. In addition, all of the issued and outstanding Husky preferred shares were exchanged for Cenovus preferred 
shares with substantially identical terms. The Arrangement closed on January 1, 2021. 

The Arrangement will combine oil sands and heavy oil assets with extensive transportation, storage and logistics and 
downstream infrastructure, creating opportunities to optimize the margin captured across the heavy oil value chain. 
The  combined  company will  be  largely  integrated, reducing  exposure  to  Alberta  heavy oil  price  differentials  while 
maintaining exposure to global commodity prices.  

The  Arrangement  was  accounted  for  using  the  acquisition  method  pursuant  to  IFRS  3,  “Business  Combinations”. 
Under  the  acquisition  method,  assets  and  liabilities  are  measured  at  their  estimated  fair  value  on  the  date  of 
acquisition with the exception of income tax, stock-based compensation, lease liabilities and ROU assets. The total 
consideration was allocated to the tangible and intangible assets acquired and liabilities assumed.  

B) Purchase Price Allocation 

Cenovus acquired all the issued and outstanding Husky common shares in consideration for the issuance of 0.7845 
Cenovus common shares plus 0.0651 Cenovus warrants for each Husky common share. Cenovus issued 788.5 million 
Cenovus common shares with a fair value of $6.1 billion, based on the December 31, 2020 closing share price of 
$7.75, as reported on the TSX. In addition, 65.4 million common share purchase warrants were issued. Each whole 
warrant entitles the holder to acquire one Cenovus common share for a period of five years at an exercise price of 
$6.54  per  share.  The  fair  value  of  the  warrants  was  estimated  to  be  $216  million.  Cenovus  also  acquired  all  the 
issued  and  outstanding  Husky  preferred  shares  in  exchange  for  36.0  million  Cenovus  first  preferred  shares  with 
substantially  identical  terms  and  a  fair  value  of  $519  million.  The  outstanding  Husky  stock  options  were  also 
exchanged  for  Cenovus  replacement  stock  options.  Each  replacement  stock  option  entitles  the  holder  to  acquire 
0.7845 of a Cenovus common share at an exercise price per share of a Husky stock option divided by 0.7845. The 
fair value of the replacement stock options was estimated to be $9 million.  

The  preliminary  purchase  price  allocation  is  based  on  Management’s  best  estimate  of  the  assets  acquired  and 
liabilities assumed. Upon finalizing the value of net assets acquired, adjustments may be required.  

The following table summarizes the details of the consideration and the recognized amounts of assets acquired and 
liabilities assumed at the date of the acquisition.  

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:21)(cid:20)

 
 
 
 
As at 

Consideration 

Common Shares 
Preferred Shares 
Share Purchase Warrants 
Replacement Stock Options 
Non-Controlling Interest 

Total Consideration and Non-Controlling Interest 

Identifiable Assets Acquired and Liabilities Assumed 

Cash 
Restricted Cash 
Accounts Receivable and Accrued Revenues 
Inventories 
Property, Plant and Equipment, Intangible Assets and Deferred Income Tax Assets 
Right-of-Use Assets 
Long-Term Income Tax Receivable 
Other Assets 
Investments in Joint Ventures 
Accounts Payable and Accrued Liabilities 
Income Tax Payable 
Current Portion of Long-Term Debt 
Long-Term Debt 
Lease Liabilities 
Decommissioning Liabilities 
Other Liabilities 

Total Identifiable Net Assets 

January 1, 
2021   

6,111   
519   
216   
9   
11   
6,866   

735   
164   
1,272   
1,118   
15,227   
1,137   
202   
200   
457   
(2,224 ) 
(59 ) 
(40 ) 
(6,602 ) 
(1,447 ) 
(2,835 ) 
(439 ) 
6,866   

The fair value of trade and other receivables acquired as part of the acquisition is $1.1 billion, with a gross contractual 
amount of $1.2 billion. As of the acquisition date, the best estimate of the contractual cash flows not expected to be 
collected is $36 million.  

Cenovus  incurred  $29  million  of  acquisition  related  costs,  excluding  common  share,  preferred  share  and  warrant 
issuance  costs.  These  costs  have  been  included  in  transaction  costs  in  the  Consolidated  Statements  of  Earnings 
(Loss).  

C) Liquidity and Commitments 

Subsequent to the closing of the Arrangement on January 1, 2021, Cenovus obtained access to additional sources of 
liquidity including: $735 million in cash, $3.7 billion available on Husky’s committed credit facilities and $508 million 
available on Husky’s uncommitted demand facilities. Husky’s committed credit facilities have a capacity of $4.0 billion 
and  its  uncommitted  demand  facilities  have  a  capacity  of  $975  million,  of  which  $850  million  may  be  drawn  for 
general purposes, or the full amount can be available to issue letters of credit.  

The  Arrangement  resulted  in  the  assumption  of  Husky’s  non-cancellable  contracts  and  other  commercial 
commitments.  As  at  January  1,  2021,  total  commitments  assumed  by  Cenovus  were  $18.7  billion,  of  which 
$7.4 billion  were  for  various  transportation  and  storage  commitments.  Transportation  commitments  include 
$1.7 billion that are subject to regulatory approval or have been approved but are not yet in service. 

D) Segmented Disclosures 

Management  is  in  the  process  of  finalizing  the  determination  of  the  operating  and  reporting  segments  for  the 
Company. It is anticipated that the Company’s business will be conducted predominately through an upstream and 
downstream segment. Management continues to evaluate how the segments may be presented and will make a final 
determination during the first quarter of 2021. 

The upstream business is anticipated to be reported as follows: 

(cid:120)  Oil  Sands,  includes  the  development  and  production  of  heavy  oil  and  bitumen  in  northeast  Alberta  and 
Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise and Tucker oil sands 
projects, as well as Lloydminster Thermal and Cold and Enhanced Oil Recovery assets. 

(cid:120) 

Conventional,  includes  the  operations  from  conventional  oil  and  natural  gas  production,  including 
processing operations in the Deep Basin and other parts of Western Canada. 

(cid:120)  Offshore, includes the offshore operations, exploration and development activities in the Asia Pacific region 

and Atlantic Canada region.  

(cid:20)(cid:21)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
  
  
   
  
   
  
  
  
  
  
  
  
  
   
  
   
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
 
The downstream business is anticipated to be reported as follows: 

(cid:120) 

Canadian  Manufacturing,  includes  Cenovus’s  owned  and  operated  upgrader  and  asphalt  refinery  in 
Lloydminster, the owned and operated crude-by-rail terminal and two ethanol plants.  

(cid:120)  Retail, includes the Canadian retail, commercial and wholesale channels.  

(cid:120)  U.S.  Manufacturing,  includes  the  U.S.  operations  of  wholly  owned  refineries  in  Lima  and  Superior,  the 
jointly  owned  Wood  River  and  Borger  refineries  with  operator  Phillips  66  and  the  jointly  owned  Toledo 
refinery with BP Products North America Inc. as operator.  

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:21)(cid:22)

 
 
 
SUPPLEMENTAL INFORMATION (unaudited)     

Financial Statistics (1)
($ millions, except per share amounts)

Revenues

Gross Sales

Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations

Less: Royalties
Total Revenues

Operating Margin (2)

Oil Sands
Conventional

Refining and Marketing
Total Operating Margin

Adjusted Funds Flow (3)
Total Cash From (Used in) Operating Activities

Deduct (Add Back):

Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital (4)

Total Adjusted Funds Flow (4) 
Total Per Share - Basic (4)
Total Per Share - Diluted (4)

Earnings

Total Operating Earnings (Loss) (5) 

Total Per Share - Diluted

Total Net Earnings (Loss)

Total Per Share - Basic and Diluted

Net Capital Investment (6)

Oil Sands

Foster Creek 
Christina Lake
Other Oil Sands
Total Oil Sands

Conventional  
Refining and Marketing
Corporate
Total Capital Investment
Acquisitions
Divestitures
Net Acquisition and Divestiture Activity 
Net Capital Investment

Year

Q4

Q3

Q2

         Q1

2020

7,514
635
6,051

(609)
364
13,227

Year

1,113
196
1,309

(388)
921

Year

273

(72)
198
147
0.12
0.12

Year

(2,604)

(2.12)

(2,379)

(1.94)

2,227
184
1,345

(187)
143
3,426

Q4

616
82
698
(73)
625

Q4

250

(14)
(77)
341
0.28
0.28

Q4

(551)

(0.45)

(153)

(0.12)

2,195
156
1,569
(108)
153
3,659

2020

Q3

638
30
668
(74)
594

2020

Q3

732

(10)
328
414
0.34
0.34

2020

Q3

(452)

(0.37)

(194)

(0.16)

2020

Year

Q4

Q3

Q2

         Q1

193
162
72
427
78
276
60
841
18
(38)
(20)
821

36
45
9
90
39
104
9
242
8
(36)
(28)
214

32
27
6
65
12
65
6
148
4
(1)
3
151

36
31
11
78
11
46
12
147
-
(1)
(1)
146

89
59
46
194
16
61
33
304
6
-
6
310

2019

         Q1

     Year

Q2

         Q1

(834)

125

3,285

1,065
133
1,088
(91)
21
2,174

Q2

125
32
157
134
291

2,027
162
2,049
(223)
47
3,968

(266)
52
(214)
(375)
(589)

(9)
(363)
(462)
(0.38)
(0.38)

(39)
310
(146)
(0.12)
(0.12)

Q2

         Q1

(414)

(0.34)

(235)

(0.19)

(1,187)

(0.97)

(1,797)

(1.46)

2019
     Year

10,838
691
10,513
(689)
1,173
20,180

3,481
242
3,723
737
4,460

2019
     Year

(84)
(333)
3,702
3.01
3.01

2019
     Year

456

0.37

2,194

1.78

2019
     Year

243
362
51
656
103
280
137
1,176
13
(5)
8
1,184

Free Funds Flow

(4)(7)

Operating Margin (2)

)
s
n
o

i
l
l
i

m
$
(

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

0

Free 
Funds 
Flow 
Deficit

2020                                                                            

2019

Adjusted Funds Flow

(3)(4)

Capital Investment

Free Funds 
Flow

)
s
n
o

i
l
l
i

m
$
(

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

0

-500

Oil Sands                                                   Conventional

Refining & Marketing

2020

2019

(1)

(2)

(3)

(4)

(5)

(6)

(7)

We renamed our Deep Basin segment to Conventional segment in the first quarter of 2020. For a description of our operations, refer to the Reportable Segments section of the Management's Discussion and Analysis.

Operating Margin is an additional subtotal found in Note 1 of the Interim and Annual 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, inventory write-downs (reversals), 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.

Adjusted Funds Flow is a non-GAAP measure commonly 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 (Used in) Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable, inventory (excluding
inventory write-downs and reversals), income tax receivable, accounts payable and income tax payable. Net change in other assets and liabilities is composed of site restoration costs and pension funding.

The comparative periods have been reclassified to conform with current period treatment of non-cash inventory write-downs (reversals).

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, revaluation gain (loss), 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.

In the first quarter of 2020, our new resource play, Marten Hills was reclassified from the Oil Sands segment to the Conventional segment. The comparative information has been reclassified.

Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.

(cid:20)(cid:21)(cid:23)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

         
         
           
           
           
         
            
            
              
              
              
              
         
         
           
           
           
         
           
           
            
              
            
            
            
            
              
                
                
           
       
         
           
           
           
         
         
            
              
              
            
           
            
              
                
                
                
              
         
            
              
              
            
           
           
             
              
              
            
              
            
            
              
              
            
           
            
            
              
            
              
           
             
             
              
                
              
              
            
             
              
            
              
            
            
            
              
            
            
           
           
           
             
           
           
             
           
           
             
           
           
             
 
        
           
            
            
          
              
          
          
           
           
           
             
        
           
            
            
          
           
          
          
           
           
           
             
            
              
                
                
                
              
            
              
                
                
                
              
              
                 
                 
                
                
                
            
              
                
                
              
              
              
              
                
                
                
              
            
            
                
                
                
              
              
                 
                 
                
                
              
            
            
              
              
              
           
              
                 
                 
                  
                 
                
             
             
                
                
                  
                
             
             
                 
                
                 
                 
            
            
              
              
              
           
 
 
SUPPLEMENTAL INFORMATION (unaudited)     

Financial Statistics (continued) (1)

Financial Metrics (Non-GAAP Measures)  (2)

Net Debt to Adjusted EBITDA

Return on Capital Employed

Return on Common Equity

Income Tax & Exchange Rates

Effective Tax Rates Using:

Net Earnings
Operating Earnings, Excluding Divestitures

Foreign Exchange Rates (US$ per C$1)

Average

Period End

Common Share Information

Common Shares Outstanding (millions) 

Period End 
Average - Basic
Average - Diluted
Dividends ($ per share) 

Closing Price - TSX (C$ per share)
Closing Price - NYSE (US$ per share)

Share Volume Traded (millions)

Operating Statistics - Before Royalties

Upstream Production Volumes

Crude Oil and Natural Gas Liquids (bbls/d) 

Oil Sands

Foster Creek
Christina Lake

Conventional
Crude Oil
Natural Gas Liquids (3)

Total Liquids Production

Natural Gas (MMcf/d)
Conventional (4)

Total Production (4)(5) (BOE per day)

Selected Average Benchmark Prices

Crude Oil Prices (US$/bbl)

Brent
West Texas Intermediate ("WTI")
Differential Brent - WTI
Western Canadian Select at Hardisty ("WCS")

WCS (C$)
Differential WTI - WCS
Mixed Sweet Blend
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
West Texas Sour ("WTS")
Differential WTI - WTS

Refining Margins 3-2-1 Crack Spreads (6) (US$/bbl)

Chicago
Group 3

Natural Gas Prices

AECO 7A Monthly Index (C$/Mcf)  (7)
NYMEX (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)

Year

11.9x

(8)%

(13)%

Q4

11.9x

(8)%

(13)%

2020

Q3

8.3x

(7)%

(12)%

2020

Q2

         Q1

6.0x

(5)%

(10)%

3.1x

2%

2%

Year

Q4

Q3

Q2

         Q1

26.3%
24.5%

2019
     Year

1.6x

10%

12%

2019
     Year

(57.1)%
39.8%

0.746
0.785

0.768
0.785

0.751
0.750

0.722
0.734

0.744
0.705

0.754
0.770

Year

Q4

Q3

Q2

         Q1

2020

1,228.9
1,228.9
1,228.9
0.0625

7.75
6.04
5,644.5

1,228.9
1,228.9
1,228.9
-

7.75
6.04
1,419.0

1,228.9
1,228.9
1,228.9
-

5.19
3.89
854.4

2020

1,228.9
1,228.9
1,228.9
-

6.35
4.67
1,831.6

1,228.9
1,228.9
1,228.9
0.0625

2.84
2.02
1,539.5

Year

Q4

Q3

Q2

         Q1

163,210
218,513

381,723

7,244
19,513

26,757
408,480

158,068
222,625

380,693

6,229
18,358

24,587
405,280

164,954
220,983

385,937

7,554
18,297

25,851
411,788

166,032
207,157

373,189

6,541
20,320

26,861
400,050

163,820
223,216
387,036

8,662
21,104
29,766
416,802

2019
     Year

1,228.8
1,228.8
1,229.4
0.2125

13.20
10.15
2,711.7

2019
     Year

159,598
194,659
354,257

4,911
21,762
26,673
380,930

379

369

360

392

471,740

467,202

471,799

465,415

395
482,594

424
451,680

Year

Q4

Q3

Q2

         Q1

     Year

2020

 2019 

43.21
39.40
3.81
26.80
35.59
12.60
34.07
37.16
2.24
39.37
0.03

7.54
8.67

2.24
2.08
0.40

45.24
42.66
2.58
33.36
43.41
9.30
38.59
42.54
0.12
43.02
(0.36)

7.05
7.57

2.77
2.66
0.56

43.37
40.93
2.44
31.84
42.41
9.09
37.42
37.55
3.38
40.96
(0.03)

7.89
8.29

2.15
1.98
0.36

33.27
27.85
5.42
16.38
22.42
11.47
21.71
22.30
5.55
28.03
(0.18)

6.44
7.92

1.91
1.72
0.35

50.96
46.17
4.79
25.64
34.11
20.53
38.59
46.28
(0.11)
45.47
0.70

8.79
10.91

2.14
1.95
0.33

64.18
57.03
7.15
44.27
58.77
12.76
52.15
52.86
4.17
56.27
0.76

16.00
16.67

1.62
2.63
1.41

Benchmark Prices

Production from Continuing Operations

)
l
b
b
/
$
S
U

(

65

60

55

50

45

40

35

30

25

20

15

Brent

WTI
Condensate

WCS

)
d
/
s
l
b
b
(

450,000

400,000

350,000

300,000

250,000

200,000

150,000

100,000

50,000

0

2,500

2,000

1,500

1,000

500

0

)
d
/
f
c

M
M

(

Q3 2019

Q4 2019

Q1 2020

Q2 2020

Q3 2020

Q4 2020

Crude Oil

NGLs

2020                     

2019 

Natural Gas

(1)

(2)

(3)

(4)

(5)

(6)

(7)

We renamed our Deep Basin segment to Conventional segment in the first quarter of 2020. For a description of our operations, refer to the Reportable Segments section of the Management's Discussion and Analysis.

•
• 

• 
•

Net Debt includes the Company's short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments.
Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, revaluation gain, re-measurement gains (losses) on contingent payment, goodwill
impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve-
month basis. 
Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders' equity plus average debt.
Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders' equity.

Natural gas liquids include condensate volumes.

Includes production used for internal consumption by the Oil Sands segment of 344 MMcf per day and 336 MMcf per day for the three and twelve months ended December 31, 2020, respectively (336 MMcf per day and 320 MMcf
per day for the three and twelve months ended December 31, 2019, respectively).

Natural gas volumes have been converted to barrels of oil equivalent ("BOE") on the basis of six thousand cubic feet ("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 to 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.

The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI
based crude oil feedstock prices and on a last in, first out accounting basis (“LIFO”).

Alberta Energy Company ("AECO") natural gas monthly index.

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:21)(cid:24)

         
         
           
           
           
           
         
         
           
           
           
           
      
      
        
        
        
      
      
        
        
        
       
                 
                  
                  
         
         
           
           
             
             
             
           
           
           
             
             
             
           
      
      
           
        
        
        
     
     
       
       
       
       
     
     
       
       
       
       
     
     
       
       
       
       
         
         
           
           
           
           
       
       
         
         
         
         
       
       
         
         
         
         
     
     
       
       
       
       
            
            
              
              
              
              
     
     
       
       
       
       
         
         
           
           
           
           
         
         
           
           
           
           
           
           
             
             
             
             
         
         
           
           
           
           
         
         
           
           
           
           
         
           
             
           
           
           
         
         
           
           
           
           
         
         
           
           
           
           
           
           
             
             
           
             
         
         
           
           
           
           
           
          
           
           
             
             
           
           
             
             
             
           
           
           
             
             
           
           
           
           
             
             
             
             
           
           
             
             
             
             
           
           
             
             
             
             
SUPPLEMENTAL INFORMATION (unaudited)     

Operating Statistics - Before Royalties (continued) (1)

Effective Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)

Oil Sands (2)

Foster Creek
Christina Lake

Conventional

Crude Oil
Natural Gas Liquids
Natural Gas 

Year

Q4

Q3

Q2

         Q1

2020

2019
     Year

7.9%
14.4%

5.9%
16.6%

7.4%
13.4%

16.0%
18.0%

11.7%
9.5%

18.8%
21.6%

11.6%
12.2%
4.8%

9.2%
21.9%
2.1%

10.9%
38.3%
13.5%

14.2%
(9.2)%
2.5%

13.0%
(4.9)%
1.5%

16.3%
3.9%
1.1%

Netbacks
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined
as gross sales less royalties, transportation and blending, and operating expenses divided by sales volumes. Netbacks do not reflect the non-cash write-downs or reversals of product inventory until the product is sold. The crude oil
sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback
calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual
Management's Discussion and Analysis.

The Oil Sands and Conventional netbacks are calculated on a gross basis and exclude adjustments for the natural gas that is produced by the Conventional segment and used as fuel by the Oil Sands segment. The consolidated
netback is calculated on a net basis, after adjustments for natural gas produced by the Conventional segment and used as fuel by the Oil Sands segment.

Oil Sands Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Heavy Oil - Foster Creek (3) ($/bbl) 

Sales Price 
Royalties
Transportation and Blending
Operating 
Netback 

Heavy Oil - Christina Lake (3) ($/bbl) 

Sales Price 
Royalties
Transportation and Blending
Operating 
Netback 

Total Heavy Oil - Oil Sands (3) ($/bbl) 

Sales Price 
Royalties
Transportation and Blending
Operating 
Netback

Conventional Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Total Conventional (3)(4) ($/BOE) 

Sales Price 
Royalties
Transportation and Blending
Operating 
Netback 

Operations Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Total Operations (3)(4) ($/BOE) 

Sales Price 
Royalties
Transportation and Blending
Operating 
Netback 

Realized Gain (Loss) on Risk Management
Sales (4) ($/BOE)

Refinery Operations (5)
Crude Oil Capacity (Mbbls/d) 

Crude Oil Runs (Mbbls/d)

Heavy Oil
Light/Medium

Crude Utilization
Refined Products (Mbbls/d)

2019
     Year

57.21
8.44
11.70
9.14
27.93

50.91
9.42
6.64
7.33
27.52

53.78
8.97
8.94
8.15
27.72

2019
     Year

17.95
0.83
2.31
8.79
6.02

2019
     Year

50.63
8.23
8.51
7.87
26.02

2019
     Year

Year

Q4

Q3

Q2

         Q1

2020

30.80
1.57
11.05
9.24
8.94

27.04
2.90
6.95
6.79
10.40

28.64
2.34
8.70
7.84
9.76

41.52
1.89
9.74
10.34
19.55

37.20
5.07
6.55
7.50
18.08

39.02
3.73
7.90
8.70
18.69

41.51
2.44
8.59
9.04
21.44

38.44
4.27
6.78
6.53
20.86

39.67
3.54
7.51
7.53
21.09

14.28
0.56
11.32
8.33
(5.93)

11.22
1.00
6.19
6.52
(2.49)

12.64
0.80
8.56
7.36
(4.08)

27.05
1.47
14.37
9.28
1.93

18.87
1.01
8.18
6.62
3.06

22.35
1.21
10.81
7.75
2.58

Year

Q4

Q3

Q2

         Q1

2020

17.84
1.23
2.46
8.99
5.16

21.63
1.65
2.28
8.34
9.36

18.28
2.95
2.62
9.55
3.16

2020

14.48
0.12
2.38
9.05
2.93

17.23
0.35
2.55
9.01
5.32

Year

Q4

Q3

Q2

         Q1

28.23
2.41
8.52
7.21
10.09

38.37
3.81
7.82
7.41
19.33

Year

(1.74)

Q4

(1.05)

Year

495
372
149
223
75%
385

Q4

495
338
133
205
68%
350

38.55
3.86
7.46
7.09
20.14

2020

Q3

(3.46)

2020

Q3

495
382
154
228
77%
397

13.04
0.75
8.33
7.00
(3.04)

22.47
1.17
10.43
7.33
3.54

Q2

         Q1

(1.81)

(0.63)

(0.16)

Q2

         Q1

2019
     Year

495
325
112
213
66%
332

495
442
197
245
89%
460

482
443
177
266
92%
466

(1)

(2)

(3)

(4)

(5)

We renamed our Deep Basin segment to Conventional segment in the first quarter of 2020. For a description of our operations, refer to the Reportable Segments section of the Management's Discussion and Analysis.

Q4 effective royalty rate for Christina Lake and Foster Creek reflects the annual weighted average unit price adjustments and audit adjustments related to prior periods. The Q4 effective royalty rate, before the adjustments would
be 14.4% and 6.8% for Christina Lake and Foster Creek, respectively. 

Netbacks do not reflect the non-cash write-downs or reversals of product inventory until the product is sold. There was no impact to netbacks for total operations from realizing inventory write-downs for the three months ended
December 31, 2020. 

Natural gas volumes have been converted to BOE on the basis of six Mcf to one 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 to 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.

Represents 100 percent of the Wood River and Borger refinery operations.

(cid:20)(cid:21)(cid:25)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

         
         
           
           
           
           
           
           
             
             
             
             
         
           
             
           
           
           
           
         
             
             
             
             
           
         
           
           
             
           
         
         
           
           
           
           
           
           
             
             
             
             
           
           
             
             
             
             
           
           
             
             
             
             
         
         
           
           
             
           
         
         
           
           
           
           
           
           
             
             
             
             
           
           
             
             
           
             
           
           
             
             
             
             
           
         
           
           
             
           
         
         
           
           
           
           
           
           
             
             
             
             
           
           
             
             
             
             
           
           
             
             
             
             
           
           
             
             
             
             
         
         
           
           
           
           
           
           
             
             
             
             
           
           
             
             
           
             
           
           
             
             
             
             
         
         
           
           
             
           
          
          
           
           
           
           
            
            
              
              
              
              
            
            
              
              
              
              
            
            
              
              
              
              
            
            
              
              
              
              
            
            
              
              
              
              
(cid:36)(cid:39)(cid:57)(cid:44)(cid:54)(cid:50)(cid:53)(cid:60)

Oil and Gas Information 

The  estimates  of  Cenovus’s  reserves  were  prepared  effective  December  31,2020  by  IQREs,  based  on  the  COGE 
Handbook and in compliance with the requirements of NI 51-101. Estimates are presented using the IQRE Average 
forecast  prices  and  costs  dated  January1,2021  price  forecasts.  For  additional  information  about  our  reserves  and 
other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended 
December 31,2020. 

Total  proved  reserves  and  total  proved  plus  probable  reserves  for  Cenovus  and  Husky  are  based  on  a  simple 
summation  of  reserves  prepared  independently  for  each  company.  Cenovus  has  not  constructed  a  consolidated 
reserves  report  of  the  combined  assets  of  Cenovus  and  Husky  and  has  not  engaged  an  independent  reserves 
evaluator to produce such a report in accordance with NI 51-101. Reserves calculated for the combined company 
could be materially different than reserves calculated by adding the reserves of the two companies. The anticipated 
increase in reserves for the combined company may be more or less than anticipated, and the difference could be 
material. 

Cenovus  and  Husky  employed  different  methodologies  to  estimate  their  reserves  information  for  the  year  ended 
December  31,  2020.  All  of  Husky’s  oil  and  gas  reserves  estimates  were  prepared  by  internal  qualified  reserves 
evaluators  using  a  formalized  process  for  determining,  approving  and  booking  reserves.  As  a  result,  the  actual 
reserves  of  Cenovus  (after  giving  effect  to  the  Arrangement),  if  calculated  as  of  December  31,  2020  by  an 
independent reserves evaluator in accordance with NI 51-101, may differ from the anticipated total proved reserves 
and total proved plus probable reserves of the combined company for a number of reasons, and such differences 
may be material. 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. 

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 U.S. 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 document is identified by words such as “achieve”, “aim”, “anticipate”, 
“believe”, “can be”, “capacity”, “committed”, “commitment”, “continue”, “could”, “deliver”, “drive”, “enhance”, 
“ensure”, “estimate”, “expect”, “focus”, “forecast”, “forward”, “future”, “guidance”, “maintain”, “may”, “objective”, 
“outlook”, “plan”, “position”, “potential”, “priority”, “re-establishing”, “strategy”, “should”, “target”, “will”, or similar 
expressions and includes suggestions of future outcomes, including, but not limited to, statements about: strategy 
and related milestones; schedules and plans; stronger financial performance in 2021; anticipated benefits of the 
Arrangement, including: achieving $1.2 billion of incremental annual free funds flow comprised of approximately 
$600 million in annual corporate and operating synergies and approximately $600 million in annual sustaining 
capital allocation synergies independent of commodity prices with the majority of annual savings achieved within 
the first year of combined operations and the full amount achieved within year two, the impact of the Arrangement 
on certain reserves data and other oil and gas information, including any pro forma information, the planned 
amalgamation of Cenovus and Husky, achieving longer term cost savings and margin enhancements based on 
further physical integration, reducing our exposure to Alberta heavy oil price differentials while maintaining 
exposure to global commodity prices, reducing condensate costs associated with heavy oil transportation over the 
longer term, accelerating balance sheet deleveraging, achieving sustainable growth in shareholder distributions; 
improving efficiencies to drive incremental capital, operating and G&A cost reductions; the ability of our assets to 
respond to market signals and ramp up production accordingly; statements and expectations relating to our 2021 
budget; our ability to partially mitigate the impact of crude oil and refined product differentials through 
transportation commitments, integration, marketing agreements, dynamic storage, traditional storage tanks and 
financial hedge contracts; maintaining an investment grade credit rating; reduced free funds flow volatility; 
enhanced resilience; financial flexibility to withstand economic volatility; improved capacity to generate significant 
free funds flow; achieving Net Debt to Adjusted EBITDA target of less than 2.0 times without the need for asset 
dispositions; our focus on allocating free funds flow to reduce Net Debt to less than $10 billion and targeting a 
longer-term Net Debt level at or below $8 billion; focus on maximizing shareholder value through disciplined, 
returns-focused capital investment and cost leadership to realize the best margins for our products and 
environmental benefits; maintaining liquidity, delivering a stable cash flow through price cycles and preserving a 

(cid:1)

(cid:21)(cid:19)(cid:21)(cid:19)(cid:3)(cid:36)(cid:49)(cid:49)(cid:56)(cid:36)(cid:47)(cid:3)(cid:53)(cid:40)(cid:51)(cid:50)(cid:53)(cid:55)(cid:3)(cid:3)(cid:95)(cid:3)(cid:20)(cid:21)(cid:26)
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(cid:1)

resilient balance sheet by reducing spending while maintaining safe and reliable operations; the expected 
production levels of our business segments in 2021; longer-term focus on sustainably growing shareholder returns 
and reducing Net Debt as well as continuing to integrate ESG considerations into our business plan; maintaining a 
strong balance sheet to help Cenovus navigate through commodity price volatility; evaluating disciplined 
investment in our portfolio against dividends, share repurchases and achieving and maintaining the optimal debt 
level while targeting investment grade status; focusing investment on areas where we believe we have the 
greatest competitive advantage; plan to achieve our strategy by leveraging our strategic focus areas including our 
oil sands, conventional oil and natural gas assets, marketing, transportation and refining portfolio, and our people; 
our 2021 capital investment plan, operating cost reductions and G&A reductions enhances our financial resilience 
and financial capability to maintain our base business, deliver safe and reliable operations and to continue to 
challenge our cost structure in the face of these unprecedented conditions; our ability to reduce spending in 
response to commodity prices and other economic factors in order to maintain our financial resilience; ample 
liquidity and runway to sustain operations through a prolonged market downturn; anticipated volatility of demand 
and crude oil prices through 2021 as a result of continued uncertainty around COVID-19, with crude oil and refined 
products demand and recovery dependent on the success of economic relaunches and the overall supply and 
demand balance; maintaining a high level of capital discipline and managing our capital structure to help ensure 
the Company has sufficient liquidity through all stages of the economic cycle; demand for refined product being an 
early indicator of recovery from the impact of COVID-19; increases in staff levels at sites and offices will continue 
to be achieved in accordance with guidance received from the applicable federal, provincial, state and local 
governments and public health officials; expected recovery of the price of and demand for crude oil and refined 
products over the longer term as COVID-19 vaccines are administered and economies re-open from the impacts of 
the pandemic; expected timing for oil sands expansion phases projections for 2021 and future years and our plans 
and strategies to realize such projections; the reduction of transportation costs caused by the temporary 
suspension of the crude-by-rail program; reaching a broader customer base; forecast exchange rates and trends; 
future opportunities for oil and natural gas development; forecast operating and financial results, including forecast 
sales prices, costs and cash flows; our ability to satisfy payment obligations as they become due; priorities for and 
approach to capital investment decisions or capital allocation, including decisions pertaining to new projects and 
phases; planned capital expenditures, including the amount, timing and funding sources thereof; all statements 
with respect to our 2021 guidance estimates; expected future production, including the timing, stability or growth 
thereof; our ability to manage our production well rates in response to pipeline capacity constraints, storage 
constraints and crude oil price differentials; our ability to take steps to partially mitigate against wider WTI and 
WCS price differentials; our expectation that the general outlook for light crude oil prices will be tied primarily to 
the supply and demand response to the current uncertain price environment, the impact of oversupply, and global 
demand impacts amid COVID-19 concerns; our expectation that the WTI-WCS differential in Alberta will remain 
largely tied to the extent to which supply cuts are sustainable, the potential start-up of Enbridge Inc.’s Line 3 
Replacement Program, the completion of the Trans Mountain Expansion project, and the level of crude-by-rail 
activity; our expectation that in 2021 refining market crack spreads will remain weak relative to previous years as 
a result of significantly reduced refined products demand due to COVID-19; our expectation that our capital 
investment and near-term cash requirements will be funded through cash from operating activities and prudent use 
of our balance sheet capacity including draws on our credit and demand facilities, management of our asset 
portfolio and other corporate and financial opportunities that may be available to us; statements about our debt 
level as we manage through the low commodity price environment; expected reserves; focus on mid-term 
strategies to broaden market access for our crude oil production; supporting proposed new pipeline projects that 
would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and 
assessing options to maximize the value of our crude oil; impact on alignment of transportation and storage 
commitments and production growth; all statements related to government royalty regimes applicable to Cenovus, 
which regimes are subject to change; our ability to preserve our financial resilience and various plans and 
strategies with respect thereto; our priorities, including for 2021; future impact of regulatory measures; forecast 
commodity prices, differentials and trends and expected impact; potential impacts of various risks, including those 
related to commodity prices and climate change; the potential effectiveness of our risk management strategies; 
new accounting standards, the timing for the adoption thereof, and anticipated impact on the Consolidated 
Financial Statements; our expectation that any liabilities that may arise out of legal claims associated with the 
normal course of our operations are not likely to have a material effect on our Consolidated Financial Statements; 
the availability and repayment of our credit facilities; potential asset sales; expected impacts of the contingent 
payment to ConocoPhillips; development of a new five-year business plan for the combined company in 2021; 
being a leader in ESG performance; statements about new ESG targets and ambitions, plans to achieve them and 
our commitment to transparent performance reporting; achieving net zero emissions by 2050; holding engagement 
sessions with shareholders; future investment, use and development of technology and equipment and associated 
future outcomes; our ability to access and implement all technology necessary to efficiently and effectively operate 
our assets and achieve expected future results; planned capital expenditures; and projected growth 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. 

Statements  relating  to  “reserves”  are  deemed  to  be  forward-looking  information,  as  they  involve  the  implied 
assessment,  based  on  certain  estimates  and  assumptions,  that  the  reserves  described  exist  in  the  quantities 
predicated or estimated, and can be profitably produced in the future. 

(cid:1)
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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 our forward-looking information is based include, but are not limited to: forecast oil 
and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials; 
our  ability  to  realize  the  benefits  and  anticipated  cost  synergies  associated  with  the  combination  of  Cenovus  and 
Husky; Cenovus’s ability to successfully integrate the business of Husky, including new business activities, assets, 
operating  areas,  regulatory  jurisdictions,  personnel  and  business  partners  for  Cenovus;  the  accuracy  of  any 
assessments undertaken in connection with the Husky Arrangement and any resulting pro forma information; our 
forecast production volumes are subject to potential further ramp down of production based on business and market 
conditions;  projected  capital  investment  levels,  the  flexibility  of  capital  spending  plans  and  associated  sources  of 
funding;  the  absence  of  significant  adverse  changes  to  legislation  and  regulations,  Indigenous  relations,  interest 
rates, foreign exchange rates, competitive conditions and the supply and demand for crude oil and natural gas, NGLs, 
condensate  and  refined  products;  the  political,  economic  and  social  stability  of  jurisdictions  in  which  Cenovus 
operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, 
accident,  civil  unrest  or  other  similar  events;  the  prevailing  climatic  conditions  in  Cenovus's  operating  locations; 
achievement  of  further  cost  reductions  and  sustainability  thereof;  applicable  royalty  regimes,  including  expected 
royalty rates; future improvements in availability of product transportation capacity; increase to our share price and 
market capitalization over the long term; opportunities to repurchase shares for cancellation at prices acceptable to 
us;  cash  flows,  cash  balances  on  hand  and  access  to  credit  and  demand  facilities  being  sufficient  to  fund  capital 
investments; foreign exchange rate risk, including with respect to our US$ debt and refining capital and operating 
expenses;  our  ability  to  reduce  our  2021  oil  sands  production,  including  without  negative  impacts  to  our  assets; 
realization of expected capacity to store within our oil sands reservoirs barrels not yet produced, including that we 
will be able to time production and sales of our inventory at later dates when demand has increased, pipeline and/or 
storage capacity has improved and crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains 
largely tied to the extent to which voluntary economically driven supply cuts are made, the potential start-up of the 
Enbridge Inc.’s Line 3 Replacement Program, the completion of Trans Mountain Expansion project, and the level of 
crude-by-rail  activity;  the  ability  of  our  refining  capacity,  dynamic  storage,  existing  pipeline  commitments  and 
financial hedge transactions to partially mitigate a portion of our WCS crude oil volumes against wider differentials; 
production declines from both associated gas and dry gas, along with rebounding U.S. demand and liquified natural 
gas exports should tighten North American gas fundamentals further in 2021 and result in stronger prices than 2020 
on an annual basis; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources 
not currently classified as proved; the accuracy of accounting estimates and judgments; future use and development 
of  technology  and  associated  expected  future  results;  our  ability  to  obtain  necessary  regulatory  and  partner 
approvals; the successful, timely and cost effective implementation of capital projects or stages thereof; our ability 
to generate sufficient cash flow to meet our current and future obligations; the sufficiency of existing cash balances, 
internally generated cash flows, existing credit facilities, management of the Corporation’s asset portfolio and access 
to  capital  markets  to  fund  future  development  costs  and  dividends,  including  any  increase  thereto;  estimated 
abandonment  and  reclamation  costs,  including  associated  levies  and  regulations  applicable  thereto;  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  our  development  plans;  our  ability  to  complete  asset  sales,  including  with  desired  transaction 
metrics  and  within  the  timelines  we  expect;  the  stability  of  general  domestic  and  global  economic,  market  and 
business  conditions;  forecast  inflation  and  other  assumptions  inherent  in  Cenovus’s  2021  guidance  available  on 
cenovus.com  and  as  set  out  below;  expected  impacts  of  the  contingent  payment  to  ConocoPhillips;  alignment  of 
realized WCS and WCS prices used to calculate the contingent payment to ConocoPhillips; our ability to access and 
implement  all  technology  and  equipment  necessary  to  achieve  expected  future  results  and  that  such  results  are 
realized; our ability to implement capital projects or stages thereof in a successful and timely manner; and other 
risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. 

2021 guidance, as updated January 28, 2021 and available on cenovus.com, assumes: Brent prices of US$49.50/bbl, 
WTI prices of US$46.50/bbl; WCS of US$32.50/bbl; Differential WTI-WCS of US$14.00/bbl; AECO natural gas prices 
of $2.50/Mcf; Chicago 3-2-1 crack spread of US$11.00/bbl; and an exchange rate of $0.78 US$/C$. 

The risk factors and uncertainties that could cause our actual results to differ materially from the forward-looking 
information,  include,  but  are  not  limited  to:  the  effect  of  the  COVID-19  pandemic  on  our  business,  including  any 
related restrictions, containment, and treatment measures taken by varying levels of government in the jurisdictions 
in  which  we  operate;  the  success  of  our  new  COVID-19  workplace  policies  and  the  return  of  our  people  to  our 
workplace; our ability to achieve the benefits and anticipated cost synergies anticipated with the Arrangement in a 
timely manner or at all; the ability of Cenovus and Husky to amalgamate; Cenovus’s ability to successfully integrate 
Husky’s business with its own in a timely and cost effective manner or at all; the effects of entering new business 
activities; unforeseen or undisclosed liabilities associate with the Arrangement; the inaccuracy of any assessments 
undertaken  in  connection  with  the  Arrangement  and  any  resulting  pro  forma  information;  the  inaccuracy  of  any 
information  provided  by  Husky;  our  ability  to  access  or  implement  some  or  all  of  the  technology  necessary  to 
efficiently and effectively operate our assets and achieve expected future results; the effect of Cenovus’s increased 
indebtedness;  the  effect  of  new  significant  shareholder;  volatility  of  and  other  assumptions  regarding  commodity 
prices; the duration of the market downturn; foreign exchange risk, including related to agreements denominated in 
foreign currencies; our continued liquidity is sufficient to sustain operations through a prolonged market downturn; 
WTI-WCS differential in Alberta does not remain largely tied to the extent to which voluntary economically driven 

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(cid:1)

supply cuts are made, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the 
Trans Mountain Expansion project, and the level of crude-by-rail activity; our ability to achieve lower transportation 
costs as a result of temporarily suspending the crude-by-rail program; our ability to realize the expected impacts of 
our  capacity  to  store  within  our  oil  sands  reservoirs  barrels  not  yet  produced,  including  possible  inability  to  time 
production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; 
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 regarding 
commodity  prices,  currency  and  interest  rates;  lack  of  alignment  of  realized  WCS  prices  and  WCS  prices  used  to 
calculate the contingent payment to ConocoPhillips; product supply and demand; the accuracy of our share price and 
market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in 
our marketing operations, including credit risks, exposure to counterparties and partners, including the 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; our ability to maintain desirable ratios of 
Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; our ability to access various sources of debt and 
equity  capital,  generally,  and  on  terms  acceptable  to  us;  our  ability  to  finance  growth  and  sustaining  capital 
expenditures; changes in credit ratings applicable to us or any of our securities; changes to our dividend plans; our 
ability  to  utilize  tax  losses  in  the  future;  the  accuracy  of  our  reserves,  future  production  and  future  net  revenue 
estimates; the accuracy of our accounting estimates and judgements; our ability to replace and expand oil and gas 
reserves;  the  costs  to  acquire  exploration  rights,  undertake  geological  studies,  appraisal  drilling  and  project 
developments; potential requirements under applicable accounting standards for impairment or reversal of estimated 
recoverable  amounts  of  some  or  all  of  our  assets  or  goodwill  from  time  to  time;  our  ability  to  maintain  our 
relationships  with  our  partners  and  to  successfully  manage  and  operate  our  integrated  operations  and  business; 
reliability of our 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 resulting 
in operational interruptions, including blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, 
gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills 
from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, 
epidemics or pandemics, and catastrophic events, including, but not limited to, war, extreme weather events, natural 
disasters, iceberg incidents, acts of vandalism and terrorism, and other accidents or hazards that may occur at or 
during  transport  to  or  from  commercial  or  industrial  sites  and  other  accidents  or  similar  events;  refining  and 
marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, 
natural gas and other energy sources used in oil sands processes and increased insurance deductibles or premiums; 
the cost and availability of equipment necessary to our operations; potential failure of products to achieve or maintain 
acceptance  in  the  market;  risks  associated  with  the  energy  industry’s  and  Cenovus’s  reputation,  social  license  to 
operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or 
modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining bitumen 
and/or  crude  oil  into  petroleum  and  chemical  products;  risks  associated  with  technology  and  equipment  and  its 
application  to  our  business,  including  potential  cyberattacks;  geo-political  and  other  risks  associated  with  our 
international operations; risks associated with climate change and our assumptions relating thereto; the timing and 
the costs of well and pipeline construction; our ability to access markets and 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 or storage capacity; availability of, and our ability to 
attract  and  retain,  critical  talent;  possible  failure  to  obtain  and  retain  qualified  leadership  and  personnel,  and 
equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with 
any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, 
permits and approvals in any of the locations in which we operate or to any of the infrastructure upon which we rely; 
government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; 
changes to regulatory approval processes 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, our financial results and 
our Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of 
production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the 
jurisdictions in which we operate or supply; the status of our relationships with the communities in which we operate, 
including with Indigenous communicates; the occurrence of unexpected events such as protests, pandemics, war, 
terrorist  threats  and  the  instability  resulting  therefrom;  and  risks  associated  with  existing  and  potential  future 
lawsuits, shareholder proposals and regulatory actions against us. 

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 our material risk factors, see Risk Management 
and Risk Factors in this MD&A, and to the risk factors described in other documents Cenovus files from time to time 
with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and 
Exchange Commission on EDGAR at sec.gov, and on the Corporation’s website at cenovus.com. Additional information 
concerning Husky’s business and assets as of December 31, 2020 may be found in the Husky AIF and this MD&A, 
each of which is filed and available on SEDAR under Husky’s profile at sedar.com. 

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(cid:1)

Information on or connected to Cenovus’s at website cenovus.com or Husky’s website at huskyenergy.com does not 
form part of this MD&A unless expressly incorporated by reference herein. 

ABBREVIATIONS 

The following abbreviations have been used in this document: 

Crude Oil 

bbl 
Mbbls/d 
MMbbls 
BOE 
MMBOE 
WTI 
WCS 
CDB 
MSW 
WTS 

barrel 
thousand barrels per day 
million barrels 
barrel of oil equivalent 
million barrel of oil equivalent 
West Texas Intermediate 
Western Canadian Select 
Christina Dilbit Blend 
Mixed Sweet Blend 
West Texas Sour 

DEFINITIONS 

Natural Gas 

Mcf 
MMcf 
Bcf 
MMBtu 
GJ 
AECO 
NYMEX 

thousand cubic feet 
million cubic feet 
billion cubic feet 
million British thermal units 
gigajoule 
Alberta Energy Company 
New York Mercantile Exchange 

Scope 1 emissions are direct emissions from owned or operated facilities. Cenovus accounts for emissions on a gross 
operatorship  basis.  This  includes  fuel  combustion,  venting,  flaring  and  fugitive  emissions.  It  does  not  include 
emissions from the 50 percent non-operated ownership in the Company’s refineries or emissions from non-operated 
Conventional assets. 

Scope  2  emissions  are  indirect  emissions  from  the  generation  of  purchased  energy  for  the  Company’s  operated 
facilities. For Cenovus, this is limited to electricity imports. 
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NETBACK RECONCILIATIONS 

The  following  tables  provide  a  reconciliation  of  the  items  comprising  Netbacks  to  Operating  Margin  found  in  our 
Consolidated Financial Statements. 

Total Production 

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Basis of 
Netback 
Calculation   
Total 
Upstream   

4,344   

370   

1,313   

1,109   

-   

1,552   

268   

1,284   

Basis of 
Netback 
Calculation   
Total 
Upstream   

7,222   

1,174   

1,214   

1,121   

3,713   

23   

3,690   

Basis of 
Netback 
Calculation   
Continuing 
Operations   

5,689   

546   

972   

1,224   

2,947   

1,577   

1,370   

Basis of 
Netback 
Calculation   
Total 
Upstream   

1,449   

143   

296   

279   

-   

731   

40   

691   

Per Consolidated Financial Statements 

Adjustments 

Year Ended 
December 31, 2020 ($ millions)

Oil
Sands (1)

 Conventional (1) (2)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 
Inventory Write-Down (Reversal) 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

7,514        
324        
4,399        
1,094        
316        
1,381        
268        
1,113        

635        
40        
81        
318        
-        
196        
-        
196        

Total 

(3,452 )     
-        
(3,452 )     
-        

Upstream     Condensate      Inventory     
-        
6        
285        
25        
(316 )     
-        
-        
-        

8,149        
364        
4,480        
1,412        
316        
1,577        
268        
1,309        

-        
-        
-        

Internal 
Usage (3)

(295 )     
-        
-        
(295 )     

Other     
(58 )     
-        
-        
(33 )     

-        
-        
-        

(25 )     
-        
(25 )     

Year Ended 
December 31, 2019 ($ millions)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Year Ended
December 31, 2018 ($ millions) (4)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Per Consolidated Financial Statements 

Oil
Sands (1)

 Conventional (1) (2)

Total 
Upstream   

 Condensate   

  Inventory   

Adjustments 

10,838        
1,143        
5,152        
1,039        
3,504        
23        
3,481        

691         

11,529         

(4,021 )      

30         

82         

1,173         

-         

5,234         

(4,021 )      

337         

1,376         

242         

3,746         

-         

23         

242         

3,723         

-         

-         

-         

-         

-         

-         

-         

-         

-         

-         

-         

Internal 
Usage (3)

Other   

(222 )      

(64 )      

-         

-         

(222 )      

-         

-         

-         

1         

1         

(33 )      

(33 )      

-         

(33 )      

Per Consolidated Financial Statements 

Adjustments 

Oil
Sands(1)
10,026        
473        
5,879        
1,037        
2,637        
1,551        
1,086        

  Conventional(1) (2)

Continuing 
Operations     Condensate      Inventory     
-        
-        
-        
-        
-        
-        
-        

10,930        
546        
5,969        
1,440        
2,975        
1,577        
1,398        

(4,993 )     
-        
(4,993 )     
-        
-        
-        
-        

904        
73        
90        
403        
338        
26        
312        

Internal 
Usage(3)

(179 )     
-        
-        
(179 )     
-        
-        
-        

Other     
(69 )     
-        
(4 )     
(37 )     
(28 )     
-        
(28 )     

(1)
(2)
(3)
(4)

Found in Note 1 of the Consolidated Financial Statements. 
This segment was previously referred to as the Deep Basin segment. 
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. 
On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

Three Months Ended 
December 31, 2020 ($ millions)

Oil
Sands (5)

 Conventional (5) (6)

Total 
Upstream   

 Condensate   

  Inventory   

Internal
Usage (7)

Other   

Per Interim Consolidated Financial Statements      

Adjustments 

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Inventory Write-Down (Reversal) 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

2,227        
131        
1,131        
309        
-        
656        
40        
616        

184        
12        
18        
72        
-        
82        
-        
82        

2,411        
143        
1,149        
381        
-        
738        
40        
698        

(853 )     
-        
(853 )     
-        
-        
-        
-        
-        

-        
-        
-        
-        
-        
-        
-        
-        

(92 )     
-        
-        
(92 )     
-        
-        
-        
-        

(17 )     
-        
-        
(10 )     
-        
(7 )     
-        
(7 )     

(5)
(6)
(7)

Found in Note 1 of the interim Consolidated Financial Statements. 
This segment was previously referred to as the Deep Basin segment. 
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.  

(cid:20)(cid:22)(cid:21)(cid:3)(cid:95)(cid:3)(cid:3)(cid:38)(cid:40)(cid:49)(cid:50)(cid:57)(cid:56)(cid:54)(cid:3)(cid:40)(cid:49)(cid:40)(cid:53)(cid:42)(cid:60)

 
 
     
     
 
 
  
  
  
  
  
        
        
        
  
  
  
 
 
     
     
 
 
 
 
  
  
  
  
  
  
  
 
 
     
     
 
 
  
  
  
  
  
  
  
 
 
     
 
 
 
 
  
  
  
  
  
  
  
  
 
Three Months Ended 
December 31, 2019 ($ millions)

Oil
Sands (1)

  Conventional (1) (2)

Upstream   

 Condensate   

  Inventory   

Total 

Internal
Usage (3)

Other   

Per Interim Consolidated Financial Statements      

Adjustments 

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

2,659        
316        
1,416        
268        
659        
(15 )     
674        

190        
9        
20        
80        
81        
-        
81        

2,849        
325        
1,436        
348        
740        
(15 )     
755        

(1,060 )     
-        
(1,060 )     
-        
-        
-        
-        

-        
-        
-        
-        
-        
-        
-        

(82 )     
-        
-        
(82 )     
-        
-        
-        

(13 )     
1        
1        
(6 )     
(9 )     
-        
(9 )     

(1)
(2)
(3)

Found in Note 1 of the interim Consolidated Financial Statements. 
This segment was previously referred to as the Deep Basin segment. 
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. 

Basis of 
Netback 
Calculation   
Total 
Upstream   

1,694   

326   

377   

260   

731   

(15 ) 

746   

Oil Sands 

Basis of Netback Calculation 

Adjustments 

Year Ended 
December 31, 2020 ($ millions)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Inventory Write-Down (Reversal) 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Foster 
Creek     
1,859        
95        
667        
558        
-        
539        
111        
428        

Christina Lake     
2,194        
235        
565        
551        
-        
843        
157        
686        

Total 
Crude Oil     
4,053        
330        
1,232        
1,109        
-        
1,382        
268        
1,114        

Natural 

-        
-        
-        
-        

Gas     Condensate      Inventory     
-        
3,452        
-        
(6 )     
(285 )     
3,452        
(25 )     
-        
316        
-        
-        
-        

-        
-        
-        

-        
-        
-        

Basis of Netback Calculation 

Adjustments 

Year Ended 
December 31, 2019 ($ millions)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Foster 
Creek     
3,295        

486        

674        

526        

1,609        

10        

1,599        

Christina Lake     
3,511        
650        
458        
505        
1,898        
13        
1,885        

Total 
Crude Oil     
6,806        
1,136        
1,132        
1,031        
3,507        
23        
3,484        

Natural 

Gas     Condensate      Inventory     
-        
4,021        
-        
-        
-        
4,021        
-        
-        
-        
-        
-        
-        
-        
-        

-        
-        
-        
-        
-        
-        
-        

Basis of Netback Calculation 

Adjustments 

Year Ended
December 31, 2018 ($ millions) (5)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Foster 
Creek     
2,531        
371        
495        
532        
1,133        
683        
450        

Christina Lake     
2,489        
102        
391        
492        
1,504        
868        
636        

Total 
Crude Oil     
5,020        
473        
886        
1,024        
2,637        
1,551        
1,086        

Natural 

Gas     Condensate      Inventory     
-        
4,993        
-        
-        
-        
4,993        
-        
-        
-        
-        
-        
-        
-        
-        

1        
-        
-        
2        
(1 )     
-        
(1 )     

(4)
(5)

Found in Note 1 of the Consolidated Financial Statements. 
On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

Three Months Ended 
December 31, 2020 ($ millions)

Foster 
Creek   

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Inventory Write-Down (Reversal) 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

615        
28        
144        
154        
-        
289        
15        
274        

(1)

Found in Note 1 of the interim Consolidated Financial Statements. 

Basis of Netback Calculation 
Total 
Crude Oil      
1,371      
131      
278      
306      
-      
656      
40      
616      

Christina 
Lake   
756        
103        
134        
152        
-        
367        
25        
342        

Natural 
Gas   

 Condensate   

  Inventory   

Adjustments 

-        
-        
-        
-        
-        
-        
-        
-        

853        
-        
853        
-        
-        
-        
-        
-        

-         
-         
-         
-         
-         
-         
-         
-         

Per
Consolidated
Financial
Statements (4)
Total 
Oil Sands   

7,514   

324   

4,399   

1,094   

316   

1,381   

268   

1,113   

Per
Consolidated
Financial
Statements (4)
Total 
Oil Sands   

10,838   

1,143   

5,152   

1,039   

3,504   

23   

3,481   

Per
Consolidated
Financial
Statements (4)
Total 
Oil Sands   

10,026   

473   

5,879   

1,037   

2,637   

1,551   

1,086   

Other     
9        
-        
-        
10        

(1 )     
-        
(1 )     

Other     
11        
7        
(1 )     
8        
(3 )     
-        
(3 )     

Other     
12        
-        
-        
11        
1        
-        
1        

Per Interim
Consolidated
Financial
Statements (1)
Total 
Oil Sands  

Other     
3       
-       
-       
3       
-       
-       
-       
-       

2,227  

131  

1,131  

309  

-  

656  

40  

616   

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Basis of Netback Calculation 

Adjustments 

Total 
Crude Oil   

Natural 
Gas   

 Condensate   

  Inventory   

Other   

Per Interim
Consolidated
Financial
Statements (1)
Total 
Oil Sands   

Three Months Ended 
December 31, 2019 ($ millions)

Foster 
Creek   

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

731        
130        
207        
132        
262        
(5 )     
267        

(1)

Found in Note 1 of the interim Consolidated Financial Statements. 

Christina 
Lake   
866        
179        
150        
136        
401        
(10 )     
411        

Conventional (2) 

Year Ended 
December 31, 2020 ($ millions)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Year Ended 
December 31, 2019 ($ millions)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Year Ended
December 31, 2018 ($ millions) (5)
Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

Operating Margin 

1,597        
309        
357        
268        
663        
(15 )     
678        

-        
-        
-        
-        
-        
-        
-        

1,060        
-        
1,060        
-        
-        
-        
-        

-        
-        
-        
-        
-        
-        
-        

2        
7        
(1 )     
-        
(4 )     
-        
(4 )     

2,659   

316   

1,416   

268   

659   

(15 ) 

674   

Basis of Netback 

Calculation      

Adjustments      

Total   

Other(4)

Per Consolidated
Financial
Statements(3)
Total 
Conventional   

586        
40        
81        
295        
170        
-        
170        

49        
-        
-        
23        
26        
-        
26        

635   

40   

81   

318   

196   

-   

196   

Basis of Netback 

Calculation      

Adjustments      

Total   

Other(4)

Per Consolidated
Financial
Statements(3)
Total 
Conventional   

638         
30         
82         
312         
214         
-         
214         

53         
-         
-         
25         
28         
-         
28         

691   

30   

82   

337   

242   

-   

242   

Basis of Netback 

Calculation      

Adjustments      

Total   

Other(4)

Per Consolidated
Financial
Statements(3)
Total 
Conventional   

847         
73         
86         
377         
311         
285         

57         
-         
4         
26         
27         
27         

904   

73   

90   

403   

338   

312   

(2)
(3)
(4)
(5)

This segment was previously referred to as the Deep Basin segment. 
Found in Note 1 of the Consolidated Financial Statements. 
Reflects operating margin from processing facility. 
On January 1, 2019, we adopted IFRS 16 using the modified retrospective approach; therefore, comparative information has not been restated. 

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Three Months Ended 
December 31, 2020 ($ millions)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Three Months Ended 
December 31, 2019 ($ millions)

Gross Sales 

Royalties 

Transportation and Blending 

Operating 

Netback 

(Gain) Loss on Risk Management 

Operating Margin 

Basis of Netback 

Calculation      

Adjustments      

Total   

Other(2)

170        
12        
18        
65        
75        
-        
75        

14        
-        
-        
7        
7        
-        
7        

Basis of Netback 

Calculation      

Adjustments      

Total   

Other(2)

179        
9        
20        
74        
76        
-        
76        

11        
-        
-        
6        
5        
-        
5        

Per Interim
Consolidated
Financial
Statements(1)
Total 
Conventional   

184   

12   

18   

72   

82   

-   

82   

Per Interim
Consolidated
Financial
Statements(1)
Total 
Conventional   

190   

9   

20   

80   

81   

-   

81   

(1)
(2)

Found in Note 1 of the interim Consolidated Financial Statements. 
Reflects operating margin from processing facility. 

The following table provides the sales volumes used to calculate Netback. 

Sales Volumes 

(barrels per day, unless otherwise stated) 

2020      

2019      

2020      

2019      

2018   

Three Months Ended 

Year Ended December 31 

December 31, 

December 31, 

Oil Sands 

Foster Creek 

Christina Lake 

Total Oil Sands Crude Oil 

Conventional (3)

Total Liquids 

161,108        
220,676        
381,784        

153,797        
207,399        
361,196        

164,906        
221,675        
386,581        

157,770        

162,685   

188,910        

204,016   

346,680        

366,701   

24,543        

26,197        

26,646        

26,673        

32,454   

Natural Gas (MMcf per day)

369        

403        

379        

424        

527   

Total Conventional (BOE per day)

86,123        

93,317        

89,821        

97,423        

120,258   

Less: Internal Consumption (4) (MMcf per day)

(344 )     

(336 )      

(336 )     

(320 )      

(306 ) 

Sales From Continuing Operations (4) (BOE per day)

410,864        

398,457        

420,456        

390,813        

436,163   

(3)
(4)

This segment was previously referred to as the Deep Basin segment. 
Less natural gas volumes used for internal consumption by the Oil Sands segment 

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NOTES

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NOTES

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NOTES

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NOTES

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NOTES

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I N F O R M A T I O N   F O R 

SHAREHOLDERS

ANNUAL MEETING 
Due to the COVID-19 pandemic, Cenovus will hold its Annual Meeting 
of Shareholders in a virtual format again this year to help mitigate 
health and safety risks to our community, shareholders, employees and 
other stakeholders. Holders of Cenovus common shares are invited 
to attend the virtual Annual Meeting of Shareholders to be held on 
Wednesday, May 12, 2021 at 1 p.m. MT via live webcast accessible online 
at https://web.lumiagm.com/445299876. Please see our Management 
Information Circular available on cenovus.com for additional information. 

TRANSFER AGENT & REGISTRAR 
Computershare Investor Services Inc.  
8th Floor, 100 University Avenue  
Toronto, Ontario  M5J 2Y1 Canada 
www.investorcentre.com/cenovus 
Shareholder inquiries by phone:   
(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:3)(cid:36)(cid:80)(cid:72)(cid:85)(cid:76)(cid:70)(cid:68)(cid:3)(cid:20)(cid:17)(cid:27)(cid:25)(cid:25)(cid:17)(cid:22)(cid:22)(cid:21)(cid:17)(cid:27)(cid:27)(cid:28)(cid:27)(cid:3)(cid:11)(cid:40)(cid:81)(cid:74)(cid:79)(cid:76)(cid:86)(cid:75)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:41)(cid:85)(cid:72)(cid:81)(cid:70)(cid:75)(cid:12)(cid:3) 
(cid:50)(cid:88)(cid:87)(cid:86)(cid:76)(cid:71)(cid:72)(cid:3)(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:3)(cid:36)(cid:80)(cid:72)(cid:85)(cid:76)(cid:70)(cid:68)(cid:3)(cid:20)(cid:17)(cid:24)(cid:20)(cid:23)(cid:17)(cid:28)(cid:27)(cid:21)(cid:17)(cid:27)(cid:26)(cid:20)(cid:26)(cid:3)(cid:11)(cid:40)(cid:81)(cid:74)(cid:79)(cid:76)(cid:86)(cid:75)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:41)(cid:85)(cid:72)(cid:81)(cid:70)(cid:75)(cid:12)

SHAREHOLDER ACCOUNT MATTERS 
For information regarding your shareholdings or to change your 
address, transfer shares, eliminate duplicate mailings, direct deposit of 
dividends, etc., please contact Computershare Investor Services Inc.  
If your shares are held by a broker, please contact your broker.

STOCK EXCHANGES 
(cid:38)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:3)(cid:87)(cid:85)(cid:68)(cid:71)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:55)(cid:82)(cid:85)(cid:82)(cid:81)(cid:87)(cid:82)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)(cid:11)(cid:55)(cid:54)(cid:59)(cid:12)(cid:3) 
(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:49)(cid:72)(cid:90)(cid:3)(cid:60)(cid:82)(cid:85)(cid:78)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)(cid:11)(cid:49)(cid:60)(cid:54)(cid:40)(cid:12)(cid:3)(cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:92)(cid:80)(cid:69)(cid:82)(cid:79)(cid:3)(cid:38)(cid:57)(cid:40)(cid:17)(cid:3)(cid:38)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:3)
warrants trade on the TSX and the NYSE under the symbols TSX: CVE.WT 
(cid:68)(cid:81)(cid:71)(cid:3)(cid:49)(cid:60)(cid:54)(cid:40)(cid:29)(cid:3)(cid:38)(cid:57)(cid:40)(cid:3)(cid:58)(cid:54)(cid:17)(cid:3)(cid:38)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:73)(cid:72)(cid:85)(cid:85)(cid:72)(cid:71)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:3)(cid:54)(cid:72)(cid:85)(cid:76)(cid:72)(cid:86)(cid:3)(cid:20)(cid:15)(cid:3)(cid:54)(cid:72)(cid:85)(cid:76)(cid:72)(cid:86)(cid:3)(cid:21)(cid:15)(cid:3)(cid:54)(cid:72)(cid:85)(cid:76)(cid:72)(cid:86)(cid:3)(cid:22)(cid:15)(cid:3)
Series 5 and Series 7 trade on the TSX under the symbols CVE.PR.A,  
CVE.PR.B, CVE.PR.C, CVE.PR.E and CVE.PR.G.

ANNUAL INFORMATION FORM/FORM 40-F 
(cid:50)(cid:88)(cid:85)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:44)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:41)(cid:82)(cid:85)(cid:80)(cid:3)(cid:76)(cid:86)(cid:3)(cid:238)(cid:79)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:38)(cid:68)(cid:81)(cid:68)(cid:71)(cid:76)(cid:68)(cid:81)(cid:3)(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)
Administrators in Canada on SEDAR at sedar.com and with the 
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Disclosure System as an Annual Report on Form 40-F on EDGAR at sec.gov.

NYSE CORPORATE GOVERNANCE STANDARDS 
As a Canadian company listed on the NYSE, we are not required to 
comply with most of the NYSE corporate governance standards and 
instead may comply with Canadian corporate governance requirements. 
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between our corporate governance practices and those required to 
be followed by U.S. domestic companies under the NYSE corporate 
(cid:74)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:86)(cid:17)(cid:3)(cid:40)(cid:91)(cid:70)(cid:72)(cid:83)(cid:87)(cid:3)(cid:68)(cid:86)(cid:3)(cid:86)(cid:88)(cid:80)(cid:80)(cid:68)(cid:85)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)https://www.cenovus.
com/about/governance/key-governance-documents.html, we are 
in compliance with the NYSE corporate governance standards in all 
(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:238)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:72)(cid:70)(cid:87)(cid:86)(cid:17)

INVESTOR RELATIONS 
Please visit the Investors section at cenovus.com for 
investor information. 

Investor inquiries should be directed to:  
(cid:23)(cid:19)(cid:22)(cid:17)(cid:26)(cid:25)(cid:25)(cid:17)(cid:26)(cid:26)(cid:20)(cid:20)(cid:15)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:17)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:35)(cid:70)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:17)(cid:70)(cid:82)(cid:80)

Media inquiries should be directed to: 
(cid:23)(cid:19)(cid:22)(cid:17)(cid:26)(cid:25)(cid:25)(cid:17)(cid:26)(cid:26)(cid:24)(cid:20)(cid:15)(cid:3)(cid:80)(cid:72)(cid:71)(cid:76)(cid:68)(cid:17)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:35)(cid:70)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:17)(cid:70)(cid:82)(cid:80)

CENOVUS HEAD OFFICE 
Cenovus Energy Inc. 
225 6 Ave SW 
(cid:51)(cid:50)(cid:3)(cid:37)(cid:82)(cid:91)(cid:3)(cid:26)(cid:25)(cid:25) 
Calgary, Alberta  T2P 0M5 Canada 
(cid:51)(cid:75)(cid:82)(cid:81)(cid:72)(cid:29)(cid:3)(cid:23)(cid:19)(cid:22)(cid:17)(cid:26)(cid:25)(cid:25)(cid:17)(cid:21)(cid:19)(cid:19)(cid:19) 
cenovus.com

CENOVUS’S LEADERSHIP TEAM 
(cid:11)(cid:68)(cid:86)(cid:3)(cid:68)(cid:87)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:20)(cid:12)
(cid:36)(cid:79)(cid:72)(cid:91)(cid:3)(cid:51)(cid:82)(cid:88)(cid:85)(cid:69)(cid:68)(cid:76)(cid:91)(cid:15)(cid:3)(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:9)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:73)(cid:238)(cid:70)(cid:72)(cid:85)
Keith Chiasson, EVP, Downstream 
Andrew Dahlin, EVP, Safety & Operations Technical Services
(cid:53)(cid:75)(cid:82)(cid:81)(cid:68)(cid:3)(cid:39)(cid:72)(cid:79)(cid:41)(cid:85)(cid:68)(cid:85)(cid:76)(cid:15)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:54)(cid:88)(cid:86)(cid:87)(cid:68)(cid:76)(cid:81)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:50)(cid:73)(cid:238)(cid:70)(cid:72)(cid:85)(cid:3)(cid:9)(cid:3)(cid:54)(cid:57)(cid:51)(cid:15)(cid:3) 

Stakeholder Engagement

(cid:45)(cid:72)(cid:73)(cid:73)(cid:3)(cid:43)(cid:68)(cid:85)(cid:87)(cid:15)(cid:3)(cid:40)(cid:57)(cid:51)(cid:3)(cid:9)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:50)(cid:73)(cid:238)(cid:70)(cid:72)(cid:85)(cid:3)
(cid:45)(cid:82)(cid:81)(cid:3)(cid:48)(cid:70)(cid:46)(cid:72)(cid:81)(cid:93)(cid:76)(cid:72)(cid:15)(cid:3)(cid:40)(cid:57)(cid:51)(cid:3)(cid:9)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:50)(cid:73)(cid:238)(cid:70)(cid:72)(cid:85)
Gary Molnar, SVP, Legal, General Counsel & Corporate Secretary
Norrie Ramsay, EVP, Upstream – Thermal, Major Projects & Offshore 
Kam Sandhar, EVP, Strategy & Corporate Development 
Sarah Walters, EVP, Corporate Services 
Drew Zieglgansberger, EVP, Upstream – Conventional & Integration

CENOVUS’S BOARD OF DIRECTORS  
(cid:11)(cid:68)(cid:86)(cid:3)(cid:68)(cid:87)(cid:3) January 1, 2021(cid:12)
Keith A. MacPhail, Board Chair, Calgary, Alberta (cid:11)(cid:22)(cid:15)(cid:26)(cid:12)(cid:3)
(cid:46)(cid:72)(cid:76)(cid:87)(cid:75)(cid:3)(cid:48)(cid:17)(cid:3)(cid:38)(cid:68)(cid:86)(cid:72)(cid:92)(cid:15)(cid:3)(cid:54)(cid:68)(cid:81)(cid:3)(cid:36)(cid:81)(cid:87)(cid:82)(cid:81)(cid:76)(cid:82)(cid:15)(cid:3)(cid:55)(cid:72)(cid:91)(cid:68)(cid:86)(cid:3)(cid:11)(cid:21)(cid:15)(cid:23)(cid:12)
Canning K. N. Fok, Hong Kong Special Administrative Region (cid:11)(cid:25)(cid:12)
Jane E. Kinney, Toronto, Ontario (cid:11)(cid:20)(cid:15)(cid:23)(cid:12)
Harold N. Kvisle, Calgary, Alberta(cid:3)(cid:11)(cid:21)(cid:15)(cid:22)(cid:12)(cid:3)
Eva L. Kwok, Vancouver, British Columbia(cid:3)(cid:11)(cid:21)(cid:15)(cid:22)(cid:12)
Richard J. Marcogliese, Alamo, California(cid:3)(cid:11)(cid:20)(cid:15)(cid:23)(cid:12)
(cid:38)(cid:79)(cid:68)(cid:88)(cid:71)(cid:72)(cid:3)(cid:48)(cid:82)(cid:81)(cid:74)(cid:72)(cid:68)(cid:88)(cid:15)(cid:3)(cid:48)(cid:82)(cid:81)(cid:87)(cid:85)(cid:72)(cid:68)(cid:79)(cid:15)(cid:3)(cid:52)(cid:88)(cid:197)(cid:69)(cid:72)(cid:70)(cid:3)(cid:11)(cid:20)(cid:15)(cid:23)(cid:12)(cid:3)
(cid:36)(cid:79)(cid:72)(cid:91)(cid:3)(cid:45)(cid:17)(cid:3)(cid:51)(cid:82)(cid:88)(cid:85)(cid:69)(cid:68)(cid:76)(cid:91)(cid:15)(cid:3)(cid:38)(cid:68)(cid:79)(cid:74)(cid:68)(cid:85)(cid:92)(cid:15)(cid:3)(cid:36)(cid:79)(cid:69)(cid:72)(cid:85)(cid:87)(cid:68)(cid:3)(cid:11)(cid:24)(cid:12)
Wayne E. Shaw, Toronto, Ontario(cid:3)(cid:11)(cid:20)(cid:15)(cid:23)(cid:12)(cid:3)
(cid:41)(cid:85)(cid:68)(cid:81)(cid:78)(cid:3)(cid:45)(cid:17)(cid:3)(cid:54)(cid:76)(cid:91)(cid:87)(cid:15)(cid:3)(cid:43)(cid:82)(cid:81)(cid:74)(cid:3)(cid:46)(cid:82)(cid:81)(cid:74)(cid:3)(cid:54)(cid:83)(cid:72)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:36)(cid:71)(cid:80)(cid:76)(cid:81)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:53)(cid:72)(cid:74)(cid:76)(cid:82)(cid:81)(cid:3)(cid:11)(cid:22)(cid:15)(cid:25)(cid:12)
Rhonda I. Zygocki, Friday Harbor, Washington (cid:11)(cid:21)(cid:15)(cid:22)(cid:12)(cid:3)

(cid:11)(cid:20)(cid:12)(cid:3) (cid:48)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:36)(cid:88)(cid:71)(cid:76)(cid:87)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)
(cid:11)(cid:21)(cid:12)(cid:3) (cid:48)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:43)(cid:88)(cid:80)(cid:68)(cid:81)(cid:3)(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:72)(cid:81)(cid:86)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:11)(cid:113)(cid:43)(cid:53)(cid:38)(cid:114)(cid:12)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)
(cid:11)(cid:22)(cid:12)(cid:3) (cid:48)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:49)(cid:82)(cid:80)(cid:76)(cid:81)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:42)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:11)(cid:113)(cid:49)(cid:38)(cid:42)(cid:114)(cid:12)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)
(cid:11)(cid:23)(cid:12)(cid:3) (cid:48)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:68)(cid:73)(cid:72)(cid:87)(cid:92)(cid:15)(cid:3)(cid:40)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:15)(cid:3)(cid:53)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:76)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:11)(cid:113)(cid:54)(cid:40)(cid:53)(cid:53)(cid:114)(cid:12)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)
(cid:11)(cid:24)(cid:12)(cid:3) (cid:36)(cid:86)(cid:3)(cid:68)(cid:81)(cid:3)(cid:82)(cid:73)(cid:238)(cid:70)(cid:72)(cid:85)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:76)(cid:81)(cid:71)(cid:72)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:71)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:15)(cid:3)(cid:48)(cid:85)(cid:17)(cid:3)(cid:51)(cid:82)(cid:88)(cid:85)(cid:69)(cid:68)(cid:76)(cid:91)(cid:3)(cid:76)(cid:86)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:68)(cid:3)(cid:80)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3) 
  of any of the committees of Cenovus’s Board
(cid:11)(cid:25)(cid:12)(cid:3) (cid:49)(cid:82)(cid:81)(cid:16)(cid:76)(cid:81)(cid:71)(cid:72)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:71)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:3)
(cid:11)(cid:26)(cid:12)(cid:3) (cid:36)(cid:81)(cid:3)(cid:72)(cid:91)(cid:16)(cid:82)(cid:73)(cid:238)(cid:70)(cid:76)(cid:82)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:89)(cid:82)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:80)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:36)(cid:88)(cid:71)(cid:76)(cid:87)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)(cid:15)(cid:3)(cid:43)(cid:53)(cid:38)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)(cid:3) 

and SERR Committee

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2020 ANNUAL REPORT  | 141

 
 
 
CENOVUS ENERGY INC. 

Cenovus  Energy  Inc.  is  an  integrated  energy  company  with  oil  and  natural  gas 
production operations in Canada and the Asia Pacific region, and upgrading, refining 
and marketing operations in Canada and the United States. The company is focused 
on managing its assets in a safe, innovative and cost-efficient manner, integrating 
environmental, social and governance considerations into its business plans. Cenovus 
common shares and warrants are listed on the Toronto and New York stock exchanges, 
and  the  company’s  preferred  shares  are  listed  on  the  Toronto  Stock  Exchange.  
For more information, visit cenovus.com.

c e n o v u s . c o m

225 6 Ave SW, PO Box 766
Calgary, Alberta  T2P 0M5, Canada